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SOUTHERN UNION CO filed this Form 10-Q on 05/09/2013
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Southern Union Q1 2013 10-Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 1-6407
SOUTHERN UNION COMPANY
(Exact name of registrant as specified in its charter)

Delaware
75-0571592
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
3738 Oak Lawn Avenue
75219
Dallas, Texas
(Zip Code)
(Address of principal executive offices)
 

Registrant’s telephone number, including area code:  (214) 981-0700

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x No ¨
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 
Yes x No ¨

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. Large accelerated filer ¨  Accelerated filer ¨  Non-accelerated filer x  Smaller reporting company ¨

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

Southern Union Company meets the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.  Item 2 of Part I has been reduced and Item 3 of Part I and Items 2 and 3 of Part II have been omitted in accordance with Instruction H.




TABLE OF CONTENTS



i


Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by Southern Union Company and its subsidiaries (“Southern Union” or the “Company”) in periodic press releases and some oral statements of the Company’s officials during presentations about the Company, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Company believes such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations, or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Company’s actual results may vary materially from those anticipated, projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I — Item 1A. Risk Factors” in the Company’s Report on Form 10-K for the year ended December 31, 2012 filed with the Securities and Exchange Commission on March 1, 2013.
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
/d
 
per day
 
 
 
APUC
 
Algonquin Power & Utilities Corp
 
 
 
Btu
 
British thermal units
 
 
 
Citrus
 
Citrus Corp.
 
 
 
Citrus Merger
 
ETP’s acquisition of Citrus Corp. on March 26, 2012
 
 
 
EBITDA
 
Earnings before interest, taxes, depreciation and amortization
 
 
 
EPA
 
United States Environmental Protection Agency
 
 
 
ETE
 
Energy Transfer Equity, L.P.
 
 
 
ETE Merger
 
ETE’s acquisition of Southern Union on March 26, 2012
 
 
 
ETP
 
Energy Transfer Partners, L.P., a subsidiary of ETE
 
 
 
ETP GP
 
Energy Transfer Partners GP, L.P., the general partner of ETP
 
 
 
ETP LLC
 
Energy Transfer Partners, L.L.C., the general partner of ETP GP
 
 
 
Exchange Act
 
Securities Exchange Act of 1934
 
 
 
FERC
 
Federal Energy Regulatory Commission
 
 
 
GAAP
 
Accounting principles generally accepted in the United States of America
 
 
 
Holdco
 
ETP Holdco Corporation
 
 
 
KDHE
 
Kansas Department of Health and Environment
 
 
 
LIBOR
 
London Interbank Offer Rate
 
 
 
Laclede Massachusetts
 
Plaza Massachusetts Acquisition, Inc.
 
 
 
Laclede Missouri
 
Plaza Missouri Acquisition, Inc.
 
 
 
LDC Disposal Group
 
Southern Union’s Missouri Gas Energy and New England Gas Company divisions
 
 
 
LNG
 
Liquefied natural gas
 
 
 
LNG Holdings
 
Trunkline LNG Holdings, LLC
 
 
 
MDPU
 
Massachusetts Department of Public Utilities
 
 
 
Merger Sub
 
Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE
 
 
 

ii


MGP
 
Manufactured gas plant
 
 
 
MMBtu
 
Million British thermal units
 
 
 
MMcf
 
Million cubic feet
 
 
 
NGL
 
Natural gas liquids
 
 
 
NMED
 
New Mexico Environment Department
 
 
 
NYMEX
 
New York Mercantile Exchange
 
 
 
OPEB plans
 
Other postretirement employee benefit plans
 
 
 
Panhandle
 
Panhandle Eastern Pipe Line Company, LP and its subsidiaries
 
 
 
PCB
 
Polychlorinated biphenyl
 
 
 
PEPL
 
Panhandle Eastern Pipe Line Company, LP
 
 
 
PEPL Holdings
 
PEPL Holdings, LLC
 
 
 
ppb
 
parts per billion
 
 
 
Regency
 
Regency Energy Partners LP
 
 
 
Sea Robin
 
Sea Robin Pipeline Company, LLC
 
 
 
SEC
 
United States Securities and Exchange Commission
 
 
 
SUGS
 
Southern Union Gas Services
 
 
 
Sunoco
 
Sunoco, Inc.
 
 
 
TBtu
 
Trillion British thermal units
 
 
 
TCEQ
 
Texas Commission on Environmental Quality
 
 
 
Trunkline
 
Trunkline Gas Company, LLC
 
 
 
Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, unrealized gains and losses on commodity risk management activities, non-cash impairment charges and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Company's proportionate ownership.


iii


PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

The Company’s March 26, 2012 merger transaction with ETE (the “ETE Merger”) was accounted for by ETE using business combination accounting.  Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value.  By the application of “push-down” accounting, Southern Union’s assets, liabilities and equity were accordingly adjusted to fair value on March 26, 2012.  Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions.

Due to the application of “push-down” accounting, the Company’s financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting.  Periods prior to March 26, 2012 are identified herein as “Predecessor,” while periods subsequent to the ETE Merger are identified as “Successor.”


iv


SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)




 
 
March 31,
2013
 
December 31, 2012
ASSETS
 
 
 
 
CURRENT ASSETS:
 
 
 
 
Cash and cash equivalents
 
$
165

 
$
49

Accounts receivable, net
 
151

 
155

Accounts receivable from related companies
 
80

 
72

Inventories
 
169

 
163

Exchanges receivable
 
25

 
11

Current assets held for sale
 
136

 
184

Prepayments and other assets
 
149

 
120

Total current assets
 
875

 
754

PROPERTY, PLANT AND EQUIPMENT:
 
 

 
 

Plant in service
 
5,616

 
5,491

Construction work in progress
 
226

 
272

 
 
5,842

 
5,763

Accumulated depreciation and amortization
 
(165
)
 
(105
)
Net property, plant and equipment
 
5,677

 
5,658

NON-CURRENT ASSETS HELD FOR SALE
 
992

 
985

DEFERRED CHARGES
 
69

 
65

UNCONSOLIDATED INVESTMENTS
 
114

 
115

GOODWILL
 
2,364

 
2,364

OTHER NON-CURRENT ASSETS
 
55

 
52

Total assets
 
$
10,146

 
$
9,993



















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

1


SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)



 
 
March 31,
2013
 
December 31, 2012
LIABILITIES AND EQUITY
 
 
 
 
CURRENT LIABILITIES:
 
 

 
 

Current maturities of long–term debt
 
$
256

 
$
259

Accounts payable and accrued liabilities
 
197

 
118

Accounts payable to related companies
 
148

 
110

Federal, state and local taxes payable
 
20

 
16

Accrued interest
 
41

 
32

Exchanges payable
 
146

 
133

Derivative instruments
 
18

 
18

Current liabilities held for sale
 
80

 
85

Other
 
40

 
108

Total current liabilities
 
946

 
879

LONG-TERM DEBT, less current maturities
 
3,048

 
3,024

DEFERRED CREDITS
 
335

 
330

DEFERRED INCOME TAXES
 
1,641

 
1,590

NON-CURRENT LIABILITIES HELD FOR SALE
 
142

 
142

COMMITMENTS AND CONTINGENCIES (Note 11)
 


 


STOCKHOLDER’S EQUITY:
 
 
 
 
Premium on capital stock
 
4,079

 
4,079

Accumulated other comprehensive loss
 
(25
)
 
(25
)
Accumulated deficit
 
(20
)
 
(26
)
Total stockholder’s equity
 
4,034

 
4,028

Total liabilities and stockholder’s equity
 
$
10,146

 
$
9,993




















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

2


SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
(unaudited)

 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition (March 26, 2012) to March 31, 2012
 
 
Period from January 1, 2012 to March 25, 2012
OPERATING REVENUES
 
$
393

 
$
31

 
 
$
443

OPERATING EXPENSES:
 


 
 

 
 
 

Cost of natural gas and other energy
 
159

 
14

 
 
197

Operating, maintenance and general
 
120

 
61

 
 
116

Depreciation and amortization
 
59

 
4

 
 
49

Total operating expenses
 
338

 
79

 
 
362

OPERATING INCOME (LOSS)
 
55

 
(48
)
 
 
81

OTHER INCOME (EXPENSE):
 
 
 
 

 
 
 

Interest expense, net of interest capitalized
 
(33
)
 
(4
)
 
 
(50
)
Earnings from unconsolidated investments
 
1

 

 
 
16

Other, net
 
1

 

 
 
(2
)
Total other expenses, net
 
(31
)
 
(4
)
 
 
(36
)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
 
24

 
(52
)
 
 
45

Income tax expense (benefit) from continuing operations
 
10

 
(12
)
 
 
12

INCOME (LOSS) FROM CONTINUING OPERATIONS
 
14

 
(40
)
 
 
33

Income from discontinued operations
 
22

 
1

 
 
17

NET INCOME (LOSS)
 
$
36

 
$
(39
)
 
 
$
50












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

3


SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
(unaudited)

 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition (March 26, 2012) to March 31, 2012
 
 
Period from January 1, 2012 to March 25, 2012
Net income (loss)
 
$
36

 
$
(39
)
 
 
$
50

Other comprehensive income, net of tax:
 
 
 
 

 
 
 

Change in fair value of interest rate hedges
 

 

 
 
4

Reclassification of unrealized loss on interest rate hedges into earnings
 

 

 
 
5

Change in fair value of commodity hedges
 

 
1

 
 
3

Reclassification of unrealized (gain) loss on commodity hedges into earnings
 

 

 
 
(1
)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings
 

 

 
 
1


 

 
1

 
 
12

Comprehensive income (loss)
 
$
36

 
$
(38
)
 
 
$
62


























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

4


SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(Dollars in millions)
(unaudited)


 
 
Premium on Capital Stock
 
Accumulated Other Comprehensive Loss
 
Accumulated Deficit
 
Total
Stockholder’s
Equity
Balance, December 31, 2012
 
$
4,079

 
$
(25
)
 
$
(26
)
 
$
4,028

Unit-based compensation
 
1

 

 

 
1

Dividends paid on common stock
 

 

 
(30
)
 
(30
)
Net income
 

 

 
36

 
36

Other
 
(1
)
 

 

 
(1
)
Balance, March 31, 2013
 
$
4,079

 
$
(25
)
 
$
(20
)
 
$
4,034







































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

5


SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
(unaudited)

 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition (March 26, 2012) to March 31, 2012
 
 
Period from January 1, 2012 to March 25, 2012
CASH FLOWS FROM OPERATING ACTIVITES:
 
 
 
 
 
 
 

Net income (loss)
 
$
36

 
$
(39
)
 
 
$
50

Reconciliation of net income to net cash provided by (used in) operating activities:
 
 
 
 

 
 
 

Depreciation and amortization (including discontinued operations)
 
59

 
5

 
 
57

Deferred income taxes
 
22

 
(12
)
 
 
23

Provision for bad debts
 
1

 

 
 
1

Amortization of costs charged to interest
 
(8
)
 

 
 
1

Net gain on curtailment of OPEB plans
 

 
(15
)
 
 

Unrealized gain on derivatives
 
(5
)
 

 
 

Non-cash compensation expense
 
2

 

 
 
2

Earnings from unconsolidated investments, net of cash distributions
 

 

 
 
(16
)
Changes in operating assets and liabilities, net of merger impact
 
131

 
(133
)
 
 
79

Net cash flows provided by (used in) operating activities
 
238

 
(194
)
 
 
197

CASH FLOWS FROM INVESTING ACTIVITES:
 
 
 
 

 
 
 

Additions to property, plant and equipment
 
(123
)
 
(2
)
 
 
(60
)
Loan repayment from unconsolidated investments
 

 

 
 
37

Distributions from unconsolidated affiliates in excess of cumulative earnings
 
1

 

 
 

Proceeds from Citrus Merger
 

 

 
 
1,895

Plant retirements and other
 
(1
)
 

 
 
(2
)
Net cash flows provided by (used in) investing activities
 
(123
)
 
(2
)
 
 
1,870

CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 

 
 
 

Issuance of long-term debt
 

 

 
 
455

Dividends paid on common stock
 
(30
)
 

 
 
(19
)
Note payable - related party
 

 
221

 
 

Repayment of long-term debt
 

 

 
 
(1,048
)
Net change in revolving credit facilities
 
30

 
(47
)
 
 
12

Purchase of treasury stock
 

 

 
 
(1,453
)
Other
 
1

 
(2
)
 
 
(1
)
Net cash flows provided by (used in) financing activities
 
1

 
172

 
 
(2,054
)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
 
116

 
(24
)
 
 
13

CASH AND CASH EQUIVALENTS, beginning of period
 
49

 
37

 
 
24

CASH AND CASH EQUIVALENTS, end of period
 
$
165

 
$
13

 
 
$
37


The accompanying notes are an integral part of these consolidated financial statements.
6



SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar amounts are in millions)
(unaudited)

1.
DESCRIPTION OF BUSINESS:
Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, treating, processing, transportation, storage and distribution of natural gas in the United States.  The Company operates in three reportable segments as follows:  
Transportation and Storage — The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas, and also provides LNG terminalling and regasification services.  Its operations expand from the Gulf Coast region throughout the Midwest and Great Lakes region.
Gathering and Processing — The Gathering and Processing segment is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets. Its operations are conducted through SUGS.  As discussed in Note 3, Southern Union completed its contribution of SUGS and its parent company to Regency for approximately $1.50 billion consisting of cash, Regency common units and Regency Class F units on April 30, 2013.
Distribution — The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.  Through Southern Union’s regulated utility operations, Missouri Gas Energy and New England Gas Company, the Company serves natural gas end-user customers in Missouri and Massachusetts, respectively.  As discussed in Note 3, Southern Union and The Laclede Group, Inc. have entered into definitive purchase and sale agreements pursuant to which Laclede Missouri has agreed to acquire the assets of Southern Union’s Missouri Gas Energy division, and Laclede Massachusetts has agreed to acquire the assets of Southern Union’s New England Gas Company division for approximately $1.04 billion, subject to customary closing adjustments.  On February 11, 2013, The Laclede Group, Inc. announced that it had entered into an agreement with APUC that will allow a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of New England Gas Company, subject to certain approvals.  It is expected that the transactions contemplated by the purchase and sale agreements will close in the third quarter of 2013.

See Note 3 for information related to the Company’s disposal and other related transactions.

2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND OTHER MATTERS:

There have been no changes in the Company’s significant accounting policies as disclosed in its Annual Report on Form 10-K for the year ended December 31, 2012.

3.
DISPOSAL AND RELATED TRANSACTIONS:
SUGS Contribution
On April 30, 2013, the Company completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to the Company, (ii) the issuance of approximately 6.3 million Regency Class F units to the Company, (iii) the distribution of $570 million in cash to the Company, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The total cash consideration to the Company was reduced by $107 million in estimated closing adjustments. In addition, PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the Contribution Agreement. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. The Company has not presented SUGS as discontinued operations due to the expected continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency received as consideration.


7


Holdco Transaction
On April 30, 2013, ETP acquired from ETE its interest in Holdco for approximately 49.5 million of newly issued ETP common units and $1.40 billion in cash, less $68 million in estimated closing adjustments. Holdco is the entity formed by ETP and ETE in 2012 to own the equity interests in Southern Union and Sunoco. As a result of this transaction, ETP now owns 100% of Holdco.
Discontinued Operations
In December 2012, the Company entered into a purchase and sale agreement with The Laclede Group, Inc. pursuant to which Laclede Missouri has agreed to acquire the assets of the Missouri Gas Energy division and Laclede Massachusetts has agreed to acquire the assets of the New England Gas Company division (together, the “LDC Disposal Group”) for approximately $1.04 billion, subject to customary closing adjustments.  On February 11, 2013, The Laclede Group, Inc. announced that it had entered into an agreement with APUC that will allow a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of New England Gas Company, subject to certain approvals.  It is expected that the transactions contemplated by the purchase and sale agreements will close in the third quarter of 2013.  All periods reflected herein have been restated to present the LDC Disposal Group’s operations as discontinued operations in the consolidated statements of operations.  The LDC Disposal Group’s assets and liabilities have been reported as assets and liabilities held for sale as of March 31, 2013 and December 31, 2012.
Summarized financial information for Southern Union’s LDC Disposal Group is as follows:
 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition (March 26, 2012) to March 31, 2012
 
 
Period from January 1, 2012 to March 25, 2012
Revenue from discontinued operations
 
$
246

 
$
8

 
 
$
190

Net income of discontinued operations, excluding effect of taxes and overhead allocations
 
56

 
1

 
 
27

The goodwill allocated to the LDC Disposal Group was $133 million at March 31, 2013.

4.
RELATED PARTY TRANSACTIONS:

Accounts receivable from related companies reflected on the condensed consolidated balance sheets primarily related to payroll funding and various administrative and operating costs paid by the Company on behalf of affiliates. Accounts payable from related companies primarily related to various administrative and operating costs paid by affiliates on behalf of the Company.

The following table provides a summary of the related party activity included in our condensed consolidated statements of operations. Prior period amounts were not included as they were immaterial.
 
 
Three Months Ended March 31, 2013
Operating revenues — ETP
 
$
20

Cost of natural gas and other energy
 
13

Operating, maintenance and general
 
25

Earnings from unconsolidated investments
 
1


The Company received $2 million in distributions related to its investment in ETP during the three months ended March 31, 2013.


8


5.
ACCUMULATED OTHER COMPREHENSIVE LOSS:

The table below presents the components in accumulated other comprehensive loss, net of tax, as of the dates indicated:
 
 
March 31,
2013
 
December 31, 2012
Commodity hedges
 
$
(3
)
 
$
(3
)
Benefit plans:
 
 

 
 

Net actuarial loss and prior service costs — pensions
 
(11
)
 
(11
)
Net actuarial gain and prior service credit — OPEB plans
 
(11
)
 
(11
)
Total accumulated other comprehensive loss, net of tax
 
$
(25
)
 
$
(25
)

6.
DEBT OBLIGATIONS:

Based on the estimated borrowing rates currently available to the Company and its subsidiaries for loans with similar terms and average maturities, the aggregate fair value of the Company’s consolidated debt obligations at March 31, 2013 and December 31, 2012 was $3.43 billion and $3.39 billion, respectively.  As of March 31, 2013 and December 31, 2012, the aggregate carrying amount of the Company’s consolidated debt obligations was $3.30 billion and $3.28 billion, respectively.  The fair value of the Company’s consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

Credit Facilities. The Eighth Amended and Restated Revolving Credit Agreement (the “Southern Union Credit Facility”) provides for borrowings of up to $700 million and expires in May 2016.  Borrowings under the Southern Union Credit Facility are available for working capital, other general company purposes and letter of credit requirements.  The interest rate and commitment fee under the Southern Union Credit Facility are calculated using a pricing grid, which is based on the credit ratings for Southern Union's senior unsecured notes.  The annualized interest rate for the Southern Union Credit Facility was 1.83% as of March 31, 2013.

As of March 31, 2013 and December 31, 2012, the Company had $240 million and $210 million, respectively, outstanding under the Southern Union Credit Facility.

In connection with the SUGS Contribution, borrowings under the Southern Union Credit Facility were repaid and the facility terminated. 
Panhandle Term Loans. The effective interest rate for the $455 million LNG Holdings term loan due February 2015 was 1.83% as of March 31, 2013.
Covenants Related to Our Credit Agreements. We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of March 31, 2013.


9


7.
RETIREMENT BENEFITS:
Components of Net Periodic Benefit Cost  
The following tables set forth the components of net periodic benefit cost of the Company’s pension and postretirement benefit plans for the periods presented below:
 
 
Pension Benefits
 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition (March 26, 2012) to March 31, 2012
 
 
Period from January 1, 2012 to March 25, 2012
Net Periodic Benefit Cost:
 
 
 
 
 
 
 
Service cost
 
$
1

 
$

 
 
$
1

Interest cost
 
2

 

 
 
2

Expected return on plan assets
 
(3
)
 

 
 
(2
)
Actuarial loss amortization
 
1

 

 
 
2

 
 
1

 

 
 
3

Regulatory adjustment (2)
 
2

 

 
 

Net periodic benefit cost
 
$
3

 
$

 
 
$
3

 
 
Other Postretirement Benefits
 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition (March 26, 2012) to March 31, 2012
 
 
Period from January 1, 2012 to March 25, 2012
Net Periodic Benefit Cost:
 
 
 
 
 
 
 
Service cost
 
$

 
$

 
 
$
1

Interest cost
 
1

 

 
 
1

Expected return on plan assets
 
(2
)
 

 
 
(1
)
Prior service credit amortization
 

 

 
 
(1
)
Curtailment recognition (1)
 

 
(15
)
 
 

 
 
(1
)
 
(15
)
 
 

Regulatory adjustment (2)
 
3

 

 
 
1

Net periodic benefit cost (credit)
 
$
2

 
$
(15
)
 
 
$
1

(1) 
Subsequent to the ETE Merger, the Company amended certain of its OPEB plans, which prospectively restrict participation in the plans for the impacted active employees.  The plan amendments resulted in the plans becoming currently over-funded and, accordingly, the Company recorded a pre-tax curtailment gain of $75 million.  Such gain was offset by establishment of a non-current refund liability in the amount of $60 million.  As such, the net curtailment gain recognition was $15 million.
(2) 
In the Distribution segment, the Company recovers certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

10


8.
TAXES ON INCOME:

The following tables summarize the Company’s income taxes from continuing operations for the periods presented:

 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition (March 26, 2012) to March 31, 2012
 
 
Period from January 1, 2012 to March 25, 2012
Total income tax expense (benefit) from continuing operations
 
$
10

 
$
(12
)
 
 
$
12

Effective tax rate
 
41
%
 
23
%
 
 
27
%

The Company’s effective income tax rate for the period ended March 31, 2013 was higher than the U.S. federal income tax statutory rate of 35% primarily due to state income taxes.  During the period from March 26, 2012 to March 31, 2012, the Company’s effective income tax rate was lower than the federal statutory rate primarily due to the Company’s pre-tax loss as a result of merger-related expenses coupled with non-deductible executive compensation included in the merger-related expenses. During the period from January 1, 2012 to March 25, 2012, the effective income tax rate was lower than the federal statutory rate primarily as a result of the dividend received deduction for the anticipated receipt of dividends associated with the earnings from the Company’s prior unconsolidated investment in Citrus.

9.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:
The Company is exposed to certain risks in its ongoing business operations.  The primary risks managed by using derivative instruments are interest rate risk and commodity price risk.  Interest rate swaps are the principal derivative instruments used by the Company to manage interest rate risk associated with its long-term borrowings, although other interest rate derivative contracts may also be used from time to time.  Natural gas and NGL price swaps and NGL processing spread swaps are the principal derivative instruments used by the Company to manage commodity price risk associated with purchases and/or sales of natural gas and/or NGL, although other commodity derivative contracts may also be used from time to time.  The Company recognizes all derivative instruments as assets or liabilities at fair value in the consolidated balance sheets.
Interest Rate Contracts
The Company may enter into interest rate swaps to manage its exposure to changes in interest payments on long-term debt attributable to movements in market interest rates, and may enter into treasury rate locks to manage its exposure to changes in future interest payments attributable to changes in treasury rates prior to the issuance of new long-term debt instruments.
Interest Rate Swaps.  In 2011, the Company entered into interest rate swap agreements to hedge the $600 million Junior Subordinated Notes due 2066 with an aggregate notional amount of $525 million, of which $450 million were for ten-year periods and $75 million were for five-year periods.  These interest rate swaps became effective on November 1, 2011.  The Company pays interest on the Junior Subordinated Notes at the floating rate of three-month LIBOR plus a credit spread of 3.0175% beginning November 1, 2011.  The interest rate swaps effectively fix the interest rate applicable to the floating rate on a portion of the Junior Subordinated Notes and are accounted for as cash flow hedges, with the effective portion of their settled value recorded in accumulated other comprehensive income and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.  The floating rate LIBOR-based portion of the interest payments was exchanged for weighted average fixed rate interest payments of 3.63%.  In conjunction with the ETE Merger, the Company discontinued hedge accounting treatment on these interest rate swaps.  Therefore, changes in fair value were recognized in earnings.
The Company also had outstanding pay-fixed interest rate swaps with a total notional amount of $455 million to hedge the LNG Holdings $455 million term loan, which was refinanced in February 2012.  These interest rate swaps were accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impacted earnings.  These swaps terminated in the first quarter of 2012.
For the predecessor period in 2012 during which hedge accounting treatment was applied, there was no swap ineffectiveness.

11


Commodity Contracts – Gathering and Processing Segment
The Company primarily enters into natural gas and NGL price swaps and NGL processing spread swaps to manage its exposure to changes in margin on forecasted sales of natural gas and NGL volumes resulting from movements in market commodity prices.
Natural Gas Price Swaps.  As of March 31, 2013, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 3,437,500 MMBtu for 2013.  These natural gas price swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified into operating revenues in the same periods during which the forecasted natural gas sales impact earnings.  As of March 31, 2013, approximately $3 million of net after-tax losses in accumulated other comprehensive income related to these natural gas price swaps are expected to be recognized in operating revenues during the next 12 months.  Any ineffective portion of the cash flow hedge is reported in current-period earnings.
Commodity Contracts – Distribution Segment
Through the Distribution segment, included in the LDC Disposal Group at March 31, 2013, the Company enters into natural gas commodity financial instruments to manage the exposure to changes in the cost of natural gas passed through to utility customers that result from movements in market commodity prices.  The cost of the derivative instruments and settlement of the respective obligations are recovered from utility customers through the purchased natural gas adjustment clause as authorized by the applicable regulatory authority and therefore do not impact earnings.
Natural Gas Price Swaps.  As of March 31, 2013, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 14,030,000 MMBtu, 8,160,000 MMBtu and 220,000 MMBtu for the remainder of 2013, 2014 and 2015, respectively.  These natural gas price swaps are accounted for as economic hedges, with changes in their fair value recorded to deferred natural gas purchases.
Summary Financial Statement Information
The following table summarizes the fair value amounts of the Company’s asset and liability derivative instruments and their location reported in the consolidated balance sheets at the dates indicated. The asset and liability derivative instruments belonging to the Distribution segment have been included in current asset and liabilities held for sale at March 31, 2013.
 
 
Fair Value
 
 
Asset Derivatives
 
Liability Derivatives
Balance Sheet Location
 
March 31,
2013
 
December 31, 2012
 
March 31,
2013
 
December 31, 2012
Cash Flow Hedges:
 
 
 
 
 
 
 
 
Commodity contracts — Gathering and Processing:
 
 

 
 

 
 

 
 

Natural gas price swaps:
 
 

 
 

 
 

 
 

Accounts payable to related companies
 
$

 
$

 
$
3

 
$
5

 
 

 

 
3

 
5

Economic Hedges:
 
 

 
 

 
 

 
 

Interest rate contracts:
 
 

 
 

 
 

 
 

Derivative instruments — liabilities
 

 

 
18

 
18

Deferred credits
 

 

 
54

 
59

Commodity contracts — Distribution:
 
 

 
 

 
 

 
 

Natural gas price swaps:
 
 

 
 

 
 

 
 

Current assets held for sale
 
8

 
1

 

 

Non-current assets held for sale
 

 
1

 

 

Current liabilities held for sale
 

 

 
2

 
9

 
 
8

 
2

 
74

 
86

Total
 
$
8

 
$
2

 
$
77

 
$
91

The Company has master netting arrangements with certain of its counterparties, which permit applicable obligations of the parties to be settled on a net versus gross basis.  If a right of offset exists, the fair value amounts for the derivative instruments are reported in the consolidated balance sheets on a net basis and disclosed herein on a gross basis.

12


The following tables summarize the location and amount (excluding income tax effects) of derivative instrument gains and losses reported in the Company’s consolidated financial statements for the periods presented:
 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition (March 26, 2012) to March 31, 2012
 
 
Period from January 1, 2012 to March 25, 2012
Cash Flow Hedges:
 
 
 
 
 
 
 
Interest rate contracts:
 
 
 
 
 
 
 
Change in fair value — increase in accumulated other comprehensive income
 
$

 
$

 
 
$
6

Reclassification of unrealized loss from accumulated other comprehensive income — increase of interest expense
 

 

 
 
8

Commodity contracts — Gathering and Processing:
 
 
 
 

 
 
 

Change in fair value — increase in accumulated other comprehensive income
 

 
2

 
 
5

Reclassification of unrealized gain from accumulated other comprehensive income
 

 

 
 
2

Economic Hedges:
 
 
 
 

 
 
 
Interest rate contracts:
 
 
 
 
 
 
 
Change in fair value — increase in interest expense
 
5

 

 
 

Commodity contracts — Distribution:
 
 

 
 

 
 
 
Change in fair value — decrease in deferred natural gas purchases
 
(13
)
 

 
 
(2
)
Derivative Instrument Contingent Features
Certain of the Company’s derivative instruments contain provisions that require the Company’s debt to be maintained at an investment grade credit rating from each of the major credit rating agencies.  If the Company’s debt were to fall below investment grade, the Company would be in violation of these provisions, and the counterparties to the derivative instruments could potentially require the Company to post collateral for certain of the derivative instruments. 


13


10.
FAIR VALUE MEASUREMENT:
 
The following table sets forth the Company’s assets and liabilities that are measured at fair value on a recurring basis at the date indicated:
 
 
Fair Value
as of
 
Fair Value Measurements at
March 31, 2013
Using Fair Value Hierarchy
 
 
March 31, 2013
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 
 
 
 
 
 
 
Commodity derivatives
 
$
6

 
$

 
$
6

 
$

Total
 
$
6

 
$

 
$
6

 
$

Liabilities:
 
 

 
 

 
 

 
 

Commodity derivatives
 
$
3

 
$

 
$
3

 
$

Interest-rate swap derivatives
 
72

 

 
72

 

Total
 
$
75

 
$

 
$
75

 
$


The Company’s Level 2 instruments primarily include natural gas and NGL price swaps and NGL processing spread swap derivatives and interest-rate swap derivatives that are valued using pricing models based on an income approach that discounts future cash flows to a present value amount.  The significant pricing model inputs for natural gas and NGL price swaps and NGL processing spread swap derivatives include published NYMEX forward index prices for delivery of natural gas at Henry Hub, Permian Basin and Waha, and NGL at Mont Belvieu.  The significant pricing model inputs for interest-rate swaps include published rates for U.S. Dollar LIBOR interest rate swaps.  The pricing models also adjust for nonperformance risk associated with the counterparty or Company, as applicable, through the use of credit risk adjusted discount rates based on published default rates.  The Company did not have any Level 3 instruments measured at fair value at March 31, 2013 and there were no transfers between hierarchy levels.

The approximate fair value of the Company’s cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to their short-term nature.

11.
COMMITMENTS AND CONTINGENCIES:
PEPL Holdings Guarantee of Collection
In accordance with the Contribution Agreement pursuant to which the Company contributed SUGS to Regency, Regency issued $600 million of 4.50% Senior Notes due 2023 (the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portion of the consideration, as adjusted, under the Contribution Agreement and pay certain other expenses or disbursements directly related to the closing of the SUGS contribution. In connection with the closing of the SUGS contribution, on April 30, 2013, Regency entered into the guarantee of collection with PEPL Holdings, a subsidiary of the Company, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basis to the Company) to Regency and Regency Energy Finance Corp. with respect to the payment of the principal amount of the Regency Debt.
Environmental Matters
The Company’s operations are subject to federal, state and local laws, rules and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws, rules and regulations require the Company to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals.  Failure to comply with environmental laws, rules and regulations may expose the Company to significant fines, penalties and/or interruptions in operations. The Company’s environmental policies and procedures are designed to achieve compliance with such applicable laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements.

14


Environmental Remediation
Transportation and Storage Segment
Panhandle is responsible for environmental remediation at certain sites on its natural gas transmission systems for contamination resulting from the past use of lubricants containing PCBs in compressed air systems; the past use of paints containing PCBs; and the prior use of wastewater collection facilities and other on-site disposal areas. Panhandle has implemented a program to remediate such contamination.  The primary remaining remediation activity on the Panhandle systems is associated with past use of paints containing PCBs or PCB impacts to equipment surfaces and to a building at one location.  The PCB assessments are ongoing and the related estimated remediation costs are subject to further change. Other remediation typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility.  The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, Panhandle could potentially be held responsible for contamination caused by other parties. In some instances, Panhandle may share liability associated with contamination with other potentially responsible parties.  Panhandle may also benefit from contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations.
The Company’s environmental remediation activities are undertaken in cooperation with and under the oversight of appropriate regulatory agencies, enabling the Company under certain circumstances to take advantage of various voluntary cleanup programs in order to perform the remediation in the most effective and efficient manner.
Distribution Segment
The Company is allowed to recover environmental remediation expenditures through rates in certain jurisdictions within its Distribution segment.  Significant charges to earnings could be required prior to rate recovery for jurisdictions that do not have rate recovery mechanisms.
The Company is responsible for environmental remediation at various contaminated sites that are primarily associated with former MGPs and sites associated with the operation and disposal activities of former MGPs that produced a fuel known as “town gas.” Some byproducts of the historic manufactured gas process may be regulated substances under various federal and state environmental laws. To the extent these byproducts are present in soil or groundwater at concentrations in excess of applicable standards, investigation and remediation may be required.  The sites include properties that are part of the Company’s ongoing operations, sites formerly owned or used by the Company and sites owned by third parties. Remediation typically involves the management of contaminated soils and may involve removal of old MGP structures and remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility; some contamination may be unrelated to former MGPs. The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Company could potentially be held responsible for contamination caused by other parties.  In some instances, the Company may share liability associated with contamination with other potentially responsible parties and may also benefit from insurance policies or contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations.
North Attleboro MGP Site in Massachusetts (“North Attleboro Site”).  In November 2003, the Massachusetts Department of Environment Protection issued a Notice of Responsibility to New England Gas Company, acknowledging receipt of prior notifications and investigative reports submitted by New England Gas Company, following the discovery of suspected coal tar material at the North Attleboro Site.  Subsequent sampling in the adjacent river channel revealed sediment impacts necessitating the investigation of off-site properties.  Assessment activities have recently been completed and it is estimated that the Company will spend approximately $11 million over the next several years to complete remediation activities at the North Attleboro Site, as well as maintain the engineered barrier constructed in 2008 at the upland portion of the site.  As New England Gas Company is allowed to recover environmental remediation expenditures through rates associated with its Massachusetts operations, the estimated costs associated with the North Attleboro Site have been included in regulatory assets in the consolidated balance sheets.

15


Environmental Remediation Liabilities
The table below reflects the amount of accrued liabilities recorded in the consolidated balance sheets at the dates indicated to cover environmental remediation actions where management believes a loss is probable and reasonably estimable.  Except for matters discussed above, the Company does not have any material environmental remediation matters assessed as reasonably possible that would require disclosure in the financial statements.
 
 
March 31,
2013
 
December 31,
2012
Current
 
$
7

 
$
7

Noncurrent
 
26

 
26

Total environmental liabilities
 
$
33

 
$
33

Litigation and Other Claims
Will Price.  Will Price, an individual, filed actions in the U.S. District Court for the District of Kansas for damages against a number of companies, including Panhandle, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners.  On September 19, 2009, the Court denied plaintiffs’ request for class certification.  Plaintiffs have filed a motion for reconsideration, which the Court denied on March 31, 2010.  Panhandle believes that its measurement practices conformed to the terms of its FERC natural gas tariffs, which were filed with and approved by the FERC.  As a result, the Company believes that it has meritorious defenses to the Will Price lawsuit (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of the FERC, and the defense that Panhandle complied with the terms of its tariffs).  In the event that Plaintiffs refuse Panhandle’s pending request for voluntary dismissal, Panhandle will continue to vigorously defend the case.  The Company believes it has no liability associated with this proceeding.
Attorney General of the Commonwealth of Massachusetts v New England Gas Company.  On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the MDPU against New England Gas Company with respect to certain environmental cost recoveries.  The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with the Company’s environmental response activities.  In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including:  (i) the prudence of any and all legal fees, totaling $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Company’s former Vice Chairman, President and Chief Operating Officer, joined the Company’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as the Company’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery.  The Company has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel.  The hearing officer has deferred consideration of the Company’s motion to dismiss.  The AG’s motion to be reimbursed expert and consultant costs by the Company of up to $150,000 was granted.  The hearing officer has stayed discovery until resolution of a separate matter concerning the applicability of attorney-client privilege to legal billing invoices.  The Company believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, the Company will continue to assess its potential exposure for such cost recoveries as the matter progresses.
Litigation Relating to the ETE Merger
In June 2011, several putative class action lawsuits were filed in the Judicial District Court of Harris County, Texas naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. The lawsuits were styled Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas and Magda v. Southern Union Company, et al., Cause No. 2011-37134, in the 11th Judicial District Court of Harris County, Texas. The lawsuits were consolidated into an action styled In re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas. Plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union's stockholders in connection with the ETE Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty. The amended petitions allege that the ETE Merger involves an unfair price and an inadequate sales process, that Southern Union's directors entered into the ETE Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the ETE Merger to Southern Union stockholders. The amended petitions seek injunctive relief, including an injunction of the ETE Merger, and an award of attorneys’ and other fees and costs, in addition to other relief. On October 21,

16


2011, the court denied ETE's October 13, 2011, motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery.
Also in June 2011, several putative class action lawsuits were filed in the Delaware Court of Chancery naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. Three of the lawsuits also named Merger Sub as a defendant. These lawsuits are styled: Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS; KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS; LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS; and Memo v. Southern Union Company, et al., C.A. No. 6639-CS. These cases were consolidated with the following style: In re Southern Union Co. Shareholder Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery. The consolidated complaint asserts similar claims and allegations as the Texas state-court consolidated action. On July 25, 2012, the Delaware plaintiffs filed a notice of voluntary dismissal of all claims without prejudice. In the notice, plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case.
The Texas case remains pending, and discovery is ongoing.
In November 2011, a derivative lawsuit was filed in the Judicial District Court of Harris County, Texas naming as defendants ETP, ETP GP, ETP LLC, the boards of directors of ETP LLC (collectively with ETP GP and ETP LLC, the “ETP Defendants”), certain members of management for ETP and ETE, ETE, and Southern Union.  The lawsuit is styled W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, in the 157th Judicial District Court of Harris County, Texas.  Plaintiffs assert claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the ETP Defendants and the individual defendants.  Plaintiffs also assert claims for aiding and abetting and tortious interference with contract against Southern Union.  On October 5, 2012, certain defendants filed a motion for summary judgment with respect to the primary allegations in this action.  On December 13, 2012, Plaintiffs filed their opposition to the motion for summary judgment. Defendants filed a reply on December 19, 2012.  On December 20, 2012, the court conducted an oral hearing on the motion. Plaintiffs filed a post-hearing sur-reply on January 7, 2013.  On January 16, 2013, the Court granted defendants' motion for summary judgment.  The deadline for the remaining defendants to file an answer or otherwise respond is late April, 2013.  Trial in this action is not currently set.
Mercury Release
In October 2004, New England Gas Company discovered that one of its facilities, formerly associated with discontinued operations which were sold in 2006, had been broken into and that mercury had been released both inside a building and in the immediate vicinity, including a parking lot in a neighborhood several blocks away.  Mercury from the parking lot was apparently tracked into nearby apartment units, as well as other buildings.  Cleanup was completed at the property and nearby apartment units.  The vandals who broke into the facility were arrested and convicted. In October 2007, the U.S. Attorney in Rhode Island filed a three-count indictment against the Company in the U.S. District Court for the District of Rhode Island (“District Court”) alleging violation of permitting requirements under the Federal Resource Conservation and Recovery Act (“RCRA”) and notification requirements under the Emergency Planning and Community Right to Know Act (“EPCRA”) relating to the 2004 incident.  Trial commenced on September 22, 2008, and on October 15, 2008, the jury acquitted Southern Union on the EPCRA count and one of the two RCRA counts and found the Company guilty on the other RCRA count.  On October 2, 2009, the District Court imposed a fine of $6 million and a payment of $12 million in community service.
On December 22, 2010, the United States Court of Appeals for the First Circuit (“First Circuit”) affirmed the conviction and the sentence.  On February 17, 2011, the First Circuit denied the Company’s petition for en banc rehearing.  The Company, on October 31, 2011, filed a petition for a writ of certiorari review by the United States Supreme Court (“Supreme Court”), which review was granted and the case was heard by the Supreme Court on March 19, 2012.
On June 21, 2012, the United States Supreme Court reversed the First Circuit, holding that the sentence imposed on the Company was unconstitutional, and remanded the case back to the District Court for further proceeding consistent with that holding.
On July 17, 2012, the Government moved for “clarification” of the First Circuit’s December 22, 2010 decision urging the First Circuit to find that, in addition to resolving whether (i) the alternative fine statute increases the maximum fine that may be imposed on the Company from $50,000 to $500,000; (ii) the $12 million community service obligation is a fine or restitution; and (iii) a new jury should be empanelled to hear evidence regarding the number of days RCRA was violated.
On July 26, 2012, the First Circuit vacated the fine imposed by the District Court and remanded the matter to the District Court for resentencing consistent with the Supreme Court’s opinion.  In the same order, the First Circuit denied without prejudice the Government’s motion for clarification, holding that the issues raised by the Government in its July 17, 2012 motion could be addressed by the parties on remand.  Accordingly, the Government petitioned the District Court for

17


consideration of the same issues and the hearing took place on December 3, 2012.  The District Court has ruled in favor of the Company and limited the penalty to “community service” of up to $500,000.
Simmons v. Southern Union Company. Cause No. 1316-CV-07265, in the Circuit Court of Jackson County, Missouri, Kansas City: On March 22, 2013, the first lawsuit related to the February 19, 2013 natural gas incident at JJ's Restaurant was filed in Missouri state court on behalf of six injured restaurant employees.  The defendants include Southern Union Company d/b/a MGE, USIC Locating Services, Inc. (the utility marking service), Heartland Midwest, LLC (the directional boring company and contractor of Time Warner Cable Media, Inc.), Time Warner Cable Media, Inc., Missouri One Call System, Inc., (Missouri's notification center for utility locates), and Mike Palier (MGE's first responder).  Plaintiffs' claims include negligence and strict liability for inherently dangerous activities.  Plaintiffs have not specified an amount of damages, but seek punitive damages against MGE and certain other defendants in a jury trial.  No trial date has been set.
Liabilities for Litigation and Other Claims
In addition to the matters discussed above, the Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business.
The Company records accrued liabilities for litigation and other claim costs when management believes a loss is probable and reasonably estimable.  When management believes there is at least a reasonable possibility that a material loss or an additional material loss may have been incurred, the Company discloses (i) an estimate of the possible loss or range of loss in excess of the amount accrued; or (ii) a statement that such an estimate cannot be made.  As of March 31, 2013 and December 31, 2012, the Company recorded litigation and other claim-related accrued liabilities of $27 million and $27 million, respectively.  Except for the matters discussed above, the Company does not have any material litigation or other claim contingency matters assessed as probable or reasonably possible that would require disclosure in the financial statements.
Other Commitments and Contingencies
Regulation and Rates.  See Note 13 for potential contingent matters associated with the Company’s regulated operations.
Unclaimed Property Audits.  The Company is subject to the laws and regulations of states and other jurisdictions concerning the identification, reporting and escheatment (the transfer of property to the state) of unclaimed or abandoned funds, and is subject to audit and examination for compliance with these requirements.  The Company is currently being examined by a third party auditor on behalf of nine states for compliance with unclaimed property laws.
Air Quality Control
Oil and Natural Gas Sector New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants.  On April 17, 2012 the EPA issued the Oil and Natural Gas Sector New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants.  The standards revise the new source performance standards for volatile organic compounds from leaking components at onshore natural gas processing plants and new source performance standards for sulfur dioxide emissions from natural gas processing plants.  The EPA also established standards for certain oil and gas operations not covered by the existing standards.  In addition to the operations covered by the existing standards, the newly established standards regulate volatile organic compound emissions from gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers and storage vessels.  The Company is reviewing the new standards to determine the impact on its operations.
Transportation and Storage Segment.  In August 2010, the EPA finalized a rule that requires reductions in a number of pollutants, including formaldehyde and carbon monoxide, for certain engines regardless of size at Area Sources (sources that emit less than 10 tons per year of any one Hazardous Air Pollutant (“HAP”) or 25 tons per year of all HAPs) and engines less than 500 horsepower at Major Sources (sources that emit 10 tons per year or more of any one HAP or 25 tons per year of all HAPs).  Compliance is required by October 2013.  It is anticipated that the limits adopted in this rule will be used in a future EPA rule that is scheduled to be finalized in 2013, with compliance required in 2016.  This future rule is expected to require reductions in formaldehyde and carbon monoxide emissions from engines greater than 500 horsepower at Major Sources.
Nitrogen oxides are the primary air pollutant from natural gas-fired engines.  Nitrogen oxide emissions may form ozone in the atmosphere.  In 2008, the EPA lowered the ozone standard to 75 ppb with compliance anticipated in 2013 to 2015.  In January 2010, the EPA proposed lowering the standard to 60 to 70 ppb in lieu of the 75 ppb standard, with compliance required in 2014 or later.  In September 2011, the EPA decided to rescind the proposed lower ozone standard and begin the process to implement the 75 ppb ozone standard established in 2008.
In January 2010, the EPA finalized a 100 ppb one-hour nitrogen dioxide standard.  The rule requires the installation of new nitrogen dioxide monitors in urban communities and roadways by 2013.  This new monitoring may result in additional nitrogen

18


dioxide non-attainment areas.  In addition, ambient air quality modeling may be required to demonstrate compliance with the new standard.
The Company is currently reviewing the potential impacts of the August 2010 Area Source National Emissions Standards for Hazardous Air Pollutants rule, implementation of the 2008 ozone standard and the new nitrogen dioxide standard on operations in its Transportation and Storage and Gathering and Processing segments and the potential costs associated with the installation of emission control systems on its existing engines.  The ultimate costs associated with these activities cannot be estimated with any certainty at this time, but the Company believes, based on the current understanding of the current and proposed rules, such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
12.
REPORTABLE SEGMENTS:

The Company’s primary operating segments, which are individually disclosed as its reportable business segments, are:  Transportation and Storage, Gathering and Processing, and Distribution.  These operating segments are organized for segment reporting purposes based on the way internal managerial reporting presents the results of the Company’s various businesses to its chief operating decision maker for use in determining the performance of the businesses.

The Transportation and Storage segment operations are conducted through Panhandle and the Company’s investment in Citrus (through March 26, 2012, the date of the Citrus Merger).  The Gathering and Processing segment operations are conducted through SUGS.  The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts, through its Missouri Gas Energy and New England Gas Company operating divisions, respectively. See Note 1 for additional information associated with the Company’s reportable segments.

Sales of products or services between segments are billed at regulated rates or at market rates, as applicable.  There were no material intersegment revenues during the three months ended March 31, 2013, the period from Acquisition (March 26, 2012) to March 31, 2012 and the period from January 1, 2012 to March 25, 2012.

The remainder of the Company’s business operations, which do not meet the quantitative threshold for segment reporting, are presented as Corporate and other activities.  Corporate and other activities consist of unallocated corporate costs, a wholly-owned subsidiary with ownership interests in electric power plants, and other miscellaneous activities.

The Company reports Segment Adjusted EBITDA as a measure of segment performance.  The Company defines Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, unrealized gains and losses on unhedged derivative activities, accretion expense and amortization of regulatory assets and other non-operating income or expense items.  Segment Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries and unconsolidated affiliates based on the Company’s proportionate ownership.

Segment Adjusted EBITDA may not be comparable to measures used by other companies and should be considered in conjunction with net earnings and other performance measures such as operating income or net cash flows provided by operating activities.


19


The following tables set forth certain selected financial information for the Company’s segments for the periods presented or at the dates indicated:
 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition (March 26, 2012) to March 31, 2012
 
 
Period from January 1, 2012 to March 25, 2012
Operating revenues from external customers:
 
 
 
 
 
 
 
Transportation and Storage
 
$
199

 
$
13

 
 
$
194

Gathering and Processing
 
190

 
20

 
 
246

Total segment operating revenues
 
389

 
33

 
 
440

Corporate and other activities
 
4

 
(2
)
 
 
3

 
 
$
393

 
$
31

 
 
$
443

Depreciation and amortization:
 
 
 
 

 
 
 

Transportation and Storage
 
$
42

 
$
3

 
 
$
30

Gathering and Processing
 
17

 
1

 
 
18

Total segment depreciation and amortization
 
59

 
4

 
 
48

Corporate and other activities
 

 

 
 
1

 
 
$
59

 
$
4

 
 
$
49

Earnings from unconsolidated investments:
 
 
 
 

 
 
 

Transportation and Storage
 
$

 
$

 
 
$
16

Gathering and Processing
 

 

 
 

Corporate and other activities
 
1

 

 
 

 
 
$
1

 
$

 
 
$
16


Results from the Distribution segment were included in discontinued operations and therefore were not reflected in the table above.


20


 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition (March 26, 2012) to March 31, 2012
 
 
Period from January 1, 2012 to March 25, 2012
Segment Adjusted EBITDA:
 
 
 
 

 
 
 

Transportation and Storage
 
$
124

 
$
(33
)
 
 
$
186

Gathering and Processing
 
(6
)
 
(11
)
 
 
25

Distribution
 
39

 
(10
)
 
 
34

Corporate and other activities
 
4

 
(2
)
 
 
(19
)
Total Segment Adjusted EBITDA
 
161

 
(56
)
 
 
226

Depreciation and amortization
 
(59
)
 
(4
)
 
 
(49
)
Net gain on curtailment of OPEB plans
 

 
15

 
 

Non-cash equity-based compensation, accretion expense and amortization of regulatory assets
 
(2
)
 

 
 
(1
)
Other, net
 
1

 

 
 
(2
)
Earnings from unconsolidated investments
 
1

 

 
 
16

Adjusted EBITDA attributable to unconsolidated investments
 
(5
)
 

 
 
(61
)
Adjusted EBITDA attributable to discontinued operations
 
(40
)
 
(3
)
 
 
(34
)
Interest expense
 
(33
)
 
(4
)
 
 
(50
)
Income (loss) from continuing operations before income tax expense
 
$
24

 
$
(52
)
 
 
$
45


 
 
March 31, 2013
 
December 31, 2012
Total assets:
 
 

 
 

Transportation and Storage
 
$
6,198

 
$
6,219

Gathering and Processing
 
2,038

 
1,965

Distribution (1)
 
1,224

 
1,190

Total segment assets
 
9,460

 
9,374

Corporate and other activities
 
686

 
619

Total assets
 
$
10,146

 
$
9,993


(1)Distribution segment assets have been reported as assets held for sale in the consolidated balance sheets at March 31, 2013 and December 31, 2012.

13.
REGULATION AND RATES:

Panhandle.  On July 26, 2012, Trunkline filed an application with the FERC for approval to transfer approximately 770 miles of underutilized loop piping facilities by sale to an affiliate; such facilities are contemplated to be converted to crude oil transportation service.  This sale is subject to FERC approval.  Several parties have intervened, commented, or protested this filing and the Company is currently responding to the Commission’s requests for additional information on this application.
In November 2011, the FERC commenced an audit of PEPL to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial reporting to the FERC, reservation charge crediting policy and record retention.  The audit is related to the period from January 1, 2010 through December 31, 2011 and is pending the issuance of a draft audit report.
New England Gas Company.  On September 15, 2008, New England Gas Company made a filing with the MDPU seeking recovery of approximately $4 million, or 50% of the amount by which its 2007 earnings fell below a return on equity of 7%.  This filing was made pursuant to New England Gas Company’s rate settlement approved by the MDPU in 2007.  On February 2, 2009, the MDPU issued its order denying the Company’s requested earnings sharing adjustments (“ESA”) in its entirety.  The Company appealed that decision to the Massachusetts Supreme Judicial Court (“MSJC”).  On November 13,

21


2009, New England Gas Company made a similar filing with the MDPU, also pursuant to the above-referenced settlement, to recover approximately $2 million, representing 50% of the amount by which its 2008 earnings deficiency fell below a return on equity of 7%.  The MDPU held the 2008 ESA matter in abeyance pending judicial resolution of the issues pertaining to the 2007 ESA.  On February 11, 2011, the MSJC issued an opinion reversing the MDPU’s rejection of New England Gas Company’s 2007 ESA and remanded the matter back to the MDPU to determine the appropriate amount of the 2007 ESA and the method for recovery.  On July 13, 2011, New England Gas Company filed its motion for proceeding on remand requesting that the MDPU (i) find that $4 million is the appropriate ESA amount for recovery related to calendar year 2007 and that such amount should be recovered over a twelve month period beginning November 1, 2011; and (ii) investigate New England Gas Company’s request for recovery of an ESA amount of $2 million over a twelve-month period beginning November 1, 2012.  On January 27, 2012, the MDPU issued its order approving the 2007 ESA in its entirety and authorizing recovery of approximately $4 million over a twelve-month period beginning February 1, 2012.  On January 25, 2013, the MDPU issued its order approving the 2008 ESA for $2 million to be recovered over a twelve-month period beginning February 1, 2013, which reflected a reduction of approximately $10,000 from the initial request.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Tabular dollar amounts are in millions, except per gallon and per MMBtu amounts)

The information in Item 2 has been prepared pursuant to the reduced disclosure format permitted by General Instruction H to Form 10-Q. Accordingly, this Item 2 includes only management’s narrative analysis of the results of operations and certain supplemental information.
References to “we,” “us,” “our”, the “Company” and “Southern Union” shall mean Southern Union Company and its subsidiaries.

OVERVIEW

The Company evaluates operational and financial segment performance using several factors, of which the primary financial measure is Segment Adjusted EBITDA.  For additional information related to the Company’s use of Segment Adjusted EBITDA as its primary financial measure for its reportable segments, see Note 12 to our consolidated financial statements.

The ETE Merger, which was completed on March 26, 2012, was accounted for by ETE using business combination accounting.  By the application of “push-down” accounting, the Company allocated the purchase price paid by ETE to its assets, liabilities and equity as of the acquisition date based on preliminary estimates.  Accordingly, the successor financial statements reflect a new basis of accounting and predecessor and successor period financial results (separated by a heavy black line) are presented, but are not comparable.

The most significant impacts of the new basis of accounting going forward are expected to be (i) higher depreciation expense due to the step-up of depreciable assets and assignment of purchase price to certain amortizable intangible assets and (ii) lower interest expense (though not cash payments) for the remaining life of the related long-term debt due to its revaluation and related debt premium amortization. 

The results of operations for the successor and predecessor periods reflect certain merger-related expenses, which are not expected to have a continuing impact on the results going forward, and those amounts are discussed in the segments’ results below.

The Company reports Segment Adjusted EBITDA as a measure of segment performance.  The Company defines Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, unrealized gains and losses on unhedged derivative activities, accretion expense and amortization of regulatory assets and other non-operating income or expense items.  Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Company's proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries' results of operations.

Segment Adjusted EBITDA may not be comparable to measures used by other companies and should be considered in conjunction with net earnings and other performance measures such as operating income or net cash flows provided by operating activities.
RECENT DEVELOPMENTS
SUGS Contribution
On April 30, 2013, the Company completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. The consideration paid by Regency in

22


connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to the Company, (ii) the issuance of approximately 6.3 million Regency Class F units to the Company, (iii) the distribution of $570 million in cash to the Company, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The total cash consideration to the Company was reduced by $107 million in estimated closing adjustments. In addition, PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the Contribution Agreement. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. The Company has not presented SUGS as discontinued operations due to the expected continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency received as consideration.

Holdco Transaction
On April 30, 2013, ETP acquired from ETE its interest in Holdco for approximately 49.5 million of newly issued ETP common units and $1.40 billion in cash, less $68 million in estimated closing adjustments. Holdco is the entity formed by ETP and ETE in 2012 to own the equity interests in Southern Union and Sunoco. As a result of this transaction, ETP now owns 100% of Holdco.

RESULTS OF OPERATIONS

The following table provides a reconciliation of Segment Adjusted EBITDA (by segment) to net income for the periods presented.
 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition (March 26, 2012) to March 31, 2012
 
 
Period from January 1, 2012 to March 25, 2012
Segment Adjusted EBITDA:
 
 
 
 
 
 
 
Transportation and storage segment
 
$
124

 
$
(33
)
 
 
$
186

Gathering and processing segment
 
(6
)
 
(11
)
 
 
25

Distribution segment
 
39

 
(10
)
 
 
34

Corporate and other activities
 
4

 
(2
)
 
 
(19
)
Total Segment Adjusted EBITDA
 
161

 
(56
)
 
 
226

Depreciation and amortization
 
(59
)
 
(4
)
 
 
(49
)
Interest expense
 
(33
)
 
(4
)
 
 
(50
)
Non-cash compensation expense, accretion expense and amortization of regulatory assets
 
(2
)
 

 
 
(1
)
Net gain on curtailment of OPEB plans
 

 
15

 
 

Other, net
 
1

 

 
 
(2
)
Earnings from unconsolidated investments
 
1

 

 
 
16

Adjusted EBITDA attributable to unconsolidated investments
 
(5
)
 

 
 
(61
)
Adjusted EBITDA attributable to discontinued operations
 
(40
)
 
(3
)
 
 
(34
)
Income (loss) from continuing operations before income tax expense
 
24

 
(52
)
 
 
45

Income tax expense (benefit)
 
10

 
(12
)
 
 
12

Income (loss) from continuing operations
 
14

 
(40
)

 
33

Income from discontinued operations
 
22

 
1

 
 
17

Net income (loss)
 
$
36

 
$
(39
)
 
 
$
50



23


The segment analysis in the following section describes the significant items impacting the Segment Adjusted EBITDA amounts reflected above. In addition, as discussed in the “Overview” section above, the comparability of net income between predecessor and successor periods was impacted by the application of “push-down” accounting. The most significant impacts of this new basis of accounting were:

Incremental depreciation and amortization expense has been recognized in the successor periods subsequent to March 25, 2012 as a result of the application of the new basis of accounting.
The application of “push-down” accounting also resulted in the Company’s long-term debt being recorded at fair value, which impacted the amount of amortization recorded in interest expense. This change in the amount of amortization resulted in a net reduction within interest expense of approximately $10 million per quarter subsequent to March 25, 2012.
In addition to the impact of the amortization of the debt fair value adjustments, interest expense was also lower during the three months ended March 31, 2013 due to repayments of long-term debt in 2012.

The Company’s consolidated net income was also impacted by changes in income taxes that were driven by the ETE Merger; those impacts were described in the “Federal and State Income Taxes” section below.

The “Supplemental Pro Forma Information” section, which follows the “Business Segment Results” section, provides additional analysis of the Company’s consolidated net income on a year-to-date basis, assuming the ETE Merger had been completed on January 1, 2012.
Federal and State Income Taxes

The following table sets forth the Company’s income taxes from continuing operations for the periods presented.
 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition (March 26, 2012) to March 31, 2012
 
 
Period from January 1, 2012 to March 25, 2012
Income tax expense (benefit)
 
$
10

 
$
(12
)
 
 
$
12

Effective tax rate
 
41
%
 
23
%
 
 
27
%

The Company’s effective income tax rate for the period ended March 31, 2013 was higher than the federal statutory rate of 35% primarily due to state income taxes. The effective income tax rate for the period from March 26, 2012 to March 31, 2012 was lower than the federal statutory rate primarily due to the Company’s pre-tax loss as a result of merger-related expenses coupled with non-deductible executive compensation included in the merger-related expenses. The effective income tax rate for the period from January 1, 2012 to March 25, 2012 was lower than the federal statutory rate primarily due to the dividend received reduction for the anticipated receipt of dividends associated with the earnings from the Company’s prior unconsolidated investment in Citrus.
Business Segment Results

Transportation and Storage Segment

The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest, Gulf Coast and Midcontinent United States, and LNG terminalling and regasification services.  The Transportation and Storage segment’s operations are regulated as to rates and other matters by the FERC. Demand for natural gas transmission services on Panhandle’s pipeline system is seasonal, with the highest throughput and a higher portion of annual total operating revenues and Segment Adjusted EBITDA occurring in the traditional winter heating season, which occurs during the first and fourth calendar quarters.
  
The Company’s business within the Transportation and Storage segment is conducted through both short- and long-term contracts with customers.  Short-term and long-term contracts are affected by changes in market conditions and competition with other pipelines, changing supply sources and volatility in natural gas prices and basis differentials.  Since the majority of the revenues within the Transportation and Storage segment are related to firm capacity reservation charges, which customers pay whether they utilize their contracted capacity or not, volumes transported do not have as significant an impact on revenues over the short-term.  However, longer-term demand for capacity may be affected by changes in the customers’ actual and anticipated utilization of their contracted capacity and other factors.

24



The Company’s regulated transportation and storage businesses can file (or be required to file) for changes in their rates, which are subject to approval by the FERC.  Although a significant portion of the Company’s contracts are discounted or negotiated rate contracts, changes in rates and other tariff provisions resulting from regulatory proceedings have the potential to impact negatively the Company’s results of operations and financial condition.

The following table illustrates the results of operations applicable to the Company’s Transportation and Storage segment for the periods presented.
 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition
(March 26, 2012) to March 31,
2012
 
 
Period from
January 1, 2012 to
March 25,
2012
Operating revenues (1)
 
$
199

 
$
13

 
 
$
194

Operating, maintenance and general, net of non-cash compensation expense, accretion and gain on curtailment
 
(67
)
 
(46
)
 
 
(60
)
Taxes other than on income and revenues
 
(8
)
 

 
 
(9
)
Adjusted EBITDA related to unconsolidated investments
 

 

 
 
61

Segment Adjusted EBITDA
 
$
124

 
$
(33
)
 
 
$
186

 
 
 
 
 
 
 
 
Panhandle natural gas volumes transported (TBtu): (2)
 
 
 
 
 
 
 
PEPL
 
177

 
9

 
 
152

Trunkline
 
180

 
12

 
 
177

Sea Robin
 
40

 
2

 
 
20


(1) 
Reservation revenues comprised 89% of total operating revenues for the three months ended March 31, 2013. Reservation revenues comprised 88% of total operating revenues in both the successor and predecessor periods in 2012.
(2) 
Includes transportation deliveries made throughout the Company’s pipeline network.

Following is a discussion of the significant items and variance impacting Segment Adjusted EBITDA for the Company’s Transportation and Storage segment.

Operating Revenues. Operating revenues for the three months ended March 31, 2013 decreased slightly compared to the predecessor and successor periods in 2012 primarily due to lower capacity sold at lower rates and lower parking revenues, the impacts of which were partially offset by higher usage revenues as a result of higher volumes.
Operating, Maintenance and General Expenses. The period from March 26, 2012 to March 31, 2012 included $41 million of merger-related employee severance expenses.
Unconsolidated Investments. The primary driver for the reduction in Segment Adjusted EBITDA for the Company’s Transportation and Storage segment was the contribution of Citrus to ETP on March 26, 2012. Citrus was reflected in Adjusted EBITDA attributable to unconsolidated investments for the predecessor period shown above but was not reflected in the successor periods. The period from January 1, 2012 to March 25, 2012 reflected Adjusted EBITDA attributable to Citrus of $61 million.

Gathering and Processing Segment
The Gathering and Processing segment is primarily engaged in connecting producing wells of exploration and production companies to its gathering system, providing compression and gathering services, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets.  Its operations are conducted through SUGS, which was contributed to Regency on April 30, 2013.  SUGS’ natural gas supply contracts primarily include fee-based, percent-of-proceeds and margin sharing (conditioning fee and wellhead) purchase contracts.  These natural gas supply contracts vary in length from month-to-month to a number of years, with many of the contracts having a term of three to five years.  SUGS’ primary sales customers include exploration and production companies, power generating companies, electric and gas utilities, energy marketers, industrial end-users located primarily in the Gulf Coast and southwestern United States, and petrochemical companies.  With respect to customer demand for the products and services it

25


provides, SUGS’ business is not generally seasonal in nature; however, SUGS’ operations and the operations of its natural gas producers can be adversely impacted by severe weather.

The majority of SUGS’ gross margin is derived from the sale of NGL and natural gas equity volumes and fee-based services.  The prices of NGL and natural gas are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of factors beyond the Company’s control.  The Company monitors these risks and manages the associated commodity price risk using both economic and accounting hedge derivative instruments.  For additional information related to the Company’s commodity price risk management, see Note 9 to our consolidated financial statements.

The following table presents the results of operations applicable to the Company’s Gathering and Processing segment for the periods presented.
 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition
(March 26, 2012) to March 31,
2012
 
 
Period from
January 1, 2012 to
March 25,
2012
Operating revenues
 
$
190

 
$
20

 
 
$
246

Cost of natural gas and other energy (1)
 
(157
)
 
(14
)
 
 
(196
)
Gross margin (2)
 
33

 
6

 
 
50

Operating, maintenance and general, excluding non-cash compensation expense and accretion
 
(37
)
 
(17
)
 
 
(23
)
Taxes other than on income and revenues
 
(2
)
 

 
 
(2
)
Segment Adjusted EBITDA
 
$
(6
)
 
$
(11
)
 
 
$
25

 
 
 
 
 
 
 
 
Operating Information:
 
 
 
 
 
 
 
Volumes:
 
 
 
 
 
 
 
Avg natural gas processed (MMBtu/d)
 
461,847

 
453,614

 
 
451,893

Avg NGL produced (gallons/d)
 
1,666,592

 
1,650,345

 
 
1,624,666

Avg natural gas wellhead volumes (MMBtu/d)
 
480,549

 
481,881

 
 
504,822

Natural gas sales (MMBtu)  
 
19,148,879

 
1,324,080

 
 
18,537,127

NGL sales (gallons)  
 
142,438,132

 
11,827,811

 
 
165,589,355

Average Pricing:
 
 
 
 
 
 
 
Realized natural gas ($/MMBtu)  (3)
 
$
3.40

 
$
2.44

 
 
$
2.44

Realized NGL ($/gallon)  (3)
 
0.85

 
1.17

 
 
1.17

Natural Gas Daily Waha ($/MMBtu)
 
3.42

 
2.40

 
 
2.43

Natural Gas Daily El Paso ($/MMBtu)
 
3.42

 
2.39

 
 
2.42

Estimated plant processing spread ($/gallon)
 
0.54

 
0.99

 
 
0.96


(1) 
Cost of natural gas and other energy consists of natural gas and NGL purchase costs, fractionation and other fees.
(2) 
Gross margin consists of operating revenues less cost of natural gas and other energy.  The Company believes that this measurement is meaningful for understanding and analyzing the Gathering and Processing segment’s operating results for the periods presented because commodity costs are a significant factor in the determination of the segment’s revenues.
(3) 
Excludes impact of realized and unrealized commodity derivative gains and losses.
Following is a discussion of the significant items and variances impacting Segment Adjusted EBITDA for the Company’s Gathering and Processing segment.
Gross Margin. Gross margin for the three months ended March 31, 2013 decreased compared to the predecessor and successor periods in 2012 due to decreases in natural gas and NGL sales volumes and a decrease in market-driven realized average NGL prices. Realized average natural gas and NGL prices were $3.40 per MMBtu and $0.85 per gallon for the three months ended March 31, 2013, compared to $2.44 per MMBtu and $1.17 per gallon for the period from March 26, 2012 to March 31, 2012 and $2.44 per MMBtu and $1.17 per gallon for the period from January 1, 2012 to March 25, 2012.

26


Operating, Maintenance and General Expenses. Operating, maintenance and general expenses increased during the three months ended March 31, 2013 due to expansion of the SUGS system. This change was offset by the absence of $15 million in merger-related employee severance expenses that were incurred during the period from March 26, 2012 to March 31, 2012.

Distribution Segment

The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts through the Company’s Missouri Gas Energy and New England Gas Company operating divisions, respectively.  The operations of the Distribution segment have been classified as discontinued operations at March 31, 2013. The Distribution segment’s operations are regulated by the public utility regulatory commissions of the states in which each operates.  The Distribution segment’s operations have historically been sensitive to weather and seasonal in nature, with a significant percentage of annual operating revenues (which include pass-through gas purchase costs that are seasonally impacted) and Segment Adjusted EBITDA occurring in the traditional winter heating season during the first and fourth calendar quarters.  Most of Missouri Gas Energy’s revenues are based on a distribution rate structure that eliminates the impact of weather and conservations.  For additional information related to rate matters within the Distribution segment, see Note 13 to our consolidated financial statements.

The following table illustrates the results of operations applicable to the Company’s Distribution segment for the periods presented.
 
 
Successor
 
 
Predecessor
 
 
Three Months Ended
March 31, 2013
 
Period from Acquisition
(March 26, 2012) to March 31,
2012
 
 
Period from
January 1, 2012 to
March 25,
2012
Amounts reported within discontinued operations:
 
 
 
 
 
 
 
Net operating revenues  (1)
 
$
73

 
$
5

 
 
$
66

Operating, maintenance and general expenses, excluding non-cash compensation expense and amortization of regulatory assets
 
(30
)
 
(14
)
 
 
(29
)
Taxes other than on income and revenues
 
(4
)
 
(1
)
 
 
(3
)
Segment Adjusted EBITDA
 
$
39

 
$
(10
)