Energy Transfer LP - FORM 8-K - EX-99.2 - SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009 - June 6, 2012

Attached files

file filename
8-K - FORM 8-K/A - Energy Transfer LPete60820128-kx12312011prof.htm
EX-99.1 - UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Energy Transfer LPex991ete-12312011proformae.htm
EX-23.1 - CONSENT OF PRICEWATERHOUSECOOPERS LLP - Energy Transfer LPex231ete8-kconsentofaccoun.htm

 SOUTHERN UNION COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
Financial Statements and Supplementary Data:
Page(s):
Consolidated Statements of Operations
F-2
Consolidated Balance Sheets
F-3 - F-4
Consolidated Statements of Cash Flows
F-5
Consolidated Statements of Stockholders’ Equity and Comprehensive Income
F-6 - F-7
Notes to Consolidated Financial Statements
F-8
Report of Independent Registered Public Accounting Firm
F-61


All schedules are omitted as the required information is not applicable or the information is presented in the consolidated financial statements or related notes.



GLOSSARY

The abbreviations, acronyms and industry terminology commonly used in these financial statements are defined as follows:

AFUDC            Allowance for funds used during construction
ARO            Asset retirement obligation
Bcf            Billion cubic feet
Bcf/d            Billion cubic feet per day
Btu            British thermal units
Citrus            Citrus Corp.
Company            Southern Union and its subsidiaries
EBIT            Earnings before interest and taxes
EBITDA            Earnings before interest, taxes, depreciation and amortization
EITR            Effective income tax rate
EPA            United States Environmental Protection Agency
EPS            Earnings per share
ETE            Energy Transfer Equity, L.P.
ETP            Energy Transfer Partners, L.P., a subsidiary of ETE
Exchange Act         Securities Exchange Act of 1934
FASB            Financial Accounting Standards Board
FDOT/FTE        Florida Department of Transportation/ Florida’s Turnpike Enterprise
FERC            Federal Energy Regulatory Commission
Florida Gas        Florida Gas Transmission Company, LLC, a wholly-owned subsidiary of Citrus
GAAP            Accounting principles generally accepted in the United States of America
Grey Ranch         Grey Ranch Plant, LP
HCAs             High consequence areas
IRS            Internal Revenue Service
KDHE            Kansas Department of Health and Environment
LNG            Liquified natural gas
LNG Holdings         Trunkline LNG Holdings, LLC
MADEP             Massachusetts Department of Environmental Protection
MDPU            Massachusetts Department of Public Utilities
MGPs            Manufactured gas plants
MMBtu            Million British thermal units
MMBtu/d         Million British thermal units per day
MMcf            Million cubic feet
MMcf/d            Million cubic feet per day
MPSC            Missouri Public Service Commission
NGL            Natural gas liquids
NMED            New Mexico Environment Department
NYMEX            New York Mercantile Exchange
Panhandle        Panhandle Eastern Pipe Line Company, LP and its subsidiaries
PCBs            Polychlorinated biphenyls
PEPL            Panhandle Eastern Pipe Line Company, LP
PRPs            Potentially responsible parties
RCRA             Resource Conservation and Recovery Act
SARs             Stock appreciation rights
Sea Robin        Sea Robin Pipeline Company, LLC
SEC            U.S. Securities and Exchange Commission
Sigma            Sigma Acquisition Corporation
Southern Union        Southern Union Company
Southwest Gas        Pan Gas Storage, LLC (d.b.a. Southwest Gas)
SPCC            Spill Prevention, Control and Countermeasure
SUGS            Southern Union Gas Services
TCEQ            Texas Commission on Environmental Quality
Trunkline            Trunkline Gas Company, LLC
Trunkline LNG        Trunkline LNG Company, LLC


F-1


SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(In thousands, except per share amounts)
Operating revenues (Note 18):
 
 
 
 
 
 
Natural gas gathering and processing
 
$
1,179,680

 
$
1,008,023

 
$
732,251

Natural gas distribution
 
666,650

 
698,513

 
692,904

Natural gas transportation and storage
 
803,650

 
769,450

 
749,161

Other
 
15,974

 
13,927

 
4,702

Total operating revenues
 
2,665,954

 
2,489,913

 
2,179,018

 
 
 
 
 
 
 
Operating expenses:
 
 

 
 

 
 

Cost of natural gas and other energy
 
1,362,177

 
1,243,749

 
1,060,892

Operating, maintenance and general
 
498,255

 
463,517

 
468,721

Depreciation and amortization
 
237,690

 
228,637

 
213,827

Revenue-related taxes
 
35,608

 
37,619

 
36,375

Taxes, other than on income and revenues
 
54,366

 
55,776

 
53,114

Total operating expenses
 
2,188,096

 
2,029,298

 
1,832,929

 
 
 
 
 
 
 
Operating income
 
477,858

 
460,615

 
346,089

 
 
 
 
 
 
 
Other income (expenses):
 
 

 
 

 
 

Interest expense
 
(219,232
)
 
(216,665
)
 
(196,800
)
Earnings from unconsolidated investments
 
98,935

 
105,415

 
80,790

Other, net  (Note 22)
 
1,643

 
312

 
21,401

Total other expenses, net
 
(118,654
)
 
(110,938
)
 
(94,609
)
 
 
 
 
 
 
 
Earnings from continuing operations before income taxes
 
359,204

 
349,677

 
251,480

 
 
 
 
 
 
 
Federal and state income tax expense (Note 10)
 
103,780

 
107,029

 
71,900

 
 
 
 
 
 
 
Earnings from continuing operations
 
255,424

 
242,648

 
179,580

 
 
 
 
 
 
 
Loss from discontinued operations (Note 23)
 
—

 
(18,100
)
 
—

 
 
 
 
 
 
 
Net earnings
 
255,424

 
224,548

 
179,580

 
 
 
 
 
 
 
Preferred stock dividends
 
—

 
(5,040
)
 
(8,683
)
Loss on extinguishment of preferred stock
 
—

 
(3,295
)
 
—

 
 
 
 
 
 
 
Net earnings available for common stockholders
 
$
255,424

 
$
216,213

 
$
170,897

 
 
 
 
 
 
 
Net earnings available for common stockholders
 
 

 
 

 
 

from continuing operations per share (Note 5):
 
 

 
 

 
 

Basic
 
$
2.05

 
$
1.88

 
$
1.38

Diluted
 
$
2.02

 
$
1.87

 
$
1.37

 
 
 
 
 
 
 
Net earnings available for common stockholders per share (Note 5):
 
 

 
 

 
 

Basic
 
$
2.05

 
$
1.74

 
$
1.38

Diluted
 
$
2.02

 
$
1.73

 
$
1.37

Cash dividends declared on common stock per share:
 
$
0.60

 
$
0.60

 
$
0.60

 
 
 
 
 
 
 
Weighted average shares outstanding (Note 5):
 
 

 
 

 
 

Basic
 
124,720

 
124,474

 
124,076

Diluted
 
126,283

 
125,191

 
124,409


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

F-2


SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 


ASSETS
 
 
December 31,
 
 
2011
 
2010
 
 
(In thousands)
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
23,640

 
$
3,299

Accounts receivable
 
 

 
 

net of allowances of $2,325 and $3,321, respectively
 
270,741

 
310,006

Accounts receivable – affiliates
 
10,467

 
10,747

Inventories
 
204,235

 
226,875

Deferred natural gas purchases
 
50,716

 
85,138

Natural gas imbalances - receivable
 
54,549

 
52,141

Prepayments and other assets
 
42,675

 
67,535

Total current assets
 
657,023

 
755,741

 
 
 
 
 
Property, plant and equipment (Note 13):
 
 

 
 

Plant in service
 
7,195,747

 
6,957,989

Construction work in progress
 
103,862

 
120,264

 
 
7,299,609

 
7,078,253

Less accumulated depreciation and amortization
 
(1,573,273
)
 
(1,373,794
)
Net property, plant and equipment
 
5,726,336

 
5,704,459

 
 
 
 
 
Deferred charges:
 
 

 
 

Regulatory assets (Note 4)
 
57,447

 
66,216

Deferred charges
 
60,407

 
66,929

Total deferred charges
 
117,854

 
133,145

 
 
 
 
 
Unconsolidated investments  (Note 6)
 
1,633,289

 
1,538,548

 
 
 
 
 
Goodwill
 
89,227

 
89,227

 
 
 
 
 
Other
 
47,130

 
17,423

 
 
 
 
 
 
 
 
 
 
Total assets
 
$
8,270,859

 
$
8,238,543








 


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

F-3


SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 


STOCKHOLDERS' EQUITY AND LIABILITIES
 
 
December 31,
 
 
2011
 
2010
 
 
(In thousands)
Stockholders’ equity (Note 16):
 
 
 
 
Common stock, $1 par value; 200,000 shares authorized;
 
 
 
 
126,142 and 125,839 shares issued at December 31, 2011
 
 
 
 
and 2010, respectively
 
$
126,142

 
$
125,839

Premium on capital stock
 
1,934,102

 
1,920,622

Less treasury stock: 1,298 and 1,230 shares, respectively, at cost
 
(33,228
)
 
(30,532
)
Less common stock held in trust: 581 and 597 shares, respectively
 
(10,888
)
 
(10,857
)
Deferred compensation plans
 
10,888

 
10,857

Accumulated other comprehensive loss (Note 7)
 
(119,192
)
 
(40,157
)
Retained earnings
 
731,787

 
551,210

Total stockholders' equity
 
2,639,611

 
2,526,982

 
 
 
 
 
Long-term debt obligations  (Note 8)
 
3,160,372

 
3,520,906

 
 
 
 
 
Total capitalization
 
5,799,983

 
6,047,888

 
 
 
 
 
Current liabilities:
 
 

 
 

Long-term debt due within one year  (Note 8)
 
343,254

 
1,083

Notes payable (Note 8)
 
200,000

 
297,051

Accounts payable and accrued liabilities
 
194,127

 
218,531

Federal, state and local taxes payable
 
37,127

 
35,235

Accrued interest
 
33,837

 
37,464

Natural gas imbalances - payable
 
145,212

 
178,087

Derivative instruments (Note 11 and 12)
 
58,598

 
67,026

Other
 
112,135

 
137,221

Total current liabilities
 
1,124,290

 
971,698

 
 
 
 
 
Deferred credits
 
301,709

 
205,094

 
 
 
 
 
Accumulated deferred income taxes  (Note 10)
 
1,044,877

 
1,013,863

 
 
 
 
 
Commitments and contingencies  (Note 15)
 
 

 
 

 
 
 
 
 
Total stockholders' equity and liabilities
 
$
8,270,859

 
$
8,238,543









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

F-4


SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

 
 
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(In thousands)
Cash flows provided by (used in) operating activities:
 
 

 
 

 
 

Net earnings
 
$
255,424

 
$
224,548

 
$
179,580

Adjustments to reconcile net earnings to net cash flows
 
 

 
 

 
 

provided by (used in) operating activities:
 
 

 
 

 
 

Depreciation and amortization
 
237,690

 
228,637

 
213,827

Deferred income taxes
 
103,538

 
107,418

 
121,210

Provision for bad debts
 
8,089

 
8,681

 
8,601

Unrealized loss on commodity derivatives
 
50

 
18,514

 
44,778

Loss from discontinued operations
 
—

 
18,100

 
—

Loss on asset sales or dispositions
 
1,578

 
1,867

 
5,563

Stock-based compensation expense
 
10,149

 
9,331

 
7,510

Earnings from unconsolidated investments,
 
 

 
 

 
 

adjusted for cash distributions
 
(95,605
)
 
(101,915
)
 
(80,790
)
Changes in operating assets and liabilities:
 
 

 
 

 
 

Accounts receivable, billed and unbilled
 
31,456

 
(41,386
)
 
45,452

Accounts payable and accrued liabilities
 
(10,390
)
 
(8,508
)
 
12,838

Deferred natural gas purchase costs
 
37,095

 
(2,883
)
 
(73,174
)
Inventories
 
(5,848
)
 
(2,964
)
 
76,098

Prepaids and other assets
 
(1,938
)
 
(1,534
)
 
60,748

Taxes and other liabilities
 
(38,809
)
 
17,831

 
(57,962
)
Deferred charges
 
19,022

 
6,891

 
(266
)
Deferred credits
 
(20,460
)
 
(57,957
)
 
15,200

Net cash flows provided by operating activities
 
531,041

 
424,671

 
579,213

Cash flows (used in) provided by investing activities:
 
 

 
 

 
 

Additions to property, plant and equipment
 
(290,290
)
 
(293,022
)
 
(405,381
)
Contributions to unconsolidated investments
 
—

 
(100,000
)
 
(3,250
)
Loan to unconsolidated investments
 
(72,000
)
 
—

 
—

Loan repayment from unconsolidated investments
 
35,000

 
—

 
—

Plant retirements and other
 
(743
)
 
531

 
(10,793
)
Net cash flows used in investing activities
 
(328,033
)
 
(392,491
)
 
(419,424
)
Cash flows provided by (used in) financing activities:
 
 

 
 

 
 

Increase (decrease) in book overdraft
 
8,975

 
(14,154
)
 
8,583

Issuance of long-term debt
 
—

 
101,019

 
303,905

Renewal cost for credit facilities and issuance costs of debt
 
(2,162
)
 
(7,066
)
 
(4,011
)
Dividends paid on common stock
 
(74,811
)
 
(74,668
)
 
(74,424
)
Dividends paid on preferred stock
 
—

 
(7,211
)
 
(8,683
)
Extinguishment of preferred stock
 
—

 
(115,000
)
 
—

Repayment of long-term debt obligation
 
(18,556
)
 
(140,947
)
 
(60,623
)
Net change in revolving credit facilities and short-term debt
 
(97,051
)
 
217,051

 
(321,459
)
Other
 
938

 
1,550

 
3,150

Net cash flows provided by (used in) financing activities
 
(182,667
)
 
(39,426
)
 
(153,562
)
Change in cash and cash equivalents
 
20,341

 
(7,246
)
 
6,227

Cash and cash equivalents at beginning of period
 
3,299

 
10,545

 
4,318

Cash and cash equivalents at end of period
 
$
23,640

 
$
3,299

 
$
10,545

 
 
 
 
 
 
 
Cash paid for interest (net of amounts capitalized)
 
$
213,625

 
$
212,442

 
$
217,437

Cash (received) paid during the period for income taxes
 
(10,918
)
 
(20,088
)
 
486

 
 
 
 
 
 
 



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

F-5


SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
 

 
Common
Stock,
$1 Par
Value
 
Preferred
Stock,
No Par
Value
 
Premium
on
Capital
Stock
 
Treasury
Stock,
at cost
 
Common
Stock
Held
In Trust
 
Deferred
Compen-
sation
Plans
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Retained
Earnings
(Deficit)
 
Total
Stock-
holders'
Equity
 
(In thousands)
Balance December 31, 2008
$
125,122

 
$
115,000

 
$
1,893,975

 
$
(28,004
)
 
$
(11,908
)
 
$
11,908

 
$
(51,423
)
 
$
313,282

 
$
2,367,952

Comprehensive income (loss):
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Net earnings
—

 
—

 
—

 
—

 
—

 
—

 
—

 
179,580

 
179,580

Net change in other
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Net change in other comprehensive loss (Note 7),
—

 
—

 
—

 
—

 
—

 
—

 
(5,082
)
 
—

 
(5,082
)
Comprehensive income
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
174,498

Preferred stock dividends
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(8,683
)
 
(8,683
)
Common stock dividends declared
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(74,481
)
 
(74,481
)
Stock-based compensation
—

 
—

 
7,510

 
—

 
—

 
—

 
—

 
—

 
7,510

Restricted stock issuances
147

 
—

 
(633
)
 
(980
)
 
—

 
—

 
—

 
—

 
(1,466
)
Exercise of stock options
300

 
—

 
4,441

 
(125
)
 
—

 
—

 
—

 
—

 
4,616

Contributions to Trust
—

 
—

 
—

 
—

 
(1,010
)
 
1,010

 
—

 
—

 
—

Disbursements from Trust
—

 
—

 
—

 
—

 
1,149

 
(1,149
)
 
—

 
—

 
—

Balance December 31, 2009
$
125,569

 
$
115,000

 
$
1,905,293

 
$
(29,109
)
 
$
(11,769
)
 
$
11,769

 
$
(56,505
)
 
$
409,698

 
$
2,469,946

Comprehensive income (loss):
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Net earnings
—

 
—

 
—

 
—

 
—

 
—

 
—

 
224,548

 
224,548

Net change in other comprehensive loss (Note 7)
—

 
—

 
—

 
—

 
—

 
—

 
16,348

 
—

 
16,348

Comprehensive income
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
240,896

Preferred stock dividends
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(5,040
)
 
(5,040
)
Common stock dividends declared
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(74,701
)
 
(74,701
)
Stock-based compensation
—

 
—

 
9,331

 
—

 
—

 
—

 
—

 
—

 
9,331

Restricted stock issuances
149

 
—

 
658

 
(1,270
)
 
—

 
—

 
—

 
—

 
(463
)
Exercise of stock options
121

 
—

 
2,045

 
(153
)
 
—

 
—

 
—

 
—

 
2,013

Redemption of preferred stock (Note 17)
—

 
(115,000
)
 
3,295

 
—

 
—

 
—

 
—

 
(3,295
)
 
(115,000
)
Contributions to Trust
—

 
—

 
—

 
—

 
(782
)
 
782

 
—

 
—

 
—

Disbursements from Trust
—

 
—

 
—

 
—

 
1,694

 
(1,694
)
 
—

 
—

 
—

Balance December 31, 2010
$
125,839

 
$
—

 
$
1,920,622

 
$
(30,532
)
 
$
(10,857
)
 
$
10,857

 
$
(40,157
)
 
$
551,210

 
$
2,526,982





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

F-6


SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
 

(Continued)
 
Common
Stock,
$1 Par
Value
 
Preferred
Stock,
No Par
Value
 
Premium
on
Capital
Stock
 
Treasury
Stock,
at cost
 
Common
Stock
Held
In Trust
 
Deferred
Compen-
sation
Plans
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Retained
Earnings
(Deficit)
 
Total
Stock-
holders'
Equity
 
(In thousands)
Balance December 31, 2010 
$
125,839

 
$
—

 
$
1,920,622

 
$
(30,532
)
 
$
(10,857
)
 
$
10,857

 
$
(40,157
)
 
$
551,210

 
$
2,526,982

Comprehensive income (loss):
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Net earnings
—

 
—

 
—

 
—

 
—

 
—

 
—

 
255,424

 
255,424

Net change in other comprehensive loss (Note 7)
—

 
—

 
—

 
—

 
—

 
—

 
(79,035
)
 
—

 
(79,035
)
Comprehensive income
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
176,389

Common stock dividends declared
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(74,847
)
 
(74,847
)
Stock-based compensation
—

 
—

 
10,149

 
—

 
—

 
—

 
—

 
—

 
10,149

Restricted stock issuances
162

 
—

 
1,234

 
(2,419
)
 
—

 
—

 
—

 
—

 
(1,023
)
Exercise of stock options
141

 
—

 
2,097

 
(277
)
 
—

 
—

 
—

 
—

 
1,961

Contributions to Trust
—

 
—

 
—

 
—

 
(701
)
 
701

 
—

 
—

 
—

Disbursements from Trust
—

 
—

 
—

 
—

 
670

 
(670
)
 
—

 
—

 
—

Balance December 31, 2011 
$
126,142

 
$
—

 
$
1,934,102

 
$
(33,228
)
 
$
(10,888
)
 
$
10,888

 
$
(119,192
)
 
$
731,787

 
$
2,639,611


 
The Company’s common stock is $1 par value. Therefore, the change in Common Stock, $1 par value, is equivalent to the change in the number of shares of common stock issued.























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

F-7

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  Corporate Structure
The Company was incorporated under the laws of the State of Delaware in 1932.  The Company owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, processing, transportation, storage and distribution of natural gas in the United States.  Through Panhandle, the Company owns and operates approximately 10,000 miles of interstate pipelines that transport up to 5.5 Bcf/d of natural gas from the Gulf of Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes regions.  Panhandle also owns and operates an LNG import terminal located on Louisiana’s Gulf Coast.  Through its investment in Citrus, the Company has an interest in and operates Florida Gas, an interstate pipeline company that transports natural gas from producing areas in South Texas through the Gulf Coast region to Florida.  Through SUGS, the Company owns approximately 5,600 miles of natural gas and NGL pipelines, five cryogenic plants with a combined capacity of 475 MMcf/d and five natural gas treating plants with combined capacities of 585 MMcf/d.  SUGS is primarily engaged in connecting producing wells of exploration and production (E&P) companies 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 located in West Texas and Southeast New Mexico.  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.
See Note 3 – ETE Merger for information related to the Company’s intent to merge with ETE.
2.  Summary of Significant Accounting Policies and Other Matters
Basis of Presentation.   The Company’s consolidated financial statements have been prepared in accordance with GAAP.
Principles of Consolidation.  The consolidated financial statements include the accounts of Southern Union and its wholly-owned subsidiaries.  Investments in which the Company has significant influence over the operations of the investee are accounted for using the equity method.  All sig­nifi­cant intercompany accounts and transactions are eliminated in consolidation.
Use of Estimates.  The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.
Property, Plant and Equipment.
Additions.  Ongoing additions of property, plant and equipment are stated at cost. The Company capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Such indirect construction costs primarily include capitalized interest costs (more fully described below in the Interest Cost Capitalized accounting policies disclosure) and labor and related costs of departments associated with supporting construction activities.  The indirect capitalized labor and related costs are largely based upon results of periodic time studies or management reviews of time allocations, which provide an estimate of time spent supporting construction projects.  The cost of replacements and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs and replacements of minor property, plant and equipment items is charged to expense as incurred.
Retirements.  When ordinary retirements of property, plant and equipment occur within the Company’s regulated Transportation and Storage and Distribution segments, the original cost less salvage value is removed by a charge to accumulated depreciation and amortization, with no gain or loss recorded.  When entire regulated operating units of property, plant and equipment are retired or sold, the original cost less salvage value and related accumulated depreciation and amortization accounts are removed, with any resulting gain or loss recorded in earnings. 

F-8

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

When property, plant and equipment is retired within the Company’s Gathering and Processing segment, or within its other non-regulated operations, the original cost less salvage value and accumulated depreciation and amortization balances are removed, with any resulting gain or loss recorded in earnings.
Depreciation.  The Company computes depreciation expense using the straight-line method.  Depreciation rates for the Company’s Distribution segment are approved by the applicable regulatory commissions.
Computer Software.  Computer software, which is a component of property, plant and equipment, is stated at cost and is generally amortized on a straight-line basis over its useful life on a product-by-product basis.
For additional information, see Note 13 – Property, Plant and Equipment.
Asset Impairment.  An impairment loss is recognized when the carrying amount of a long-lived asset used in operations is not recoverable and exceeds its fair value.  The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.  A long-lived asset is tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable.
Goodwill.  Goodwill resulting from a purchase business combination is not amortized, but instead is tested for impairment at the Company’s Distribution segment reporting unit level at least annually by applying a fair-value based test.  The annual impairment test is updated if events or circumstances occur that would more likely than not reduce the fair value of the reporting unit below its book carrying value.  The Company evaluated goodwill for potential impairment for the years ended December 31, 2011, 2010 and 2009, and no impairment was indicated in the step one test.  There were no changes recorded to goodwill for the years ended December 31, 2011, 2010 and 2009.
Cash and Cash Equivalents.  Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.
Under the Company’s cash management system, checks issued but not presented to banks frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the Consolidated Balance Sheet.  At December 31, 2011 and 2010, such book overdraft balances classified in accounts payable were approximately $21 million and $12 million, respectively.
Segment Reporting.  The Company reports its operations under three reportable segments: the Transportation and Storage segment, the Gathering and Processing segment and the Distribution segment.  See Note 18 – Reportable Segments for additional related information.
Transportation and Storage Segment Revenues.  Revenues from transportation and storage of natural gas and LNG terminalling are based on capacity reservation charges and, to a lesser extent, commodity usage charges.  Reservation revenues are based on contracted rates and capacity reserved by the customers and are recognized monthly.  Revenues from commodity usage charges are also recognized monthly, based on the volumes received from or delivered for the customer, based on the tariff of that particular Panhandle entity, with any differences in volumes received and delivered resulting in an imbalance.  Volume imbalances generally are settled in-kind with no impact on revenues, with the exception of Trunkline, which settles certain imbalances in cash pursuant to its tariff, and records gains and losses on such cashout sales as a component of revenue, to the extent not owed back to customers.
Gathering and Processing Segment Revenues and Cost of Sales Recognition.  The business operations of the Gathering and Processing segment consist of connecting wells of natural gas producers to the Company’s gathering system, treating natural gas to remove impurities, processing natural gas for the removal of NGL and then redelivering or marketing the treated natural gas and/or processed NGL to third parties.  The terms and conditions of purchase arrangements with producers, including those limited arrangements with the samecounterparty, offer various alternatives with respect to taking title to the purchased natural gas and/or NGL.  These arrangements include (i) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing in the Company’s plant facilities and (ii) making other direct purchase of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations.  Cost of sales primarily includes the cost of purchased natural gas and/or NGL to which the Company has taken title.  Operating revenues derived from the sale of natural gas and/or NGL are recognized in the period in which the physical product is delivered to the customer and title is transferred.  Operating revenues derived from fees charged to producers are recognized in the period in which the service is provided.  Operating revenues and cost of sales within the Gathering and Processing segment are reported on a gross basis.

F-9

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Natural Gas Distribution Segment Revenues and Natural Gas Purchase Costs.   In the Distribution segment, natural gas utility customers are billed on a monthly-cycle basis.  The related cost of natural gas and revenue taxes are matched with cycle-billed revenues through utilization of purchased natural gas adjustment provisions in tariffs approved by the regulatory agencies having jurisdiction.  Revenues from natural gas delivered but not yet billed are accrued, along with the related natural gas purchase costs and revenue-related taxes.
Accounts Receivable and Allowance for Doubtful Accounts.  The Company manages trade credit risks to minimize exposure to uncollectible trade receivables.  In the Transportation and Storage and Gathering and Processing segments, prospective and existing customers are reviewed for creditworthiness based upon pre-established standards.  Customers that do not meet minimum standards are required to provide additional credit support.  In the Distribution segment, concentrations of credit risk in trade receivables are limited due to the large customer base with relatively small individual account balances.  Additionally, the Company requires a deposit from customers in the Distribution segment who lack a credit history or whose credit rating is substandard. The Company utilizes the allowance method for recording its allowance for uncollectible accounts, which is primarily based on the application of historical bad debt percentages applied against its aged accounts receivable.  Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written off.  Past due receivable balances are written-off when the Company’s efforts have been unsuccessful in collecting the amount due.
The following table presents the balance in the allowance for doubtful accounts and activity for the periods presented.
 
 
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(In thousands)
Beginning balance
 
$
3,321

 
$
1,874

 
$
6,003

Additions: charged to cost and expenses
 
8,089

 
8,681

 
8,601

Deductions: write-off of uncollectible accounts
 
(10,663
)
 
(8,230
)
 
(14,505
)
Other
 
1,578

 
996

 
1,775

Ending balance
 
$
2,325

 
$
3,321

 
$
1,874

Earnings Per Share.  Basic earnings per share is computed based on the weighted average number of common shares outstanding during each period.  Diluted earnings per share is computed based on the weighted average number of common shares outstanding during each period, the assumed exercises of stock options and SARs, and the assumed vesting of restricted stock.  See Note 5 – Earnings Per Share.
Stock-Based Compensation.  The Company measures all employee stock-based compensation using a fair value method and records the related expense in its Consolidated Statement of Operations.  For more information, see Note 14 – Stock-Based Compensation.
Accumulated Other Comprehensive Loss.  The main components of comprehensive income (loss) that relate to the Company are net earnings, unrealized gain (loss) on hedging activities and unrealized actuarial gain (loss) and prior service credits (cost) on pension and other postretirement benefit plans.  For more information, see Note 7 – Comprehensive Income (Loss).

F-10

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Inventories.  In the Transportation and Storage segment, inventories consist of natural gas held for operations and materials and supplies, both of which are carried at the lower of weighted average cost or market, while natural gas owed back to customers is valued at market.  The natural gas held for operations that the Company does not expect to consume in its operations in the next twelve months is reflected in non-current assets.
In the Gathering and Processing segment, inventories consist of non-fractionated Y-grade NGL and materials and supplies, both of which are stated at the lower of weighted average cost or market.  Materials and supplies are primarily comprised of compressor components and parts.
In the Distribution segment, inventories consist of natural gas in underground storage and materials and supplies.  The natural gas in underground storage inventory carrying value is stated at weighted average cost and is not adjusted to a lower market value because, pursuant to purchased natural gas adjustment clauses, actual natural gas costs are recovered in customers’ rates.  Materials and supplies inventory is also stated at weighted average cost.
The following table sets forth the components of inventory at the dates indicated.
 
Transportation &
Storage
 
Gathering &
Processing
 
Distribution
 
Total
 
(In thousands)
December 31, 2011
 
 
 
 
 
 
 
Current
 
 
 
 
 
 
 
Natural gas (1)
$
95,916

 
$
—

 
$
62,307

 
$
158,223

Materials and supplies
18,823

 
12,543

 
4,756

 
36,122

NGL (2)
—

 
9,890

 
—

 
9,890

Total Current
114,739

 
22,433

 
67,063

 
204,235

 
 
 
 
 
 
 
 
Non-Current
 

 
 

 
 

 
 

Natural gas (1)
2,643

 
—

 
—

 
2,643

 
$
117,382

 
$
22,433

 
$
67,063

 
$
206,878

 
 
 
 
 
 
 
 
December 31, 2010
 

 
 

 
 

 
 

Current
 

 
 

 
 

 
 

Natural gas (1)
$
129,727

 
$
—

 
$
55,856

 
$
185,583

Materials and Supplies
17,527

 
9,973

 
3,880

 
31,380

NGL (2)
—

 
9,912

 
—

 
9,912

Total Current
147,254

 
19,885

 
59,736

 
226,875

 
 
 
 
 
 
 
 
Non-Current
 

 
 

 
 

 
 

Natural gas (1)
5,715

 
—

 
—

 
5,715

 
$
152,969

 
$
19,885

 
$
59,736

 
$
232,590


____________________
(1)
Natural gas volumes held for operations in the Transportation and Storage segment at December 31, 2011 and 2010 were 29,718,000 MMBtu and 30,598,000 MMBtu, respectively.  Natural gas volumes held for operations in the Distribution segment at December 31, 2011 and 2010 were 14,191,000 MMBtu and 12,517,000 MMBtu, respectively.
(2)
NGL at December 31, 2011 and 2010 were 12,061,000 gallons and 12,061,000 gallons, respectively.

F-11

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Unconsolidated Investments.  Investments in affiliates over which the Company may exercise significant influence, generally 20 percent to 50 percent ownership interests, are accounted for using the equity method. Any excess of the Company’s investment in affiliates, as compared to its share of the underlying equity, that is not recognized as goodwill is amortized over the estimated economic service lives of the underlying assets. Other investments over which the Company may not exercise significant influence are accounted for under the cost method.  A loss in value of an investment, other than a temporary decline, is recognized in earnings.  Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity that would justify the carrying amount of the investment.  A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment.  All of the above factors are considered in the Company’s review of its equity method investments.  See Note 6 – Unconsolidated Investments.
Regulatory Assets and Liabilities.  The Company is subject to regulation by certain state and federal authorities.  In its Distribution segment, the Company’s accounting policies are in accordance with the accounting requirements and ratemaking practices of the applicable regulatory authorities.  These accounting policies allow the Company to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the Consolidated Statement of Operations by an unregulated company.  These deferred assets and liabilities then flow through the results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers.  Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders.  If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheet and included in the Consolidated Statement of Operations for the period in which the discontinuance of regulatory accounting treatment occurs.  See Note 4 – Regulatory Assets.
Fair Value Measurement.  Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk, which is primarily comprised of credit risk (both the Company’s own credit risk and counterparty credit risk) and the risks inherent in the inputs to any applicable valuation techniques.  The Company places more weight on current market information concerning credit risk (e.g. current credit default swap rates) as opposed to historical information (e.g. historical default probabilities and credit ratings).  These inputs can be readily observable, market corroborated, or generally unobservable.  The Company endeavors to utilize the best available information, including valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  A three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value is as follows:
•
Level 1 – Observable inputs such as quoted prices in active markets for identical assets or liabilities;
•
Level 2 – Observable inputs such as: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active and do not require significant adjustment based on unobservable inputs; or (iii) valuations based on pricing models, discounted cash flow methodologies or similar techniques where significant inputs (e.g., interest rates, yield curves, etc.) are derived principally from observable market data, or can be corroborated by observable market data, for substantially the full term of the assets or liabilities; and
•
Level 3 – Unobservable inputs, including valuations based on pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable.  Unobservable inputs are used to the extent that observable inputs are not available and reflect the Company’s own assumptions about the assumptions market participants would use in pricing the assets or liabilities.  Unobservable inputs are based on the best information available in the circumstances, which might include the Company’s own data.

F-12

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy.
The Company’s Level 1 instruments primarily consist of trading securities related to a non-qualified deferred compensation plan that are valued based on active market quotes.  The Company’s Level 2 instruments include commodity derivative instruments, such as natural gas and NGL processing spread swap derivatives, fixed-price forward sales contracts and certain natural gas basis swaps, and interest-rate swap derivatives that are valued based on pricing models where significant inputs are observable.  The Company did not have any Level 3 instruments at December 31, 2011 and 2010.
See Note 12 – Fair Value Measurement and Note 9 – Benefits – Pension and Other Postretirement Plans – Plan Assets for additional information regarding the assets and liabilities of the Company measured on a recurring and nonrecurring basis, respectively.
Natural Gas Imbalances.  In the Transportation and Storage and Gathering and Processing segments, natural gas imbalances occur as a result of differences in volumes of natural gas received and delivered. In the Transportation and Storage segment, the Company records natural gas imbalance in-kind receivables and payables at cost or market, based on whether net imbalances have reduced or increased system natural gas balances, respectively.  Net imbalances that have reduced system natural gas are valued at the cost basis of the system natural gas, while net imbalances that have increased system natural gas and are owed back to customers are priced, along with the corresponding system natural gas, at market.
In the Gathering and Processing segment, the Company records natural gas imbalances as receivables and payables in which imbalances due from a pipeline are recorded at the lower of cost or market and imbalances due to a pipeline are recorded at market.  Market prices are based upon Gas Daily indexes.
Fuel Tracker.  The fuel tracker applicable to the Company’s Transportation and Storage segment is the cumulative balance of compressor fuel volumes owed to the Company by its customers or owed by the Company to its customers.  The customers, pursuant to each pipeline’s tariff and related contracts, provide all compressor fuel to the pipeline based on specified percentages of the customer’s natural gas volumes delivered into the pipeline.  The percentages are designed to match the actual natural gas consumed in moving the natural gas through the pipeline facilities, with any difference between the volumes provided versus volumes consumed reflected in the fuel tracker.  The tariff of Trunkline Gas, in conjunction with the customers’ contractual obligations, allows the Company to record an asset and direct bill customers for any fuel ultimately under-recovered.  The other FERC-regulated Panhandle entities record an expense when fuel is under-recovered or record a credit to expense to the extent any under-recovered prior period balances are subsequently recouped as they do not have such explicit billing rights specified in their tariffs.  Liability accounts are maintained for net volumes of compressor fuel natural gas owed to customers collectively.  The pipelines’ fuel reimbursement is in-kind and non-discountable.
Interest Cost Capitalized.  The Company capitalizes interest on certain qualifying assets that are undergoing activities to prepare them for their intended use.  Interest costs incurred during the construction period are capitalized and amortized over the life of the assets.  Capitalized interest for the years ended December 31, 2011, 2010 and 2009 was $1.2 million, $6.6 million and $25.7 million, respectively.
Derivative Instruments and Hedging Activities.  All derivatives are recognized on the Consolidated Balance Sheet at their fair value.  On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (a fair value hedge);  (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (a cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or economic hedging instrument).  For derivatives treated as a fair value hedge, the effective portion of changes in fair value is recorded as an adjustment to the hedged item.  The ineffective portion of a fair value hedge is recognized in earnings if the short cut method of assessing effectiveness is not used.  Upon termination of a fair value hedge of a debt instrument, the resulting gain or loss is amortized to earnings through the maturity date of the debt instrument.  For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in Accumulated other comprehensive loss until the related hedged items impact earnings.  Any ineffective portion of a cash flow hedge is reported in current-period earnings.  For derivatives treated as trading or economic hedging instruments, changes in fair value are reported in current-period earnings.  Fair value is determined based upon quoted market prices and pricing models using assumptions that market participants would use.  See Note 11 – Derivative Instruments and Hedging Activities and Note 12 – Fair Value Measurement for additional related information.

F-13

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset Retirement Obligations.  Legal obligations associated with the retirement of long-lived assets are recorded at fair value at the time the obligations are incurred,  if a reasonable estimate of fair value can be made.  Present value techniques are used which reflect assumptions such as removal and remediation costs, inflation,  and profit margins that third parties would demand to settle the amount of the future obligation. The Company did not include a market risk premium for unforeseeable circumstances in its fair value estimates because such a premium could not be reliably estimated.   Upon initial recognition of the liability, costs are capitalized as a part of the long-lived asset and allocated to expense over the useful life of the related asset.   The liability is accreted to its present value each period with accretion being recorded to operating expense with a corresponding increase in the carrying amount of the liability.    To the extent the Company is permitted to collect and has reflected in its financials amounts previously collected from customers and expensed, such amounts serve to reduce what would be reflected as capitalized costs at the initial establishment of an ARO.
For more information, see Note 21 – Asset Retirement Obligations.
Income Taxes.  Income taxes are accounted for under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
The determination of the Company’s provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items.  Reserves are established when, despite management’s belief that the Company’s tax return positions are fully supportable, management believes that certain positions may be successfully challenged. When facts and circumstances change, these reserves are adjusted through the provision for income taxes.
Pensions and Other Postretirement Benefit Plans. Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.   Employers must recognize the change in the funded status of the plan in the year in which the change occurs through Accumulated other comprehensive loss in stockholders’ equity.
See Note 9 – Benefits for additional related information.
Commitments and Contingencies.  The Company is subject to proceedings, lawsuits and other claims related to environmental and other matters.  Accounting for contingencies requires significant judgment by management regarding the estimated probabilities and ranges of exposure to potential liability.  For further discussion of the Company’s commitments and contingencies, see Note 15 – Commitments and Contingencies.

F-14

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

New Accounting Principles
Accounting Principles Not Yet Adopted.  In December 2011, the FASB issued authoritative guidance that enhances current disclosures about offsetting asset and liabilities.  The guidance requires entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement.  The guidance is effective for annual and interim reporting periods beginning on or after January 1, 2013.  The Company does not expect the guidance to materially impact its consolidated financial statements.
In September 2011, the FASB issued authoritative guidance that revises the testing of goodwill impairment.  Under the revised guidance, entities testing goodwill for impairment have the option of performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step 1 of the goodwill impairment test).  If the entity determines, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step impairment test would be required.  The guidance is effective as of the beginning of a fiscal year that begins after December 15, 2011 and interim and annual periods thereafter, with early adoption permitted.  The Company does not expect the guidance to materially impact its consolidated financial statements.
In June 2011, the FASB issued authoritative guidance that changes how a company may present comprehensive income.  The guidance allows entities to elect to present items of net income and other comprehensive income in one continuous statement or in two separate, but consecutive, statements and eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.  The entity is also required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement where the components of net income and the components of other comprehensive income are presented.  The guidance is effective as of the beginning of a fiscal year that begins after December 15, 2011 and interim and annual periods thereafter, with early adoption permitted.  In December 2011, the FASB issued authoritative guidance that defers the presentation requirements for reclassification adjustments to allow the FASB time to redeliberate these requirements.  The Company does not expect the guidance to materially impact its consolidated financial statements as the guidance only requires a change in the placement of previously disclosed information.
In May 2011, the FASB issued authoritative guidance on fair value measurements that clarifies some existing concepts, eliminates wording differences between GAAP and International Financial Reporting Standards (IFRS), and in some limited cases, changes some principles to achieve convergence between GAAP and IFRS.  The guidance provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS and also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs.  The guidance is effective for periods beginning after December 15, 2011.  The Company is currently evaluating the impact of this guidance, but does not expect it will materially impact its consolidated financial statements.
3.  ETE Merger
On July 19, 2011, Southern Union entered into a Second Amended and Restated Agreement and Plan of Merger with ETE and Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE (Merger Sub) (as amended by Amendment No. 1 to Second Amended and Restated Agreement and Plan of Merger dated as of September 14, 2011, the Second Amended Merger Agreement).  The Second Amended Merger Agreement modifies certain terms of the Agreement and Plan of Merger entered into by Southern Union, ETE and Merger Sub on June 15, 2011 as amended on July 4, 2011.  The Second Amended Merger Agreement provides for the merger of Merger Sub with and into Southern Union (Merger), with Southern Union continuing as the surviving corporation in the Merger.  As a result of the Merger, Southern Union will become a wholly-owned subsidiary of ETE.  Under the terms of the Second Amended Merger Agreement, Company shareholders can elect to exchange each issued and outstanding share of Company common stock for $44.25 of cash or 1.00x ETE common unit, with no more than 60 percent of the aggregate merger consideration payable in cash and no more than 50 percent payable in ETE common units.  Elections in excess of either the cash or common unit limits will be subject to proration.  On February 17, 2012, the parties mailed merger consideration election forms to Southern Union shareholders of record as of February 10, 2012 and announced that the election deadline for Southern Union stockholders to make merger consideration elections is expected to be 5:00 p.m., Eastern Time, on March 19, 2012 (or such other later date as ETE and Southern Union shall agree).

F-15

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Second Amended Merger Agreement contains certain termination rights for Southern Union and ETE.  In certain circumstances, upon termination of the Second Amended Merger Agreement, Southern Union or ETE, as applicable: (i) will be required to pay a termination fee of $181.3 million to the other and (ii) may be obligated to pay the other’s Merger costs and expenses in an amount not to exceed $54 million.
In addition, ETE and ETP are parties to an Amended and Restated Agreement and Plan of Merger dated as of July 19, 2011 (as amended by Amendment No. 1 to Agreement and Plan of Merger dated as of September 14, 2011) (Citrus Merger Agreement).  The Citrus Merger Agreement provides that Southern Union, CrossCountry Energy, LLC (CrossCountry), PEPL Holdings, LLC (PEPL Holdings) and Citrus ETP Acquisition, L.L.C. (Citrus ETP) will become parties by joinder at a time immediately prior to the closing of the Merger.  Upon becoming a party to the Citrus Merger Agreement, Southern Union will assume the obligations and rights of ETE.  Under the Citrus Merger Agreement, CrossCountry, a wholly-owned subsidiary of Southern Union that indirectly owns a 50 percent interest in Citrus, will be merged with and into Citrus ETP with CrossCountry surviving as a wholly-owned subsidiary of ETP (Citrus Merger).
Immediately prior to the Citrus Merger and in connection with ETP’s financing of the Citrus Merger consideration, Southern Union will contribute its ninety-nine percent interest in PEPL and its 100 percent membership interest in Southern Union Panhandle, LLC to PEPL Holdings.  PEPL Holdings is a wholly-owned subsidiary of CCE Acquisition, LLC.  PEPL Holdings will guarantee payment, on a contingent recourse basis, of up to $2.0 billion of indebtedness of ETP related to the Citrus Merger (or, in the alternative, will indemnify a subsidiary of ETP for payments made by such subsidiary with respect to a guarantee of up to $2.0 billion of indebtedness of ETP by such subsidiary).  The guarantee will be non-recourse to Southern Union.
As consideration for the Citrus Merger, Southern Union will receive from ETP approximately $2.0 billion, consisting of $1.895 billion in cash and $105 million of ETP common units, with the value of the ETP common units based on the volume-weighted average trading price for the ten consecutive trading days ending immediately prior to the date that is three trading days prior to the closing date of the Citrus Merger.  After completion of the Citrus Merger, including receipt of the Citrus Merger consideration, Southern Union will contribute an amount not to exceed $1.45 billion from the Citrus Merger to Merger Sub in exchange for an equity interest in Merger Sub.  The remaining cash proceeds of approximately $445 million in cash would be used to retire existing Company debt.  It is further anticipated that Southern Union or one of its subsidiaries would retain the approximately $105 million of ETP units as an investment in an unconsolidated affiliate.  The consummation of the Citrus Merger is not a condition to consummation of the Merger.
While consummation of the Merger is subject to certain customary conditions, the parties have already satisfied a number of conditions, including without limitation:  (i)  the receipt of stockholder approval, which occurred on December 9, 2011, (ii) the expiration of the waiting period applicable to the merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, which expiration occurred on July 28, 2011, and (iii) the effectiveness, on October 27, 2011 of ETE’s Registration Statement on Form S-4 relating to the ETE common units to be issued in connection with the Merger.
Southern Union and ETE are also continuing to proceed with the regulatory approval process before the MPSC.  Pursuant to a joint application filed by Southern Union and ETE on July 13, 2011 and amended on September 15, 2011, the parties requested an order from the MPSC authorizing Southern Union to take certain actions to allow ETE to acquire the equity interests of Southern Union, including its subsidiaries.  On February 16, 2012, the parties filed with the MPSC a Non-Unanimous Stipulation and Agreement (the Stipulation) among Southern Union, ETE and the MPSC Staff.  Pursuant to the Stipulation, the parties recommend that the MPSC issue an order finding that, subject to the conditions therein, the merger of Merger Sub with and into Southern Union is not detrimental to the public interest and authorizing the undertaking of the Merger and related transactions.  The Office of Public Counsel has indicated that it does not oppose the Stipulation.  Southern Union and ETE have requested that the MPSC consider the Stipulation expeditiously.
The Merger is expected to close in the first quarter of 2012, subject to receipt of MPSC approval and satisfaction of other closing conditions.






4.  Regulatory Assets
The Company records regulatory assets with respect to its Distribution segment operations.  Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations.  In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
The following table provides a summary of regulatory assets at the dates indicated.
 
 
December 31,
 
 
2011
 
2010
 
 
(In thousands)
Pension and Other Postretirement Benefits
 
$
10,481

 
$
18,140

Environmental
 
35,869

 
38,384

Missouri Safety Program
 
448

 
1,147

Other
 
10,649

 
8,545

 
 
$
57,447

 
$
66,216

The Company’s regulatory assets at December 31, 2011 relating to Distribution segment operations that are being recovered through current rates totaled $36.6 million.  The remaining recovery period associated with these assets ranged from 3 months to 84 months.  The Company expects that the $20.8 million of regulatory assets at December 31, 2011 not currently in rates will be included in its rates as rate cases occur in the future.  The Company’s regulatory assets at December 31, 2010 relating to Distribution segment operations that are being recovered through current rates totaled $48.8 million.  The remaining recovery period associated with these assets ranged from 7 months to 84 months.

F-16

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. Earnings Per Share
The following table summarizes the Company’s basic and diluted EPS calculations for the periods presented.
 
 
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(In thousands, except per share amounts)
Net earnings from continuing operations
 
$
255,424

 
$
242,648

 
$
179,580

Loss from discontinued operations
 
—

 
(18,100
)
 
—

Preferred stock dividends
 
—

 
(5,040
)
 
(8,683
)
Loss on extinguishment of preferred stock
 
—

 
(3,295
)
 
—

Net earnings available for common stockholders
 
$
255,424

 
$
216,213

 
$
170,897

 
 
 
 
 
 
 
Weighted average shares outstanding - Basic
 
124,720

 
124,474

 
124,076

Weighted average shares outstanding - Diluted
 
126,283

 
125,191

 
124,409

 
 
 
 
 
 
 
Basic earnings per share:
 
 

 
 

 
 

Net earnings available for common stockholders
 
 

 
 

 
 

from continuing operations
 
$
2.05

 
$
1.88

 
$
1.38

Loss from discontinued operations
 
—

 
(0.14
)
 
—

Net earnings available for common stockholders
 
$
2.05

 
$
1.74

 
$
1.38

 
 
 
 
 
 
 
Diluted earnings per share:
 
 

 
 

 
 

Net earnings available for common stockholders
 
 

 
 

 
 

from continuing operations
 
$
2.02

 
$
1.87

 
$
1.37

Loss from discontinued operations
 
—

 
(0.14
)
 
—

Net earnings available for common stockholders
 
$
2.02

 
$
1.73

 
$
1.37

A reconciliation of the shares used in the basic and diluted EPS calculations is shown in the following table for the periods presented.
 
 
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(In thousands)
Weighted average shares outstanding - Basic
 
124,720

 
124,474

 
124,076

Dilutive effect of stock-based compensation awards
 
1,563

 
717

 
333

Weighted average shares outstanding - Diluted
 
126,283

 
125,191

 
124,409

For the years ended December 31, 2011, 2010 and 2009, no adjustments were required in Net earnings available for common stockholders in the diluted EPS calculations.
Except for the Company’s purchase of common stock used to pay employee federal and state income tax obligations associated with the lapse of restrictions on restricted stock awards and exercises of SARs, the Company did not purchase any shares of its common stock outstanding during the years ended December 31, 2011, 2010 or 2009.

F-17

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The table below includes information related to stock options and SARs that were outstanding but have been excluded from the computation of weighted-average stock options due to the exercise price exceeding the weighted-average market price of the Company’s common shares.
 
December 31,
 
2011
 
2010
 
2009
 
(In thousands, except per share amounts)
Options and SARs excluded
—

 
2,171

 
2,696

Exercise price ranges
$
—

 
$ 24.04 - 28.48
 
$ 21.64 - 28.48
Weighted-average market price
$
35.26

 
$
23.81

 
$
17.70

6.  Unconsolidated Investments
Unconsolidated investments at December 31, 2011 and 2010 include the Company’s 50 percent investment in Citrus and investments in other entities. The Company accounts for these investments using the equity method.  The Company’s share of net earnings or loss from these equity investments is recorded in Earnings from unconsolidated investments in the Consolidated Statement of Operations.
The following table summarizes the Company’s unconsolidated equity investments at the dates indicated.
 
 
December 31,
 
 
2011
 
2010
 
 
(In thousands)
Citrus (1)
 
$
1,608,549

 
$
1,510,847

Other
 
24,740

 
27,701

 
 
$
1,633,289

 
$
1,538,548

_____________________­­­­
(1)  See Note 3 – ETE Merger for information regarding the Company’s intent for its ownership interest in Citrus to be merged with an ETP subsidiary.
The following tables set forth the summarized financial information for the Company’s equity investments for the periods presented.
 
December 31,
 
2011
 
2010
 
Citrus
 
Other Equity
Investments
 
Citrus
 
Other Equity
Investments
 
(In thousands)
Balance Sheet Data:
 
 
 
 
 
 
 
Current assets
$
260,530

 
$
8,247

 
$
107,108

 
$
14,106

Non-current assets
5,814,630

 
42,763

 
5,453,583

 
44,602

Current liabilities
847,505

(1)
1,149

 
316,952

(1)
2,139

Non-current liabilities
3,309,834

 
87

 
3,512,350

 
185

___________________
(1)
The current portion of long-term debt at December 31, 2011 and 2010 was $686.5 million and $21.5 million, respectively.


F-18

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 
 
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
 
Citrus
 
Other Equity
Investments
 
Citrus
 
Other Equity
Investments
 
Citrus
 
Other Equity
Investments
 
 
(In thousands)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
693,626

 
$
9,801

 
$
517,158

 
$
22,492

 
$
508,416

 
$
20,395

Operating income
 
391,707

 
3,222

 
269,789

 
12,323

 
271,897

 
13,765

Net earnings
 
185,380

 
2,892

 
180,927

 
12,273

 
129,683

 
13,680

Citrus
Dividends.  Citrus did not pay dividends to the Company during the years ended December 31, 2011, 2010 and 2009.  Retained earnings at December 31, 2011 and 2010 included undistributed earnings from Citrus of $278.7 million and $181.1 million, respectively.
Citrus Excess Net Investment.  The Company’s equity investment balances include amounts in excess of the Company’s share of the underlying equity of the investee of $650 million and $649 million as of December 31, 2011 and 2010, respectively.  These amounts relate to the Company’s 50 percent equity ownership interest in Citrus.  The following table sets forth the excess net investment of the Company’s 50 percent share of the underlying Citrus equity as of December 31, 2011.
 
 
Excess
Purchase Costs
 
Amortization
Period
 
 
(In thousands)
 
 
Property, plant and equipment
 
$
2,885

 
40 years
Capitalized software
 
1,478

 
5 years
Long-term debt (1)
 
(80,204
)
 
4-20 years
Deferred taxes (1)
 
(6,883
)
 
40 years
Other net liabilities
 
(541
)
 
N/A
Goodwill (2)
 
664,609

 
N/A
Sub-total
 
581,344

 
 
Accumulated, net accretion to equity earnings
 
68,346

 
 
Net investment in excess of underlying equity
 
$
649,690

 
 
_____________________
(1)
Accretion of this amount increases equity earnings and accumulated net accretion.
(2)
The Company’s tax basis in the investment in Citrus includes equity goodwill.
Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus
Florida Gas Phase VIII Expansion.  Florida Gas’ Phase VIII Expansion project was placed in-service on April 1, 2011, at an approximate cost of $2.5 billion, including capitalized equity and debt costs.  To date, Florida Gas has entered into long-term firm transportation service agreements with shippers for 25-year terms accounting for approximately 74 percent of the available expansion capacity.
In 2011, CrossCountry Citrus, LLC (CrossCountry Citrus), an indirect wholly-owned subsidiary of the Company, and Citrus’ other stockholder each made sponsor contributions of $37 million in the form of loans to Citrus, net of repayments.   The Citrus loan has been recorded in Other non-current assets on the Consolidated Balance Sheet.  The contributions are related to the costs of Florida Gas' Phase VIII Expansion project.  In conjunction with anticipated sponsor contributions, Citrus has entered into a promissory note in favor of each stockholder for up to $150 million.  The promissory notes have a final maturity date of March 31, 2014, with no principal payments required prior to the maturity date, and bear an interest rate equal to a one-month Eurodollar rate plus a credit spread of 1.5 percent.  Amounts may be redrawn periodically under the notes to temporarily fund capital expenditures, debt retirements, or other working capital needs.   Citrus’ principal operating asset is Florida Gas, whose debt is rated Baa2 by Moody’s Investor Services, Inc. and BBB by Standard & Poors.

F-19

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In 2010, CrossCountry Citrus and Citrus’ other stockholder each made a $100 million sponsor capital contribution in the form of equity to Citrus to partially fund the Phase VIII Expansion.  The Company’s $100 million capital contribution was funded using its credit facilities.
Florida Gas Rate Filing.  On September 3, 2010, Florida Gas filed a settlement with FERC in full resolution of all issues set for hearing in its rate proceeding.  The Administrative Law Judge certified the settlement on December 21, 2010.  The settlement was approved by FERC on February 24, 2011 and became effective on April 1, 2011.  The settlement results in an increase in certain of Florida Gas’ rate schedules and a decrease in other rate schedules as compared to rates in effect prior to April 1, 2010, with a portion of such decrease not effective until October 1, 2010.
Florida Gas Debt Issuance.  In July 2010, Florida Gas issued $500 million of 5.45% Senior Notes due July 15, 2020 with an offering price of $99.826 (per $100 principal) and $350 million of 4.00% Senior Notes due July 15, 2015 with an offering price of $99.982 (per $100 principal).  Florida Gas used the net proceeds to partially fund the Phase VIII Expansion project and for general corporate purposes, which included the repayment of a portion of Florida Gas’ outstanding debt. On July 19, 2010, Florida Gas (i) made a $98.6 million distribution to Citrus, (ii) repaid $83 million that was outstanding under its credit agreements, and (iii) invested the remainder of the proceeds.  On August 19, 2010, Florida Gas redeemed its $325 million of 7.625% notes due December 1, 2010.
Retirement of Debt Obligations.  As noted in the Citrus financial statements, Citrus expects to refinance Florida Gas’ $250 million senior notes due July 2012 and extend the maturity or refinance  both of the 2007 Citrus Revolver and the  2007 Florida Gas Revolver, each due August 2012.  Alternatively, should Citrus not be successful in such  efforts, Citrus may choose to retire such debt upon maturity by utilizing some combination of cash flows from operations, utilizing available funds on existing sponsor loans from its stockholders, requesting additional sponsor loans from its stockholders  and altering the timing of controllable expenditures, among other things.  Citrus has obtained commitment letters from each of its stockholders to make additional sponsor loans in the event that the repayment of the senior notes and revolvers is necessary.  However, Citrus reasonably believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital and debt markets and market expectations regarding Citrus’ future earnings and cash flows, that it will be able to refinance and/or retire these obligations, as applicable, under acceptable terms prior to their maturity.
Environmental Matters.   Florida Gas is responsible for environmental remediation of contamination resulting from past releases of hydrocarbons and chlorinated compounds at certain sites on its natural gas transmission systems.   Florida Gas is implementing a program to remediate such contamination.  Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity.  The ultimate liability and total costs associated with these sites will depend upon many factors. These sites are generally managed in the normal course of business or operations.  The outcome of these matters is not expected to have a material adverse impact on the Company’s equity investment in Citrus.
Regulatory Assets and Liabilities.  Florida Gas is subject to regulation by certain state and federal authorities.  Florida Gas has accounting policies that conform to regulatory accounting standards and are in accordance with the accounting requirements and ratemaking practices of applicable regulatory authorities.  Florida Gas management’s assessment of the probability of its recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders.  If, for any reason, Florida Gas ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from its consolidated balance sheet, resulting in an impact to the Company’s share of its equity earnings.  Florida Gas’ regulatory asset and liability balances at December 31, 2011 were $32.7 million and $12.8 million, respectively.

F-20

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Florida Gas Pipeline Relocation Costs. The FDOT/FTE has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of Florida Gas’ mainline pipelines located in FDOT/FTE rights-of-way. Several FDOT/FTE projects are the subject of litigation in Broward County, Florida. On January 27, 2011, a jury awarded Florida Gas $82.7 million and rejected all damage claims by the FDOT/FTE.  On May 2, 2011, the judge issued an order entitling Florida Gas to an easement of 15 feet on either side of its pipelines and 75 feet of temporary work space.  The judge further ruled that Florida Gas is entitled to approximately $8 million in interest.  In addition to ruling on other aspects of the easement, he ruled that pavement could not be placed directly over Florida Gas’ pipeline without the consent of Florida Gas although Florida Gas would be required to relocate the pipeline if it did not provide such consent.  He also denied all other pending post-trial motions.  The FDOT/FTE filed a notice of appeal on July 12, 2011.  Briefing to the Florida Fourth District Court of Appeals (4th DCA) is complete.  The 4th DCA granted a request by the FDOT to expedite the appeal.  Oral argument is set for March 7, 2012.  Amounts ultimately received would primarily reduce Florida Gas’ property, plant and equipment costs.
On April 14, 2011 Florida Gas filed suit against the FDOT/FTE, Dragados USA and I-595 Express, LLC in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in Florida Gas easements.  The same judge that presided over the previously discussed FDOT/FTE proceeding was assigned to the case.  Trial is expected to be set in the third quarter of 2012.
Federal Pipeline Integrity Rules. On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule defines as HCAs. This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The rule required operators to identify HCAs along their pipelines and to complete baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessment, by December 2012. Operators were required to rank the risk of their pipeline segments containing HCAs; assessments are generally conducted on the higher risk segments first.  In addition, some system modifications will be necessary to accommodate the in-line inspections. As of December 31, 2011, Florida Gas had completed approximately 96 percent of the baseline risk assessments required to be completed by December 2012. While identification and location of all the HCAs has been completed, it is not practicable to determine with certainty the total scope of required remediation activities prior to completion of the assessments and inspections. The required modifications and inspections are currently estimated to be in the range of approximately $30 million to $40 million per year through 2012.
See Note 3 – ETE Merger for information related to the Citrus Merger, pursuant to which CrossCountry, a subsidiary of the Company that indirectly owns a 50 percent interest in Citrus, would become a wholly-owned subsidiary of ETP.
Other Equity Investments
The Company has other investments in Grey Ranch, the Lee 8 partnership and PEI Power, which are also accounted for under the equity method.  Grey Ranch operates a 200 MMcf/d carbon dioxide treatment facility.  The Lee 8 partnership operates a 3.0 Bcf natural gas storage facility in Michigan.  PEI Power II owns a 45-megawatt, natural gas-fired electric generation plant operated through a joint venture with Cayuga Energy in Pennsylvania.

F-21

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. Comprehensive Income (Loss)
The table below presents Comprehensive income (loss) for the periods presented.
 
 
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(In thousands)
Net Earnings
 
$
255,424

 
$
224,548

 
$
179,580

 
 
 

 
 

 
 

Change in fair value of interest rate hedges, net of tax of $(27,589),
 
 
 
 
 
 
$(5,237) and $(3,051), respectively
 
(46,470
)
 
(7,790
)
 
(4,538
)
Reclassification of unrealized loss (gain) on interest rate hedges
 
 
 
 
 
 
into earnings, net of tax of $9,012, $9,019 and $8,222, respectively
 
13,443

 
13,463

 
12,350

Change in fair value of commodity hedges, net of tax of $2,598,
 
 
 
 
 
 
$14,093 and $3,773, respectively
 
4,610

 
25,012

 
6,696

Reclassification of unrealized (gain) loss on commodity hedges into
 
 
 
 
 
 
earnings, net of tax of $(8,536), $(6,787) and $(16,231), respectively
 
(15,149
)
 
(12,046
)
 
(28,804
)
Actuarial gain (loss) relating to pension and other postretirement
 
 
 
 
 
 
benefits, net of tax of $(24,240), $(4,472) and $6,535, respectively
 
(38,786
)
 
(5,319
)
 
8,185

Prior service cost relating to pension and other postretirement
 
 
 
 
 
 
benefit plan amendments, net of tax of $0, $0 and $(151),
 
 
 
 
 
 
respectively
 
—

 
—

 
(186
)
Reclassification of net actuarial loss and prior service credit
 
 
 
 
 
 
relating to pension and other postretirement benefits into
 
 
 
 
 
 
earnings, net of tax of $2,234, $2,205 and $2,814, respectively
 
3,174

 
2,886

 
4,035

Change in other comprehensive income (loss) from equity
 
 
 
 
 
 
investments, net of tax of $88, $88 and $(1,744), respectively
 
143

 
142

 
(2,820
)
Total other comprehensive income (loss)
 
(79,035
)
 
16,348

 
(5,082
)
Total comprehensive income
 
$
176,389

 
$
240,896

 
$
174,498

The table below presents the components in Accumulated other comprehensive loss as of the dates indicated.
 
December 31,
 
2011
 
2010
 
(In thousands)
Interest rate hedges, net
$
(50,259
)
 
$
(17,232
)
Commodity hedges, net
(11
)
 
10,528

Benefit plans:
 

 
 

Net actuarial loss and prior service costs, net - pensions
(51,845
)
 
(32,982
)
Net actuarial gain and prior service credit, net - other postretirement benefits
(14,542
)
 
2,207

Equity investments, net
(2,535
)
 
(2,678
)
Total Accumulated other comprehensive loss, net of tax
$
(119,192
)
 
$
(40,157
)





F-22

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. Debt Obligations
The following table sets forth the debt obligations of Southern Union and Panhandle at the dates indicated.
 
December 31, 2011
 
December 31, 2010
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
 
(In thousands)
Long-Term Debt Obligations:
 
 
 
 
 
 
 
Southern Union:
 
 
 
 
 
 
 
7.60% Senior Notes due 2024
$
359,765

 
$
417,666

 
$
359,765

 
$
392,144

8.25% Senior Notes due 2029
300,000

 
386,112

 
300,000

 
332,922

7.24% to 9.44% First Mortgage Bonds
 

 
 

 
 

 
 

due 2020 to 2027
19,500

 
23,439

 
19,500

 
21,473

7.20% Junior Subordinated Notes due 2066 (1)
600,000

 
546,480

 
600,000

 
609,743

Term Loan due 2013
250,000

 
251,854

 
250,000

 
249,915

Note Payable
7,746

 
7,746

 
8,297

 
8,297

 
1,537,011

 
1,633,297

 
1,537,562

 
1,614,494

 
 
 
 
 
 
 
 
Panhandle:
 

 
 

 
 

 
 

6.05% Senior Notes due 2013
250,000

 
265,573

 
250,000

 
268,988

6.20% Senior Notes due 2017
300,000

 
340,494

 
300,000

 
322,893

8.125% Senior Notes due 2019
150,000

 
185,301

 
150,000

 
169,671

7.00% Senior Notes due 2029
66,305

 
75,128

 
66,305

 
69,911

7.00% Senior Notes due 2018
400,000

 
467,072

 
400,000

 
442,120

Term Loans due 2012
797,386

 
794,751

 
815,391

 
799,084

Net premiums on long-term debt
2,924

 
2,924

 
2,731

 
2,731

 
1,966,615

 
2,131,243

 
1,984,427

 
2,075,398

 
 
 
 
 
 
 
 
Total Long-Term Debt Obligations
3,503,626

 
3,764,540

 
3,521,989

 
3,689,892

 
 
 
 
 
 
 
 
Credit Facilities
200,000

 
200,009

 
297,051

 
301,312

 
 
 
 
 
 
 
 
Total consolidated debt obligations
3,703,626

 
$
3,964,549

 
3,819,040

 
$
3,991,204

Less current portion of long-term debt (2)
343,254

 
 

 
1,083

 
 

Less short-term debt
200,000

 
 

 
297,051

 
 

Total long-term debt
$
3,160,372

 
 

 
$
3,520,906

 
 

____________________
(1)
Effective November 1, 2011, the interest rate on the Junior Subordinated Notes changed to a variable rate based upon the three-month LIBOR rate plus 3.0175 percent, reset quarterly.  See Junior Subordinated Notes below for more information regarding the interest rate on these notes.
(2)
Excludes $455 million related to the 2012 Term Loan that was refinanced in February 2012 resulting in a change of the maturity date to February 2016.  See Retirement of Debt Obligations below for more information.
The fair value of the Company’s term loans and credit facilities as of December 31, 2011 and 2010 were determined using the market approach, which utilized reported recent loan transactions for parties of similar credit quality and remaining life, as there is no active secondary market for loans of these types and sizes.

F-23

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of the Company’s other long-term debt as of December 31, 2011 and 2010 was also determined using the market approach, which utilized observable market data to corroborate the estimated credit spreads and prices for the Company’s non-bank long-term debt securities in the secondary market.  Those valuations were based in part upon the reported trades of the Company’s non-bank long-term debt securities where available and the actual trades of debt securities of similar credit quality and remaining life where no secondary market trades were reported for the Company’s non-bank long-term debt securities. 
Long-Term Debt.  Southern Union has approximately $3.5 billion of long-term debt, including net premiums of $2.9 million, recorded at December 31, 2011, of which $343.3 million is current.  Debt of $2.83 billion is at fixed rates ranging from 3.63 percent to 9.44 percent.  Southern Union also has floating rate debt totaling $667.4 million, bearing an interest rate of 0.85 to 3.45 percent as of December 31, 2011.
As of December 31, 2011, the Company has scheduled long-term debt payments, excluding net premiums on debt, as follows:
 
 
2012
 
2013
 
2014
 
2015
 
2016
 
2017
and thereafter
 
 
(In thousands)
Southern Union Company
 
$
868

 
$
250,797

 
$
772

 
$
751

 
$
708

 
$
1,283,115

Panhandle
 
342,386

 
250,000

 
—

 
455,000

 
—

 
916,305

 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
343,254

 
$
500,797

 
$
772

 
$
455,751

 
$
708

 
$
2,199,420

Each note or bond is an obligation of Southern Union or a unit of Panhandle, as noted above.  Panhandle’s debt is non-recourse to Southern Union.  All debts that are listed as debt of Southern Union are direct obligations of Southern Union.  None of the Company’s long-term debt is cross-collateralized and most of its long-term debt obligations contain cross-default provisions.
Junior Subordinated Notes.  The Company has interest rate swap agreements that effectively fix the interest rate applicable to the floating rate on $525 million of the $600 million Junior Subordinated Notes due 2066 (Junior Subordinated Notes).  See Note 11 – Derivative Instruments and Hedging Activities – Interest Rate Contracts – Interest Rate Swaps for more information regarding these swap agreements.  The interest rate on the remaining notes is a variable rate based upon the three-month LIBOR rate plus 3.0175 percent.  The balance of the variable rate portion of the Junior Subordinated Notes was $75 million at an effective interest rate of 3.45 percent at December 31, 2011.  The balance and effective interest rate at February 17, 2012 were $75 million and 3.45 percent, respectively.
Term Loans.  On August 3, 2010, the Company entered into an Amended and Restated $250 million Credit Agreement, maturing on August 3, 2013 (2010 Term Loan).  The 2010 Term Loan bears interest at a rate of LIBOR plus 2.125 percent.  The balance of the 2010 Term Loan was $250 million and $250 million at effective interest rates of 2.40 percent and 2.39 percent at December 31, 2011 and 2010, respectively.  The balance and effective interest rate of the 2010 Term Loan at February 17, 2012 were $250 million and 2.38 percent, respectively.
On March 15, 2007, LNG Holdings, as borrower, and PEPL and Trunkline LNG, as guarantors, entered into a $455 million unsecured term loan facility due March 13, 2012 (2012 Term Loan). The interest rate under the 2012 Term Loan is a floating rate tied to LIBOR or the prime rate, at the Company’s option, in addition to a margin based on the rating of PEPL’s senior unsecured debt.  LNG Holdings has entered into interest rate swap agreements that effectively fix the interest rate applicable to the 2012 Term Loan at 4.98 percent plus a credit spread of 0.625 percent, based upon PEPL’s credit rating for its senior unsecured debt.  The balance of the 2012

F-24

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Term Loan was $455 million at December 31, 2011 and 2010.  See Note 11 – Derivative Instruments and Hedging Activities – Interest Rate Swaps for information regarding interest rate swaps.
On June 29, 2007, LNG Holdings, as borrower, and PEPL and CrossCountry Citrus, LLC, as guarantors, entered into an amended and restated $465 million term loan facility (Amended Credit Agreement) due June 29, 2012, with an interest rate of LIBOR plus 55 basis points, based upon the current credit rating of PEPL's senior unsecured debt.  The balance of the Amended Credit Agreement was $342.4 million and $360.4 million at effective interest rates of 0.85 and 0.81 percent at December 31, 2011 and 2010, respectively.  The balance and effective interest rate of the Amended Credit Agreement at February 17, 2012 were $342.4 million and 0.82 percent, respectively.
Credit Facilities.  During the second quarter of 2011, the Company entered into the Seventh Amended and Restated Revolving Credit Agreement with the banks named therein in the amount of $550 million (2011 Revolver).  The 2011 Revolver is an amendment, restatement and refinancing of the Company’s $550 million revolving credit facility, which was otherwise scheduled to mature on May 28, 2013.  The 2011 Revolver will mature on May 20, 2016.  Borrowings on the 2011 Revolver are available for the Company’s working capital, other general corporate purposes and letter of credit requirements.  The interest rate and commitment fee under the 2011 Revolver are calculated using a pricing grid, which is based upon the credit rating for the Company’s senior unsecured notes.  The annualized interest rate and commitment fee rate bases for the 2011 Revolver at December 31, 2011 were LIBOR, plus 162.5 basis points, and 25 basis points, respectively.
The Company’s additional $25 million short-term committed credit facility was renewed in July 2011 for an additional 364-day period.
Balances of $200 million and $297.1 million were outstanding under the Company’s credit facilities at effective interest rates of 1.88 and 3.02 percent at December 31, 2011 and 2010, respectively.  The Company classifies its borrowings under the credit facilities as short-term debt as the individual borrowings are generally for periods of 15 to 180 days.  At maturity, the Company may (i) retire the outstanding balance of each borrowing with available cash on hand and/or proceeds from a new borrowing, or (ii) at the Company’s option, extend the borrowing’s maturity date for up to an additional 90 days.  As of February 17, 2012, there was a balance of $148.3 million outstanding under the Company’s credit facilities at an average effective interest rate of 1.86 percent.
Restrictive Covenants.  The Company is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of the Company’s lending agreements.  Covenants exist in certain of the Company’s debt agreements that require the Company to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense.  A failure by the Company to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if the Company did not cure such default within any permitted cure period or if the Company did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
The Company’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Southern Union’s debt and other financial obligations and that of its subsidiaries. Under the current credit agreements, the significant debt covenants and cross defaults are as follows:
a) Under the Company’s 2011 Revolver, the consolidated debt to total capitalization ratio, as defined therein, cannot exceed 65 percent;
b) Under the Company’s 2011 Revolver, the Company must maintain an earnings before interest, tax, depreciation and amortization interest coverage ratio of at least 2.00 times;
c) Under the Company’s First Mortgage Bond indentures for the Fall River Gas division of New England Gas Company, the Company’s consolidated debt to total capitalization ratio, as defined therein, cannot exceed 70 percent at the end of any calendar quarter; and
d) All of the Company’s major borrowing agreements contain cross-defaults if the Company defaults on an agreement involving at least $10 million of principal.

F-25

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In addition to the above restrictions and default provisions, the Company and/or its subsidiaries are subject to a number of additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in the Company’s cash management program; and limitations on the Company’s ability to prepay debt.
Retirement of Debt Obligations.  The Company refinanced LNG Holdings’ $455 million term loan due March 13, 2012 on February 23, 2012 with an unsecured three-year term loan facility due February 23, 2015, with LNG Holdings as borrower and PEPL and Trunkline LNG as guarantors and a floating interest rate tied to LIBOR plus a margin based on the rating of PEPL’s senior unsecured debt.  The Company expects to retire the $465 million term loan due June 2012 ($342.4 million of which is outstanding at December 31, 2011) utilizing a portion of the $445 million in merger consideration to be received by Southern Union in connection with the Citrus Merger.  Should the Citrus Merger not occur by the June 2012 maturity date, the Company would expect to refinance and/or extend the $465 million term loan, or alternatively the Company might choose to retire such debt upon maturity by utilizing some combination of cash flows from operations, draw downs under existing credit facilities and altering the timing of controllable expenditures, among other things.  The Company reasonably believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital and debt markets and market expectations regarding the Company’s future earnings and cash flows, that it will be able to refinance and/or retire these obligations, as applicable, under acceptable terms prior to their maturity.  There can be no assurance, however, that the Company will be able to achieve acceptable refinancing terms in any negotiation of new capital market debt or bank financings.  Moreover, there can be no assurance the Company will be successful in its implementation of these refinancing and/or retirement plans and the Company’s inability to do so could cause a material adverse effect on the Company’s financial condition and liquidity.
9.  Benefits
Pension and Other Postretirement Benefit Plans
The Company has funded non-contributory defined benefit pension plans (pension plans) that cover substantially all Distribution segment employees.  Normal retirement age is 65, but certain plan provisions allow for earlier retirement.  Pension benefits are calculated under formulas principally based on average earnings and length of service for salaried and non-union employees and average earnings and length of service or negotiated non-wage based formulas for union employees.
The Company has postretirement health care and life insurance plans (other postretirement plans) that cover substantially all Distribution and Transportation and Storage segment employees and all Corporate employees.  The health care plans generally provide for cost sharing between the Company and its retirees in the form of retiree contributions, deductibles, coinsurance, and a fixed cost cap on the amount the Company pays annually to provide future retiree health care coverage under certain of these plans.

F-26

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Obligations and Funded Status
Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.  The following tables contain information at the dates indicated about the obligations and funded status of the Company’s pension and other postretirement plans on a combined basis.
 
 
Pension Benefits
December 31,
 
Other Postretirement Benefits
December 31,
 
 
2011
 
2010
 
2011
 
2010
 
 
(In thousands)
Change in benefit obligation:
 
 
 
 
 
 
 
 
Benefit obligation at beginning of period
 
$
193,686

 
$
177,235

 
$
109,768

 
$
98,055

Service cost
 
3,657

 
3,251

 
3,480

 
3,064

Interest cost
 
10,140

 
10,172

 
6,050

 
5,612

Benefits paid, net
 
(10,511
)
 
(10,546
)
 
(2,585
)
 
(3,224
)
Medicare Part D subsidy receipts
 
—

 
—

 
318

 
305

Actuarial loss and other
 
28,105

 
13,574

 
18,094

 
5,956

Benefit obligation at end of period
 
$
225,077

 
$
193,686

 
$
135,125

 
$
109,768

 
 
 
 
 
 
 
 
 
Change in plan assets:
 
 

 
 

 
 

 
 

Fair value of plan assets at beginning of period
 
$
127,000

 
$
115,863

 
$
102,146

 
$
68,903

Return on plan assets and other
 
(651
)
 
15,195

 
298

 
8,808

Employer contributions
 
16,957

 
6,488

 
10,363

 
27,659

Benefits paid, net
 
(10,511
)
 
(10,546
)
 
(2,585
)
 
(3,224
)
Fair value of plan assets at end of period
 
$
132,795

 
$
127,000

 
$
110,222

 
$
102,146

 
 
 
 
 
 
 
 
 
Amount underfunded at end of period
 
$
(92,282
)
 
$
(66,686
)
 
$
(24,903
)
 
$
(7,622
)
 
 
 
 
 
 
 
 
 
Amounts recognized in the Consolidated
 
 

 
 

 
 

 
 

Balance Sheet consist of:
 
 

 
 

 
 

 
 

Noncurrent assets
 
$
—

 
$
—

 
$
3,560

 
$
6,279

Current liabilities
 
(13
)
 
(13
)
 
(239
)
 
(170
)
Noncurrent liabilities
 
(92,269
)
 
(66,673
)
 
(28,224
)
 
(13,731
)
 
 
$
(92,282
)
 
$
(66,686
)
 
$
(24,903
)
 
$
(7,622
)
 
 
 
 
 
 
 
 
 
Amounts recognized in Accumulated other
 
 

 
 

 
 

 
 

comprehensive loss (pre-tax basis) consist of:
 
 

 
 

 
 

 
 

Net actuarial loss (gain)
 
$
82,790

 
$
51,365

 
$
24,723

 
$
(246
)
Prior service cost
 
1,964

 
2,551

 
2,885

 
1,074

 
 
$
84,754

 
$
53,916

 
$
27,608

 
$
828


F-27

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets.
 
 
Pension Benefits
December 31,
 
Other Postretirement Benefits
December 31,
 
 
2011
 
2010
 
2011
 
2010
 
 
(In thousands)
Projected benefit obligation
 
$
225,077

 
$
193,686

 
N/A

 
N/A

Accumulated benefit obligation
 
212,056

 
183,529

 
$
104,083

 
$
82,287

Fair value of plan assets
 
132,795

 
127,000

 
75,620

 
68,385

Net Periodic Benefit Cost
Net periodic benefit cost for the periods presented includes the components noted in the table below.
 
 
Pension Benefits
Years Ended December 31,
 
Other Postretirement Benefits
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
2011
 
2010
 
2009
 
 
(In thousands)
Net Periodic Benefit Cost:
 
 
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
3,657

 
$
3,251

 
$
2,778

 
$
3,480

 
$
3,064

 
$
2,970

Interest cost
 
10,140

 
10,172

 
9,955

 
6,050

 
5,612

 
5,481

Expected return on plan assets
 
(10,653
)
 
(9,348
)
 
(8,577
)
 
(5,820
)
 
(4,918
)
 
(3,123
)
Prior service cost (credit)
 
 

 
 

 
 

 
 

 
 

 
 

amortization
 
587

 
552

 
552

 
(1,811
)
 
(1,647
)
 
(1,260
)
Actuarial loss (gain)
 
 

 
 

 
 

 
 

 
 

 
 

amortization
 
7,985

 
8,048

 
8,405

 
(1,353
)
 
(1,862
)
 
(847
)
 
 
11,716

 
12,675

 
13,113

 
546

 
249

 
3,221

Regulatory adjustment (1)
 
868

 
(4
)
 
54

 
2,665

 
2,665

 
2,665

Net periodic benefit cost
 
$
12,584

 
$
12,671

 
$
13,167

 
$
3,211

 
$
2,914

 
$
5,886


________________________________
(1)
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.
The estimated net actuarial loss (gain) and prior service cost (credit) for pension plans that will be amortized from Accumulated other comprehensive loss into net periodic benefit cost during 2012 are $10.3 million and $580,000, respectively.  The estimated net actuarial loss (gain) and prior service cost (credit) for other postretirement plans that will be amortized from Accumulated other comprehensive loss into net periodic benefit cost during 2012 are $1.3 million and $(1.1) million, respectively.

F-28

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Assumptions
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below.
 
 
Pension Benefits
December 31,
 
Other Postretirement Benefits
December 31,
 
 
2011
 
2010
 
2011
 
2010
Discount rate
 
4.14
%
 
5.35
%
 
4.14
%
 
5.36
%
Rate of compensation increase
 
3.02
%
 
3.02
%
 
N/A

 
N/A

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below.
 
 
Pension Benefits
Years Ended December 31,
 
Other Postretirement Benefits
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
2011
 
2010
 
2009
Discount rate
 
5.35
%
 
5.82
%
 
6.05
%
 
5.36
%
 
5.85
%
 
6.05
%
Expected return on assets:
 
 

 
 

 
 

 
 

 
 

 
 

Tax exempt accounts
 
8.25
%
 
8.25
%
 
8.50
%
 
7.00
%
 
7.00
%
 
7.00
%
Taxable accounts
 
N/A

 
N/A

 
N/A

 
4.50
%
 
5.00
%
 
5.00
%
Rate of compensation increase
 
3.02
%
 
3.24
%
 
3.24
%
 
N/A

 
N/A

 
N/A

The Company employs a building block approach in determining the expected long-term rate of return on the plans’ assets, with proper consideration of diversification and rebalancing.  Historical markets are studied and long-term historical relationships between equities and fixed-income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run.  Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined.  Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.
The assumed health care cost trend rates used to measure the expected cost of benefits covered by the Company’s other postretirement benefit plans are shown in the table below.
 
 
December 31,
 
 
2011
 
2010
Health care cost trend rate assumed for next year
 
8.50
%
 
9.00
%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)
 
4.75
%
 
4.75
%
Year that the rate reaches the ultimate trend rate
 
2019

 
2019

Assumed health care cost trend rates have a significant effect on the amounts reported for healthcare plans.  A one-percentage-point change in assumed health care cost trend rates would have the following effects:
 
 
One Percentage
Point Increase
 
One Percentage
Point Decrease
 
 
(In thousands)
Effect on total of service and interest cost
 
$
878

 
$
(847
)
Effect on accumulated postretirement benefit obligation
 
11,809

 
(10,806
)

F-29

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Plan Assets
The Company’s overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification.  To achieve diversity within its pension plan asset portfolio, the Company has targeted the following asset allocations: equity of 25 percent to 70 percent, fixed income of 15 percent to 35 percent, alternative assets of 10 percent to 35 percent and cash of 0 percent to 10 percent.  To achieve diversity within its other postretirement plan asset portfolio, the Company has targeted the following asset allocations: equity of 25 percent to 35 percent, fixed income of 65 percent to 75 percent and cash and cash equivalents of 0 percent to 10 percent.  These target allocations are monitored by the Investment Committee of the Board in conjunction with an external investment advisor.  On occasion, the asset allocations may fluctuate as compared to these guidelines as a result of Investment Committee actions.
The fair value of the Company’s pension plan assets by asset category at the dates indicated is as follows:
 
 
Fair Value
as of
 
 
 
Fair Value Measurements at December 31, 2011
Using Fair Value Hierarchy
 
 
December 31, 2011
 
 
 
Level 1
 
Level 2
 
Level 3
 
 
(In thousands)
Asset Category:
 
 
 
 
 
 
 
 
 
 
Cash and cash
 
 
 
 
 
 
 
 
 
 
equivalents
 
$
11,791

 
 
 
$
11,791

 
$
—

 
$
—

Mutual fund
 
110,632

 
(1)
 
—

 
110,632

 
—

Multi-strategy
 
 

 
 
 
 

 
 

 
 

hedge funds
 
10,372

 
(2)
 
—

 
10,372

 
—

Total
 
$
132,795

 
 
 
$
11,791

 
$
121,004

 
$
—

 
 
Fair Value
as of
 
 
 
Fair Value Measurements at December 31, 2010
Using Fair Value Hierarchy
 
 
December 31, 2010
 
 
 
Level 1
 
Level 2
 
Level 3
 
 
(In thousands)
Asset Category:
 
 
 
 
 
 
 
 
 
 
Cash and cash
 
 
 
 
 
 
 
 
 
 
equivalents
 
$
4,901

 
 
 
$
4,901

 
$
—

 
$
—

Mutual fund
 
111,829

 
(1)
 
—

 
111,829

 
—

Multi-strategy
 
 

 
 
 
 

 
 

 
 

hedge funds
 
10,270

 
(2)
 
—

 
10,270

 
—

Total
 
$
127,000

 
 
 
$
4,901

 
$
122,099

 
$
—


___________________
(1)
This comingled fund invests primarily in a diversified portfolio of equity and fixed income funds.  As of December 31, 2011, the fund was primarily comprised of approximately 36 percent large-cap U.S. equities, 6 percent small-cap U.S. equities, 20 percent international equities, 30 percent fixed income securities, and 8 percent in other investments.  As of December 31, 2010, the fund was primarily comprised of approximately 38 percent large-cap U.S. equities, 8 percent small-cap U.S. equities, 20 percent international equities, 29 percent fixed income securities, and 5 percent in other investments.  These investments are generally redeemable on a daily basis at the net asset value per share of the investment.
(2)
Primarily includes hedge funds that invest in multiple strategies, including relative value, opportunistic/macro, long/short equities, merger arbitrage/event driven, credit, and short selling strategies, to generate long-term capital appreciation through a portfolio having a diversified risk profile with relatively low volatility and a low correlation with traditional equity and fixed-income markets.  These investments can generally be redeemed effective as of the last day of a calendar quarter at the net asset value per share of the investment with approximately 65 days prior written notice.

F-30

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of the Company’s other postretirement plan assets by asset category at the dates indicated is as follows:
 
Fair Value
as of
 
Fair Value Measurements at December 31, 2011
Using Fair Value Hierarchy
 
December 31, 2011
 
Level 1
 
Level 2
 
Level 3
 
(In thousands)
Asset Category:
 
 
 
 
 
 
 
Cash and Cash
 
 
 
 
 
 
 
Equivalents
$
2,476

 
$
2,476

 
$
—

 
$
—

Mutual fund
107,746

(1)
107,746

 
—

 
—

Total
$
110,222

 
$
110,222

 
$
—

 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value
 
Fair Value Measurements at December 31, 2010
 
as of
 
Using Fair Value Hierarchy
 
December 31, 2010
 
Level 1
 
Level 2
 
Level 3
 
 
 
 
 
 
 
 
 
(In thousands)
Asset Category:
 

 
 

 
 

 
 

Cash and Cash
 

 
 

 
 

 
 

Equivalents
$
2,303

 
$
2,303

 
$
—

 
$
—

Mutual fund
99,843

(1)
99,843

 
—

 
—

Total
$
102,146

 
$
102,146

 
$
—

 
$
—


___________________
(1)
This fund of funds primarily invests in a combination of equity, fixed income and short-term mutual funds.  As of December 31, 2011, the fund was primarily comprised of approximately 19 percent large-cap U.S. equities, 2 percent small-cap U.S. equities, 10 percent international equities, 55 percent fixed income securities, 8 percent cash, and 6 percent in other investments.  As of December 31, 2010, the fund was primarily comprised of approximately 17 percent large-cap U.S. equities, 4 percent small-cap U.S. equities, 10 percent international equities, 57 percent fixed income securities, 10 percent cash, and 2 percent in other investments.

F-31

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was determined by the Company to be calculated consistent with authoritative accounting guidelines.  See Note 2 – Summary of Significant Accounting Policies and Other Matters – Fair Value Measurements for information related to the framework used by the Company to measure the fair value of its pension and other postretirement plan assets.
Contributions
The Company expects to contribute approximately $16.8 million to its pension plans and approximately $10.9 million to its other postretirement plans in 2012.  The Company funds the cost of the plans in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.
Benefit Payments
The Company’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below.
Years
Pension Benefits
 
Other
Postretirement
Benefits
(Gross, Before Medicare Part D)
 
Other
Postretirement
Benefits
(Medicare Part D Subsidy Receipts)
 
 
 
 
 
(In thousands)
2012
$
11,703

 
$
4,798

 
$
584

2013
11,860

 
5,553

 
606

2014
12,328

 
6,422

 
712

2015
12,031

 
7,219

 
819

2016
12,075

 
7,960

 
958

2017
 
-
 
2021
64,869

 
48,348

 
6,532

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
Defined Contribution Plan
The Company sponsors a defined contribution savings plan (Savings Plan) that is available to all employees.  The Company provided maximum matching contributions based upon certain Savings Plan provisions during 2009 through 2011 ranging from 2 percent to 6.25 percent of the participant’s compensation paid into the Savings Plan.  Company con­tributions are 100 percent vested after five years of continuous service for all plans other than plans for Missouri Gas Energy union employees and employees of the Fall River operation, as to which contributions are 100 percent vested after six years of continuous service.  Company contribu­tions to the Savings Plan during the years ended December 31, 2011, 2010 and 2009 were $7.6 million, $7.4 million and $7 million, respectively.
In addition, the Company makes employer contributions to separate accounts, re­ferred to as Retirement Power Accounts, within the defined contribution plan.  The contribution amounts are determined as a percentage of compensation and range from 3.5 percent to 12 percent.  Company con­tributions are generally 100 percent vested after five years of continuous service.  Company contributions to Retirement Power Accounts during the years ended December 31, 2011, 2010 and 2009 were $8.1 million, $7.9 million and $7.9 million, respectively.

F-32

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10.  Taxes on Income
The following table provides a summary of the current and deferred components of income tax expense from continuing operations for the periods presented.
 
Years Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands)
Current:
 
 
 
 
 
Federal
$
4,637

 
$
1,963

 
$
(44,060
)
State
(4,395
)
 
(2,352
)
 
(5,250
)
 
242

 
(389
)
 
(49,310
)
Deferred:
 

 
 

 
 

Federal
95,972

 
93,330

 
108,956

State
7,566

 
14,088

 
12,254

 
103,538

 
107,418

 
121,210

Total federal and state income tax
 
 
 
 
 
expense from continuing operations
$
103,780

 
$
107,029

 
$
71,900

 
 
 
 
 
 
Effective tax rate
29
%
 
31
%
 
29
%
Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.  The table below summarizes the principal components of the Company’s deferred tax assets (liabilities) at the dates indicated.
 
December 31,
 
2011
 
2010
 
(In thousands)
Deferred income tax assets:
 
 
 
Alternative minimum tax credit
$
38,391

 
$
36,526

Other postretirement benefits
21,837

 
20,206

Pension benefits
32,495

 
23,491

Derivative financial instruments (interest rates)
32,057

 
13,571

Net operating loss
24,750

 
—

Other
34,566

 
39,245

Total deferred income tax assets
184,096

 
133,039

 
 
 
 
Deferred income tax liabilities:
 

 
 

Property, plant and equipment
(1,139,135
)
 
(1,032,473
)
Unconsolidated investments (Citrus)
(29,059
)
 
(19,177
)
Goodwill
(16,718
)
 
(16,952
)
Environmental reserve
(11,641
)
 
(9,374
)
Other
(19,268
)
 
(32,296
)
Total deferred income tax liabilities
(1,215,821
)
 
(1,110,272
)
Net deferred income tax liability
(1,031,725
)
 
(977,233
)
Less current income tax assets (liabilities)
13,152

 
36,630

Accumulated deferred income taxes
$
(1,044,877
)
 
$
(1,013,863
)

F-33

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company has federal net operating loss (NOL) carryforwards of $65 million, of which $15 million will expire in 2030 and $50 million in 2031.  The Company has state NOL carryforwards of $52 million, expiring between 2013 and 2031.
The differences between the Company’s EITR and the U.S. federal income tax statutory rate for the periods presented are as follows:
 
 
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(In thousands)
Computed statutory income tax expense at 35%
 
$
125,721

 
$
122,387

 
$
88,018

Changes in income taxes resulting from:
 
 

 
 

 
 

Earnings from unconsolidated investments related to
 
 
 
 
 
 
anticipated receipt of dividends
 
(27,317
)
 
(26,973
)
 
(20,300
)
State income taxes, net of federal income tax benefit
 
2,296

 
7,878

 
4,553

Other
 
3,080

 
3,737

 
(371
)
Actual income tax expense from continuing operations
 
$
103,780

 
$
107,029

 
$
71,900

Due to the anticipated increase in dividends from Citrus as a result of the Phase VIII Expansion, the Company expects the entire deferred income tax liability related to its investment in Citrus would be realized at the Company’s statutory income tax rate less the dividends received deduction.
A reconciliation of the changes in unrecognized tax benefits for the periods presented is as follows:
 
 
Years ended December 31,
 
 
2011
 
2010
 
2009
 
 
(In thousands)
Beginning of the year
 
$
15,837

 
$
12,864

 
$
7,210

 
 
 
 
 
 
 
Additions:
 
 

 
 

 
 

Tax positions taken in prior years
 
188

 
—

 
2,195

Tax positions taken in current year
 
3,354

 
3,146

 
3,459

Reductions:
 
 

 
 

 
 

Settlements
 
(791
)
 
(173
)
 
—

End of year
 
$
18,588

 
$
15,837

 
$
12,864

As of December 31, 2011, the Company has unrecognized tax benefits for capitalization policies and state filing positions of $2.3 million and $16.3 million, respectively. However, only the $16.3 million ($10.6 million, net of federal tax) unrecognized tax benefits for certain state filing positions would impact the Company’s EITR if recognized. The Company believes it is reasonably possible that its unrecognized tax benefits may be reduced by $3.3 million ($2.1 million, net of federal tax) within the next twelve months due to settlement of certain state filing positions.
The Company’s policy is to classify and accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense in its Consolidated Statement of Operations, which is consistent with the recognition of these items in prior reporting periods.
During 2011, the Company recognized interest and penalties of $726,000 ($709,000, net of tax). At December 31, 2011, the Company has interest and penalties accrued of $2.1 million ($1.8 million, net of tax).
The Company is no longer subject to U.S. federal, state or local examinations for the tax period ended December 31, 2004 and prior years, except June 30, 2004, to the extent of $1.3 million of refund claims.

F-34

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11.  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 and treasury rate locks 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 Sheet.
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 associated with the $600 million Junior Subordinated Notes due 2066 (Junior Subordinated Notes) 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 will pay interest on the Junior Subordinated Notes at the floating rate of three-month LIBOR plus a credit spread of 3.0175 percent 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 loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings.  As of December 31, 2011, the floating rate LIBOR-based portion of the interest payments commencing November 1, 2011 was exchanged for weighted average fixed rate interest payments of 3.63 percent.
The Company also has outstanding pay-fixed interest rate swaps with a total notional amount of $455 million applicable to the LNG Holdings $455 million term loan.  These interest rate swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings.
As of December 31, 2011, approximately $12.4 million of net after-tax losses in Accumulated other comprehensive loss related to these interest rate swaps is expected to be amortized into Interest expense during the next twelve months.  There was no swap ineffectiveness during the period ended December 31, 2011.  Any ineffective portion of the cash flow hedge would be reported in current-period earnings.
Treasury Rate Locks.  As of December 31, 2011, the Company had no outstanding treasury rate locks.  However, certain of its treasury rate locks that settled in prior periods are associated with interest payments on outstanding long-term debt.  These treasury rate locks are accounted for as cash flow hedges, with the effective portion of their settled value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings.  As of December 31, 2011, approximately $571,000 of net after-tax losses in Accumulated other comprehensive loss related to these treasury rate locks will be amortized into Interest expense during the next twelve months.

F-35

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 equity natural gas and NGL volumes resulting from movements in market commodity prices.
Natural Gas Price Swaps.  As of December 31, 2011, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 3,660,000 MMBtus for 2012.   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 loss and reclassified into Operating revenues in the same periods during which the forecasted natural gas sales impact earnings.  As of December 31, 2011, approximately $4 million of net after-tax gains in Accumulated other comprehensive loss related to these natural gas price swaps are expected to be amortized into Operating revenues during the next twelve months.  Any ineffective portion of the cash flow hedge is reported in current-period earnings.
NGL Price Swaps.  As of December 31, 2011, the Company had outstanding receive-fixed NGL price swaps with a total notional amount of 65,378,124 gallons (5,490,000 MMBtu equivalent basis) for 2012.   These NGL price swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in Accumulated other comprehensive loss and reclassified into Operating revenues in the same periods during which the forecasted NGL sales impact earnings.  As of December 31, 2011, approximately $4 million of net after-tax losses in Accumulated other comprehensive loss related to these NGL price swaps are expected to be amortized into Operating revenues during the next twelve months.  Any ineffective portion of the cash flow hedge is reported in current-period earnings.
Commodity Contracts - Distribution Segment
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 December 31, 2011, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 19,400,000 MMBtu and 5,560,000 MMBtu for 2012 and 2013, respectively.  These natural gas price swaps are accounted for as economic hedges, with changes in their fair value recorded to Deferred natural gas purchases.

F-36

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summary Financial Statement Information
The following table summarizes the fair value amounts of the Company’s derivative instruments and their location in the Consolidated Balance Sheet at the dates indicated.
 
 
Asset Derivatives (1)
 
Liability Derivatives (1)
 
 
December 31,
 
December 31,
Balance Sheet Location
 
2011
 
2010
 
2011
 
2010
 
 
(In thousands)
 
(In thousands)
Cash Flow Hedges:
 
 
 
 
 
 
 
 
Interest rate contracts
 
 
 
 
 
 
 
 
Derivative instruments-liabilities
 
$
—

 
$
—

 
$
19,936

 
$
19,694

Deferred credits
 
—

 
—

 
59,789

 
4,652

 
 
 
 
 
 
 
 
 
Commodity contracts - Gathering and Processing:
 
 

 
 

 
 

Natural gas price swaps
 
 

 
 

 
 

 
 

Prepayments and other assets
 
6,124

 
—

 
—

 
—

Derivative instruments-liabilities
 
—

 
16,459

 
—

 
—

NGL price swaps
 
 

 
 

 
 

 
 

Prepayments and other assets
 
—

 
—

 
1,996

 
—

Derivative instruments-liabilities
 
—

 
—

 
4,144

 
—

 
 
$
6,124

 
$
16,459

 
$
85,865

 
$
24,346

 
 
 
 
 
 
 
 
 
Economic Hedges:
 
 

 
 

 
 

 
 

Commodity contracts - Gathering and Processing:
 
 

 
 

 
 

 
 

NGL processing spread swaps
 
 

 
 

 
 

 
 

Derivative instruments-liabilities
 
$
—

 
$
—

 
$
—

 
$
29,057

Other derivative instruments
 
 

 
 

 
 

 
 

Prepayments and other assets
 
—

 
133

 
—

 
—

Derivative instruments-liabilities
 
—

 
—

 
50

 
—

 
 
 
 
 
 
 
 
 
Commodity contracts - Distribution:
 
 

 
 

 
 

 
 

Natural gas price swaps
 
 

 
 

 
 

 
 

Derivative instruments-liabilities
 
—

 
234

 
34,468

 
34,968

Deferred credits
 
3

 
105

 
5,643

 
2,806

 
 
$
3

 
$
472

 
$
40,161

 
$
66,831

 
 
 
 
 
 
 
 
 
Total
 
$
6,127

 
$
16,931

 
$
126,026

 
$
91,177


_____________
(1)
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 Sheet on a net basis and disclosed herein on a gross basis.

F-37

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the location and amount of derivative instrument gains and losses reported in the Company’s consolidated financial statements for the periods presented:
 
Years Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands)
Cash Flow Hedges:  (1)
 
 
 
 
 
Interest rate contracts:
 
 
 
 
 
Change in fair value - increase in Accumulated other comprehensive
 
 
 
 
 
loss, excluding tax expense effect of $27,589, $5,237 and $3,051, respectively
$
74,059

 
$
13,028

 
$
7,589

Reclassification of unrealized loss from Accumulated other
 

 
 

 
 

comprehensive loss - increase of Interest expense, excluding tax
 

 
 

 
 

expense effect of $(9,012), $(9,019) and $(8,222), respectively
(22,455
)
 
(22,483
)
 
(20,572
)
Commodity contracts - Gathering and Processing:
 

 
 

 
 

Change in fair value - decrease in Accumulated other comprehensive
 

 
 

 
 

loss, excluding tax expense effect of $(2,598), $(14,093) and $(3,773),
 

 
 

 
 

respectively
(7,208
)
 
(39,105
)
 
(10,469
)
Reclassification of unrealized gain from Accumulated other comprehensive
 

 
 

 
 

loss - increase of Operating revenues, excluding tax expense effect of $8,536,
 

 
 

 
 

$6,787 and $16,231, respectively
23,685

 
18,833

 
45,035

 
 
 
 
 
 
Economic Hedges:
 

 
 

 
 

Commodity contracts - Gathering and Processing:
 

 
 

 
 

Change in fair value of strategic hedges - (increase)/decrease in Operating revenues  (2)
29,855

 
31,154

 
88,799

Change in fair value of other hedges - (increase)/decrease in Operating revenues  
(96
)
 
283

 
(12
)
Commodity contracts - Distribution:
 

 
 

 
 

Change in fair value - increase/(decrease) in Deferred gas purchases
2,673

 
(6,166
)
 
(49,083
)

_________________
(1)
See Note 7 – Comprehensive Income (Loss) for additional related information.
(2)
Includes $29.1 million, $34.5 million and $59.7 million of the cash settlement impact for previously recognized unrealized losses in the years ended December 31, 2011 and 2010 and unrealized gains in the year ended December 31, 2009, respectively.  Additionally, includes nil, $18.6 million and $44.9 million of unrealized mark-to-market losses recorded in the years ended December 31, 2011, 2010 and 2009, respectively.
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.  The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net liability position at December 31, 2011 was $22.9 million.

F-38

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12.  Fair Value Measurement
The following tables set forth the Company’s assets and liabilities that are measured at fair value on a recurring basis at the dates indicated.
 
Fair Value
as of
 
Fair Value Measurements at December 31, 2011
Using Fair Value Hierarchy
 
December 31, 2011
 
Level 1
 
Level 2
 
Level 3
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Commodity derivatives
$
4,128

 
$
—

 
$
4,128

 
$
—

Long-term investments
962

 
962

 
—

 
—

Total
$
5,090

 
$
962

 
$
4,128

 
$
—

 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 

Commodity derivatives
$
44,302

 
$
—

 
$
44,302

 
$
—

Interest-rate swap derivatives
79,725

 
—

 
79,725

 
—

Total
$
124,027

 
$
—

 
$
124,027

 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value
 
Fair Value Measurements at December 31, 2010
 
as of
 
Using Fair Value Hierarchy
 
December 31, 2010
 
Level 1
 
Level 2
 
Level 3
 
 
 
 
 
 
 
 
 
(In thousands)
Assets:
 

 
 

 
 

 
 

Commodity derivatives
$
133

 
$
—

 
$
133

 
$
—

Long-term investments
937

 
937

 
—

 
—

Total
$
1,070

 
$
937

 
$
133

 
$
—

 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 

Commodity derivatives
$
50,033

 
$
—

 
$
50,033

 
$
—

Interest-rate swap derivatives
24,346

 
—

 
24,346

 
—

Total
$
74,379

 
$
—

 
$
74,379

 
$
—

The Company’s Level 1 instruments primarily consist of trading securities related to a non-qualified deferred compensation plan that are valued based on active market quotes.  The Company’s Level 2 instruments primarily include natural gas and NGL 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 December 31, 2011, 2010 or 2009.
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.


F-39

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13.  Property, Plant and Equipment
The following table provides a summary of property, plant and equipment at the dates indicated.
 
 
 
 
December 31,
 
 
Lives in Years (1)
 
2011  (2)
 
2010  (2)
 
 
 
 
(In thousands)
Regulated Operations:
 
 
 
 

 
 

Distribution plant
 
9-60

 
$
1,042,857

 
$
1,001,032

Gathering and processing plant
 
26

 
166,990

 
183,548

Transmission plant
 
5-46

 
2,321,009

 
2,239,762

General - LNG
 
5-40

 
1,118,791

 
1,117,418

Underground storage plant
 
5-46

 
321,920

 
314,744

General plant and other
 
3-50

 
304,385

 
283,737

Construction work in progress
 
 

 
48,268

 
52,800

 
 
 

 
5,324,220

 
5,193,041

Less accumulated depreciation and amortization
 
 

 
1,219,017

 
1,074,161

 
 
 

 
4,105,203

 
4,118,880

Non-regulated Operations:
 
 

 
 

 
 

Distribution plant
 
5-40

 
60,466

 
59,749

Gathering and processing plant
 
1-50

 
1,839,571

 
1,740,725

General plant and other
 
3-29

 
19,758

 
17,274

Construction work in progress
 
 

 
55,594

 
67,464

 
 
 

 
1,975,389

 
1,885,212

Less accumulated depreciation and amortization
 
 

 
354,256

 
299,633

 
 
 

 
1,621,133

 
1,585,579

Net property, plant and equipment
 
 

 
$
5,726,336

 
$
5,704,459


_________________
(1)
The composite weighted-average depreciation rates for the years ended December 31, 2011, 2010 and 2009 were 3.4 percent, 3.5 percent and 3.5 percent, respectively.
(2)
Includes capitalized computerized software cost totaling:
Unamortized computer software cost
 
$
140,397

 
$
131,182

Less accumulated amortization
 
89,258

 
79,637

Net capitalized computer software costs
 
$
51,139

 
$
51,545

Amortization expense of capitalized computer software costs for the years ended December 31, 2011, 2010 and 2009 was $10.7 million, $11.4 million and $13.1 million, respectively.  The estimated amortization expense of capitalized computer software costs for the next five years ending December 31 are as follows:  2012 -- $9.7 million; 2013 -- $8.4 million; 2014 -- $7.7 million; 2015 -- $6.6 million; and 2016 -- $4.9 million.  Computer software costs are amortized between one and fifteen years.
14.  Stock-Based Compensation
The fair value of each stock option and SAR award is estimated on the date of grant using a Black-Scholes option pricing model. The Company’s expected volatilities are based on historical volatility of the Company’s common stock.  To the extent that volatility of the Company’s common stock price increases in the future, the estimates of the fair value of stock options and SARs granted in the future could increase, thereby increasing stock-based compensation expense in future periods.  Additionally, the expected dividend yield is considered for each grant on the date of grant.  The Company’s uses the simplified method in determining the expected term of stock options and SARs granted, which results in the use of the average midpoint between vesting of the awards and their contractual term for such estimate.  The Company utilizes the simplified method primarily because it has experienced several acquisitions and divestitures during the contractual period for the current awards outstanding, resulting in a change in the employee mix and an acceleration of certain stock option and SAR exercise

F-40

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

activity.  Additionally, the Company has not experienced a full life cycle of exercise activity for employees associated with certain of its acquisitions.  Because of the impact of these significant structural changes in the Company’s business operations and the resulting variations in employee exercise activity, the historical patterns of such exercise activity is not believed to be indicative of future behavior.  In the future, as information regarding post-vesting termination becomes more accessible, the Company may change the method of deriving the expected term.  This change could impact the fair value of stock options and SARs granted in the future.  The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.
The following table represents the Black-Scholes estimated ranges under the Company’s plans for stock options and SARs awards granted in the periods presented:
 
Years ended December 31,
 
2011
 
2010
 
2009
Expected volatility
32.83% to 35.60%
 
32.79% to 34.98%
 
32.22% to 33.69%
Expected dividend yield
2.45%
 
2.45% to 2.47%
 
2.37% to 2.45%
Risk-free interest rate
1.58% to 2.41%
 
1.78% to 2.40%
 
2.34% to 2.72%
Expected life
4.75 to 6 years
 
4.75 to 6 years
 
4.75 to 6 years
Stock Options
The following table provides information on stock options granted, exercised, forfeited, outstanding and exercisable under the Third Amended and Restated 2003 Stock and Incentive Plan (Third Amended 2003 Plan) and the 1992 Long-Term Stock Incentive Plan (1992 Plan) for the periods presented:
 
Third Amended 2003 Plan
 
1992 Plan
 
Shares
Under
Option
 
Weighted-
Average
Exercise
Price
 
Shares
Under
Option
 
Weighted-
Average
Exercise
Price
 
 
 
 
 
 
 
 
Outstanding December 31, 2008
2,311,111

 
$
20.61

 
312,109

 
$
13.70

Granted
752,433

 
20.72

 
—

 
—

Exercised
(14,889
)
 
16.83

 
(263,090
)
 
13.52

Forfeited
(34,435
)
 
17.39

 
—

 
—

Outstanding December 31, 2009
3,014,220

 
$
20.69

 
49,019

 
$
14.65

Granted
684,635

 
24.90

 
—

 
—

Exercised
(91,044
)
 
19.48

 
(9,860
)
 
14.65

Forfeited
(10,940
)
 
25.60

 
—

 
—

Outstanding December 31, 2010
3,596,871

 
$
21.51

 
39,159

 
$
14.65

Granted
75,271

 
28.49

 
—

 
—

Exercised
(77,386
)
 
17.22

 
(29,188
)
 
14.65

Forfeited
(510
)
 
24.06

 
(9,971
)
 
14.65

Outstanding December 31, 2011
3,594,246

 
$
21.75

 
—

 
$
—

 
 
 
 
 
 
 
 
Exercisable December 31, 2009
1,229,447

 
$
20.70

 
49,019

 
$
14.65

Exercisable December 31, 2010
1,814,539

 
19.83

 
39,159

 
14.65

Exercisable December 31, 2011
2,478,000

 
19.86

 
—

 
—


F-41

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about stock options outstanding under the Third Amended 2003 Plan at December 31, 2011.
 
 
Options Outstanding
 
Options Exercisable
Range of Exercise Prices
 
Number of Options
 
Weighted-Average Remaining Contractual Life
 
Weighted-Average Exercise Price
 
Number of Options
 
Weighted-Average Exercise Price
Third Amended 2003 Plan:
 
 
 
 
 
 
 
 
 
 
12.55 - 15.00
 
792,934

 
6.96 years
 
$
12.55

 
792,934

 
$
12.55

15.01 - 20.00
 
205,573

 
4.78 years
 
16.90

 
205,573

 
16.90

20.01 - 25.00
 
1,726,790

 
7.00 years
 
23.28

 
1,127,284

 
23.04

25.01 - 28.49
 
868,949

 
6.47 years
 
28.23

 
352,209

 
27.85

 
 
3,594,246

 
6.73 years
 
$
21.75

 
2,478,000

 
$
19.86

Stock Appreciation Rights
The following table provides information on SARs granted, exercised, forfeited, outstanding and exercisable under the Third Amended 2003 Plan for the periods presented.
 
 
Third Amended 2003 Plan
 
 
SARs
 
Weighted-Average
Exercise Price
 
 
 
 
 
Outstanding December 31, 2008
 
1,200,552

 
$
18.02

Granted
 
417,647

 
21.64

Exercised
 
(50,174
)
 
12.55

Forfeited
 
(74,894
)
 
18.82

Outstanding December 31, 2009
 
1,493,131

 
$
19.18

Granted
 
376,795

 
24.67

Exercised
 
(47,322
)
 
12.64

Forfeited
 
(38,648
)
 
19.93

Outstanding December 31, 2010
 
1,783,956

 
$
20.50

Granted
 
4,276

 
28.10

Exercised
 
(77,477
)
 
15.33

Forfeited
 
(47,415
)
 
25.33

Outstanding December 31, 2011
 
1,663,340

 
$
20.63

 
 
 
 
 
Exercisable December 31, 2009
 
494,775

 
$
22.06

Exercisable December 31, 2010
 
900,965

 
20.53

Exercisable December 31, 2011
 
1,278,950

 
19.71

The SARs that have been awarded vest in equal installments on the first three anniversaries of the grant date.  Each SAR entitles the holder to shares of Southern Union’s common stock equal to the fair market value of Southern Union’s common stock on the applicable exercise date in excess of the grant date price for each SAR.

F-42

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about SARs outstanding under the Third Amended 2003 Plan at December 31, 2011.
 
 
SARs Outstanding
 
SARs Exercisable
Range of Exercise Prices
 
Number of SARs
 
Weighted-Average Remaining Contractual Life
 
Weighted-Average Exercise Price
 
Number of SARs
 
Weighted-Average Exercise Price
12.55 - 17.50
 
568,685

 
6.96 years
 
$
12.55

 
568,685

 
$
12.55

17.51 - 25.00
 
745,401

 
8.44 years
 
23.17

 
365,287

 
22.68

25.01 - 28.48
 
349,254

 
5.71 years
 
28.35

 
344,978

 
28.36

 
 
1,663,340

 
7.36 years
 
$
20.63

 
1,278,950

 
$
19.71

The weighted-average remaining contractual life of options and SARs outstanding under the Third Amended 2003 Plan at December 31, 2011 was 6.93 years.  The weighted-average remaining contractual life of options and SARs exercisable under the Third Amended 2003 Plan at December 31, 2011 was 6.56 years. The aggregate intrinsic value of total options and SARs outstanding and exercisable at December 31, 2011 was $108.9 million and $83.8 million, respectively.
As of December 31, 2011, there was $6.8 million of total unrecognized compensation cost related to non-vested stock options and SARs compensation arrangements granted under the stock option plans. That cost is expected to be recognized over a weighted-average contractual period of 1.56 years. The total fair value of options and SARs vested as of December 31, 2011 was $21.5 million. Compensation expense recognized related to stock options and SARs totaled $6.9 million ($4.4 million, net of tax), $6.3 million ($4 million, net of tax) and $5.4 million ($3.5 million, net of tax) for the years ended December 31, 2011, 2010 and 2009, respectively.  Cash received from the exercise of stock options was $1.8 million for the year ended December 31, 2011.
The intrinsic value of options and SARs exercised during the year ended December 31, 2011 was approximately $2.4 million.  The Company realized an additional tax benefit of approximately $487,000 for the excess amount of deductions related to stock options and SARs over the historical book compensation expense multiplied by the statutory tax rate in effect, which has been reported as an increase in financing cash flows in the Consolidated Statement of Cash Flows.
Restricted Stock Equity and Liability Units
The Company’s Third Amended 2003 Plan also provides for grants of restricted stock equity units, which are settled in shares of the Company’s common stock, and restricted stock liability units, which are settled in cash.  The restrictions associated with a grant of restricted stock equity units under the Third Amended 2003 Plan generally expire equally over a period of three years.  Restrictions on certain grants made to non-employee directors and senior executives of the Company expire over a shorter time period, in certain cases less than one year, and may be subject to accelerated expiration over a shorter term if certain criteria are met.  The restrictions associated with a grant of restricted stock liability units expire equally over a period of three years and are payable in cash at the vesting date.

F-43

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information on restricted stock equity awards granted, released and forfeited for the periods presented.
 
 
Number of
Restricted Stock
Equity Units
Outstanding
 
Weighted-Average
Grant Date
Fair Value
Restricted shares at December 31, 2008
 
363,185

 
$
18.94

Granted
 
165,567

 
20.24

Released
 
(146,990
)
 
19.90

Forfeited
 
(2,788
)
 
18.98

Restricted shares at December 31, 2009
 
378,974

 
$
19.14

Granted
 
111,457

 
23.71

Released
 
(148,218
)
 
17.63

Forfeited
 
(1,000
)
 
25.15

Restricted shares at December 31, 2010
 
341,213

 
$
21.27

Granted
 
7,000

 
28.04

Released
 
(162,362
)
 
17.96

Forfeited
 
—

 
—

Restricted shares at December 31, 2011
 
185,851

 
$
24.41

The following table provides information on restricted stock liability awards granted, released and forfeited for the periods presented.
 
 
Number of
Restricted Stock Liability
Units Outstanding
 
Weighted-Average
Grant Date
Fair Value
Restricted units at December 31, 2008
 
548,639

 
$
17.31

Granted
 
268,027

 
21.06

Released
 
(204,937
)
 
19.38

Forfeited
 
(48,079
)
 
16.87

Restricted units at December 31, 2009
 
563,650

 
$
18.38

Granted
 
175,043

 
24.67

Released
 
(237,219
)
 
18.82

Forfeited
 
(54,344
)
 
18.77

Restricted units at December 31, 2010
 
447,130

 
$
20.56

Granted
 
270,835

 
42.01

Released
 
(239,714
)
 
18.53

Forfeited
 
(17,394
)
 
18.86

Restricted units at December 31, 2011
 
460,857

 
$
34.29

As of December 31, 2011, there was $21.3 million of total unrecognized compensation cost related to non-expired, restricted stock equity units and restricted stock liability units compensation arrangements granted under the restricted stock plans. That cost is expected to be recognized over a weighted-average contractual period of 2.2  years. The total fair value of restricted stock equity and liability units that were released during the year ended December 31, 2011 was $12.9 million. Compensation expense recognized related to restricted stock equity and liability units totaled $13.8 million ($8.7 million, net of tax), $8.8 million ($5.5 million, net of tax) and $6.8 million ($4.3 million, net of tax) for the years ended December 31, 2011, 2010 and 2009, respectively.
The Company settled the restricted stock liability units released in 2011, 2010 and 2009 with cash payments of $10 million, $5.8 million and $4.4 million, respectively.

F-44

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

15.  Commitments and Contingencies
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.
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 PRPs.  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.
Gathering and Processing Segment
SUGS is responsible for environmental remediation at certain sites on its gathering and processing systems, resulting primarily from releases of hydrocarbons.  SUGS has a program to remediate such contamination.  The 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 and complexity.  The ultimate liability and total costs associated with these sites will depend upon many factors. These sites are generally managed in the normal course of business or operations.
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

F-45

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 PRPs 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 MADEP 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 $10.9 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 Sheet.
Environmental Remediation Liabilities
The table below reflects the amount of accrued liabilities recorded in the Consolidated Balance Sheet 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.
 
 
December 31,
 
 
2011
 
2010
 
 
(In thousands)
Current
 
$
9,353

 
$
10,648

Noncurrent
 
11,635

 
11,920

Total environmental liabilities
 
$
20,988

 
$
22,568

During the years ended December 31, 2011, 2010 and 2009, the Company had $3.2 million, $4.5 million and $12 million of expenditures related to environmental cleanup programs, respectively.
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.
East End Project.  The East End Project involved the installation of a total of approximately 31 miles of pipeline in and around Tuscola, Illinois, Montezuma, Indiana and Zionsville, Indiana.  Construction began in 2007 and was completed in the second quarter of 2008.  PEPL sought recovery of each contractor’s share of approximately $50 million of cost overruns from the construction contractor, an inspection contractor and the construction management contractor for improper welding, inspection and construction management of the East End Project.  Certain of the contractors filed counterclaims against PEPL for alleged underpayments of approximately $18 million.  PEPL settled with three defendants prior to trial in Harris County, Texas.  Trial began on May 16, 2011 and after the fourth week of trial a settlement was reached with the last defendant, Acuren.  The various settlements resulted in the Company receiving a total of approximately $16 million and $9 million for reimbursement of previously incurred legal expenses associated with the proceeding and project cost overruns, respectively.

F-46

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $18.5 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 current Vice Chairman, President and COO, 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 legal fees charged that were passed through the recovery mechanism and whether they would qualify for a lesser, 50 percent, level of recovery.  The Company has filed its answer.  The hearing officer has deferred hearing the Company’s motion to dismiss until the end of the proceedings.  The AG’s motion to be reimbursed costs by the Company of up to $150,000 was granted.  The Company believes it has complied with all applicable requirements of the MDPU 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.
Air Quality Control.  SUGS is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ.
Compliance Orders from the New Mexico Environmental Department
Since the first quarter of 2010, SUGS has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities.  The NMED has issued amended compliance orders (COs) and proposed penalties for alleged violations at Jal #4 in the amount of $518,720 and at Jal #3 in the amount of $5,507,583.  Hearings on the COs are scheduled for late April 2012.  SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations, including the installation of approximately $50 million of emission control equipment in the last nine years at these facilities.  The Company has recorded an accrued liability and will continue to assess its potential exposure to the allegations as the matter progresses.
Litigation Relating to the Merger with ETE
On June 21, 2011, a putative class action lawsuit captioned Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, was filed in the 333rd Judicial District Court of Harris County, Texas.  The petition named as defendants the members of the Southern Union Board, as well as Southern Union and ETE.  The plaintiff alleged that the defendants breached their fiduciary duties to Southern Union’s stockholders or aided and abetted breaches of fiduciary duties in connection with the Merger.  The petition alleged that the Merger involves an unfair price and an inadequate sales process and that defendants entered into the transaction to benefit themselves personally.  The petition sought injunctive relief, including an injunction of the Merger, attorneys’ and other fees and costs, indemnification and other relief.
Also on June 21, 2011, another putative class action lawsuit captioned Magda v. Southern Union Company, et al., Cause No. 2011-37134, was filed in the 11th Judicial District Court of Harris County, Texas.  The petition named as defendants the members of the Southern Union Board, Southern Union and ETE.  The plaintiff alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted those alleged breaches.  The petition alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders.  The petition sought injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.
On June 28, 2011 and August 19, 2011, amended petitions were filed in the Magda and Jaroslawicz actions, respectively, naming the same defendants and alleging that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted those alleged breaches of fiduciary duty.  The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders.  The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.  The two Texas cases have been consolidated with the following style: in re:  Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas.  On October 21, 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 (described below).

F-47

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On June 27, 2011, a putative class action lawsuit captioned Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS, was filed in the Delaware Court of Chancery.  The complaint named as defendants the members of the Southern Union Board, Southern Union and ETE.  The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger, and further claimed that ETE aided and abetted those alleged breaches.  The complaint alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that the directors should deem a competing proposal made by The Williams Companies, Inc.  (Williams) to be superior.  The complaint sought compensatory damages, injunctive relief, including an injunction of  the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.
On June 29 and 30, 2011, putative class action lawsuits captioned KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS, and LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS, respectively were filed in the Delaware Court of Chancery.  The complaints named as defendants the members of the Southern Union Board, Southern Union, ETE and Merger Sub.  The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that ETE aided and abetted those alleged breaches.  The complaints alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that the directors must give full consideration to the Williams proposal.  The complaints sought compensatory damages, injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.
On July 6, 2011, a putative class action lawsuit captioned Memo v. Southern Union Company, et al., C.A. No. 6639-CS, was filed in the Delaware Court of Chancery.  The complaint named as defendants the members of the Southern Union Board, Southern Union ETE and Merger Sub.  The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the amended Merger agreement and that Southern Union, ETE and Merger Sub aided and abetted those alleged breaches.  The complaint alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, and that the terms of the amended Merger agreement are preclusive.  The complaint sought injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.
On August 25, 2011, a consolidated amended complaint was filed in the Southeastern Pennsylvania Transportation Authority, KBC Asset Management NV, Memo and LBBW Asset Management Investment GmbH actions pending in the Delaware Court of Chancery naming the same defendants as the original complaints in those actions and alleging that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger, that ETE aided and abetted those alleged breaches of fiduciary duty, and that the provisions in Section 5.4 of the Second Amended Merger Agreement relating to Southern Union’s ability to accept a superior proposal is invalid under Delaware law.  The amended complaint alleges that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders.  The consolidated amended complaint seeks injunctive relief, including an injunction of  the Merger and an award of attorneys’ and other fees and costs, in addition to other relief.
On November 9, 2011, the attorneys for the plaintiffs in the aforementioned Texas and Delaware actions stated that they did not intend to pursue their efforts to enjoin the Merger.  Plaintiffs have indicated that they intend to pursue a claim for damages.  A trial has not yet been scheduled in any of these matters.
On November 28, 2011, a derivative lawsuit captioned W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, was filed in the 234th Judicial District Court of Harris County, Texas.  The petition stated that it was filed on behalf of ETP.  ETP was also named as a nominal defendant.  The petition also named as defendants Energy Transfer Partners, GP, L.P. (ETP GP), Energy Transfer Partners, LLC (ETP LLC), ETE and the Boards of Directors of ETP, ETP GP, and ETP LLC (collectively, the ETE Defendants).  The petition also named Southern Union as a defendant.  On January 6, 2012, the plaintiff in the Garrett Trust action filed an amended petition naming the same defendants.  In these petitions, the plaintiff alleges that the ETE Defendants breached their fiduciary and contractual duties in connection with the Citrus Merger and ETP’s divestiture of its propane assets to Amerigas Partners LP (the Amerigas Transaction).  The petition alleges that the Citrus Merger, among other things, involves an unfair price and an unfair process and that the Directors of ETP, ETP GP, and ETP LLC failed to adequately evaluate the transaction.  The petition also alleges that the Directors of ETP, ETP GP, and ETP LLC failed to, among other things, adequately evaluate the Amerigas Transaction.  The amended complaint alleges that these defendants entered into both transactions primarily to assist in ETE’s consummation of its merger with Southern Union and thereby primarily to benefit themselves personally.  The amended petition asserts claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the individual defendants, ETP GP, and ETP LLC.  The amended complaint asserts claims

F-48

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

against ETE and Southern Union for aiding and abetting the breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith, as well as tortious interference with contract.  The amended petition also asserts claims for declaratory judgment and conspiracy against all defendants.  The lawsuit seeks, among other things,  the following relief: (i) a declaration that the lawsuit is properly maintainable as a derivative action; (ii) a declaration that the Citrus Merger and Amerigas Transaction were unlawful and unenforceable because they involved breaches of fiduciary and contractual duties; (iii) a declaration that ETE and Southern Union aided and abetted the alleged breaches of fiduciary and contractual duties; (iv) a declaration that defendants conspired to, aided and abetted, and did breach fiduciary and contractual duties; (v) an order directing the individual defendants, ETP GP, and ETP LLC to exercise their fiduciary duties to obtain a transaction or transactions in the best interest of ETP’s unitholders; (vi) damages; and (vii) attorneys’ and other fees and costs.
The Company has not recorded an accrued liability and believes the allegations of all the foregoing actions related to the Merger with ETE lack merit and intends to contest them vigorously.
Litigation Concerning the Citrus Merger
CrossCountry Energy, LLC (CrossCountry), the Company subsidiary that indirectly owns 50 percent of the capital stock of Citrus and is a Principal under the Citrus Capital Stock Agreement (CSA), filed a complaint in the Delaware Court of Chancery against El Paso Citrus Holdings, Inc., the owner of the other 50 percent of the capital stock of Citrus, and its parent El Paso Corporation (collectively, El Paso), seeking a declaratory judgment that the Citrus Merger does not, as El Paso contends, trigger any provisions of the CSA which would require the Company to provide El Paso a right of first refusal concerning Citrus.  The complaint was filed by CrossCountry following an exchange of letters between El Paso and the Company regarding the terms of the CSA.  Following the filing of the declaratory judgment action, El Paso filed a third-party complaint against the Company, ETE, and ETP alleging, among other things, breach of the CSA.  El Paso is not currently seeking to enjoin the closing of the Citrus Merger, but rather seeks a rescission of the Citrus Merger after it is completed or, alternatively, damages.  Trial is currently set for April 2012.  The Company has not recorded an accrued liability and believes the allegations by El Paso lack merit and intends to contest them vigorously.
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 December 31, 2011 and 2010, the Company recorded litigation and other claim-related accrued liabilities of $28.3 million and $26.9 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
Retirement of Debt Obligations.  See Note 8 – Debt Obligations – Retirement of Debt Obligations for information related to the Company’s debt maturing in 2012 and Note 6 – Unconsolidated Investments – Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus – Retirement of Debt Obligations for information related to the Company’s commitment to potentially make additional sponsor loans to Citrus in the event repayment of certain Citrus debt obligations becomes necessary.
2008 Hurricane Damage.  In September 2008, Hurricanes Gustav and Ike came ashore on the Louisiana and Texas coasts.  Damage from the hurricanes affected the Company’s Transportation and Storage segment.  Offshore transportation facilities, including Sea Robin and Trunkline’s Terrebonne system, suffered damage to several platforms and gathering pipelines.  Sea Robin experienced reduced volumes until January 2010 when the remainder of the damaged facilities was placed back in service.
The capital replacement and retirement expenditure related to Hurricane Ike, which were substantially completed in 2011, totaled approximately $141 million.  Approximately $141 million, $134 million and $110 million of the capital replacement and retirement expenditures were incurred as of December 31, 2011, 2010 and 2009, respectively.  The Company anticipates reimbursement from OIL for a significant portion of the damages in excess of its $10 million deductible; however, the recoverable amount is subject to pro rata reduction to the extent that the level of total accepted claims from all insureds exceeds the carrier’s $750 million aggregate exposure limit.  OIL announced that it has reached the $750 million aggregate exposure limit and currently calculates its estimated payout amount at 70 percent or less based on estimated claim information it has

F-49

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

received.  OIL is currently making interim payouts at the rate of 50 percent of accepted claims.  As of December 31, 2011, OIL has paid a total of $64.7 million for claims submitted to date by the Company with respect to Hurricane Ike.  The final amount of any applicable pro rata reduction cannot be determined until OIL has received and assessed all claims.
Purchase Commitments.  At December 31, 2011, the Company had purchase commitments for natural gas transportation services, storage services and certain quantities of natural gas at a combination of fixed, variable
and market-based prices that have an aggregate value of approximately $608.6 million.  The Company’s purchase commitments may be extended over several years depending upon when the required quantity is purchased.  The Company has purchased natural gas tariffs in effect for all its utility service areas that provide for recovery of its purchased natural gas costs under defined methodologies and the Company believes that all costs incurred under such commitments will be recovered through its purchased natural gas tariffs.
Missouri Safety Program.  Pursuant to a 1989 MPSC order, Missouri Gas Energy is engaged in its service territories in the Missouri Safety Program.  This program includes replacement of Company and customer-owned natural gas service and yard lines, the movement and resetting of meters, the replacement of cast iron mains and the replacement and cathodic protection of bare steel mains.  In recognition of the significant capital expenditures associated with this safety program, the MPSC initially permitted the deferral and subsequent recovery through rates of depreciation expense, property taxes and associated carrying costs over a 10-year period.  On August 28, 2003, the State of Missouri passed certain statutes that provided Missouri Gas Energy the ability to adjust rates periodically to recover depreciation expense, property taxes and carrying costs associated with the Missouri Safety Program, as well as investments in public improvement projects.  The continuation of the Missouri Safety Program will result in significant levels of future capital expenditures.  The Company incurred capital expenditures of $13.8 million, $13.6 million and $14.4 million in 2011, 2010 and 2009, respectively, related to this program and estimates incurring approximately $94.8 million over the next 10 years, after which all service lines, representing about 33 percent of the annual safety program investment, will have been replaced.
Regulation and Rates. See Note 19 – Regulation and Rates 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.
Future Regulatory Compliance Commitments
SPCC Rules.  In 2008 and 2009, the EPA adopted amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements and streamlining requirements.  On November 10, 2011, the amendments to the SPCC rules went into effect.  The Company modified its programs, assets and operations in its Transportation and Storage and Gathering and Processing segments and is finalizing implementation in accordance with the provisions found in the rule.  Costs associated with these activities have not had a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.
Air Quality Control
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 ten tons per year of any one Hazardous Air Pollutant (HAP) or twenty-five tons per year of all HAPs) and engines less than 500 horsepower at Major Sources (sources that emit ten tons per year or more of any one HAP or twenty-five 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 seventy-five parts per billion (ppb) with compliance anticipated in 2013 to 2015.  In January 2010, the EPA proposed lowering the standard to sixty to seventy ppb in lieu of the seventy-five 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.

F-50

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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.
The KDHE set certain contingency measures as part of the agency’s ozone maintenance plan for the Kansas City area.  Previously, it was anticipated that these measures would be revised to conform to the requirements of the EPA ozone standard discussed above.  KDHE recently indicated that the Kansas City area will be designated as attainment for the ozone standard in 2012, and will not be pursuing any emissions reductions from PEPL’s operations unless there are changes in the future regarding the status of the Kansas City area.
Gathering and Processing Segment.  The Texas Commission on Environmental Quality recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more.  If this data demonstrates that any source or group of sources may cause or contribute to a violation of the National Ambient Air Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard.  This may potentially affect three SUGS recovery units in Texas.  It is unclear at this time how the NMED will address the sulfur dioxide standard.
16.  Stockholders’ Equity
Dividends.  The table below presents the amount of cash dividends declared and paid in the respective periods.
Stockholder
 
Date
 
Amount
 
Amount
Record Date
 
Paid
 
Per Share
 
Paid
 
 
 
 
 
 
(In thousands)
December 30, 2011
 
January 13, 2012
 
$
0.15

 
$
18,726

September 30, 2011
 
October 14, 2011
 
0.15

 
18,712

June 24, 2011
 
July 8, 2011
 
0.15

 
18,709

March 25, 2011
 
April 8, 2011
 
0.15

 
18,700

December 31, 2010
 
January 14, 2011
 
$
0.15

 
$
18,690

September 24, 2010
 
October 8, 2010
 
0.15

 
18,674

June 25, 2010
 
July 9, 2010
 
0.15

 
18,672

March 26, 2010
 
April 9, 2010
 
0.15

 
18,665

December 25, 2009
 
January 8, 2010
 
$
0.15

 
$
18,657

September 25, 2009
 
October 9, 2009
 
0.15

 
18,610

June 26, 2009
 
July 10, 2009
 
0.15

 
18,607

March 27, 2009
 
April 10, 2009
 
0.15

 
18,607

Under the terms of the indenture governing its Senior Notes, Southern Union may not declare or pay any cash or asset dividends on its common stock (other than dividends and distributions payable solely in shares of its common stock or in rights to acquire its common stock) or acquire or retire any shares of its common stock, unless no event of default exists and certain financial ratio requirements are satisfied.  Currently, the Company is
in compliance with these requirements and, therefore, the Senior Notes indenture does not prohibit the Company from paying cash dividends.

F-51

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock Award Plans.  The Third Amended 2003 Plan allows for awards in the form of stock options (either incentive stock options or non-qualified options), SARs, stock bonus awards, restricted stock, performance units or other equity-based rights.  The persons eligible to receive awards under the Third Amended 2003 Plan include all of the employees, directors, officers and agents of, and other service providers to, the Company and its affiliates and subsidiaries.  Under the Third Amended 2003 Plan: (i) no participant may receive in any calendar year awards covering more than 500,000 shares; (ii) the exercise price for a stock option may not be less than 100 percent of the fair market value of the common stock on the date of grant; and (iii) no award may be granted after September 28, 2013.
The Company maintained its 1992 Plan, under which options to purchase 8,491,540 shares of its common stock were authorized to be granted until July 1, 2002 to officers and key employees.  Options granted under the 1992 Plan were exercisable for ten years from the date of grant or such lesser period as designated for particular options, and became exercisable after a specified period of time from the date of grant in cumulative annual installments.  All awards granted under the Company’s 1992 plan were expired as of December 31, 2011.
For more information on stock-based awards, see Note 14 – Stock-Based Compensation.
17.  Preferred Securities
On October 8, 2003, the Company issued 9,200,000 depositary shares, each representing a 1/10th interest in a share of its Preferred Stock at the public offering price of $25 per share, or $230 million in the aggregate.
On July 30, 2010, the Company redeemed the remaining approximately 460,000 shares of outstanding Preferred Stock at $25 per share, which totaled $115 million.  The Company recognized a $3.3 million non-cash loss adjustment charged to Retained earnings related to the write-off of issuance costs that reduced Net earnings available for common stockholders.
18.  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.  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 – Corporate Structure for additional information associated with the Company’s reportable segments.
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 evaluates operational and financial segment performance based on several factors, of which the primary financial measure is EBIT, a non-GAAP measure.  The Company defines EBIT as Net earnings available for common stockholders, adjusted for the following:
•
items that do not impact net earnings, such as extraordinary items, discontinued operations and the impact of changes in accounting principles;
•
income taxes;
•
interest;
•
dividends on preferred stock; and
•
loss on extinguishment of preferred stock.
EBIT 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.
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 years ended December 31, 2011, 2010 and 2009.
The following tables set forth certain selected financial information for the Company’s segments for the periods presented or at the dates indicated.

F-52

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 
 
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(In thousands)
Operating revenues from external customers:
 
 
 
 
 
 
Transportation and Storage
 
$
803,650

 
$
769,450

 
$
749,161

Gathering and Processing
 
1,179,680

 
1,008,023

 
732,251

Distribution
 
666,650

 
698,513

 
692,904

Total segment operating revenues
 
2,649,980

 
2,475,986

 
2,174,316

Corporate and other activities
 
15,974

 
13,927

 
4,702

 
 
$
2,665,954

 
$
2,489,913

 
$
2,179,018

Depreciation and amortization:
 
 

 
 

 
 

Transportation and Storage
 
$
128,011

 
$
123,009

 
$
113,648

Gathering and Processing
 
72,756

 
70,056

 
66,690

Distribution
 
33,445

 
32,544

 
31,269

Total segment depreciation and amortization
 
234,212

 
225,609

 
211,607

Corporate and other activities
 
3,478

 
3,028

 
2,220

 
 
$
237,690

 
$
228,637

 
$
213,827

Earnings (loss) from unconsolidated investments:
 
 

 
 

 
 

Transportation and Storage
 
$
97,775

 
$
99,991

 
$
75,205

Gathering and Processing
 
(248
)
 
4,145

 
4,410

Corporate and other activities
 
1,408

 
1,279

 
1,175

 
 
$
98,935

 
$
105,415

 
$
80,790

Other income (expense), net:
 
 

 
 

 
 

Transportation and Storage
 
$
603

 
$
(87
)
 
$
1,657

Gathering and Processing
 
138

 
362

 
(84
)
Distribution
 
41

 
(307
)
 
7,447

Total segment other income (expense), net
 
782

 
(32
)
 
9,020

Corporate and other activities
 
861

 
344

 
12,381

 
 
$
1,643

 
$
312

 
$
21,401


F-53

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 
 
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(In thousands)
Segment performance:
 
 
 
 
 
 
Transportation and Storage EBIT
 
$
480,775

 
$
458,273

 
$
411,935

Gathering and Processing EBIT
 
50,666

 
41,756

 
(40,470
)
Distribution EBIT
 
55,364

 
63,692

 
67,302

Total segment EBIT
 
586,805

 
563,721

 
438,767

Corporate and other activities
 
(8,369
)
 
2,621

 
9,513

Interest expense
 
219,232

 
216,665

 
196,800

Federal and state income taxes
 
103,780

 
107,029

 
71,900

Loss from discontinued operations
 
—

 
18,100

 
—

Net earnings
 
255,424

 
224,548

 
179,580

Preferred stock dividends
 
—

 
5,040

 
8,683

Loss on extinguishment of preferred stock
 
—

 
3,295

 
—

Net earnings available for common stockholders
 
$
255,424

 
$
216,213

 
$
170,897

 
 
 
 
 
 
 
 
 
December 31,
 
 
 
 
2011
 
2010
 
 
 
 
(In thousands)
 
 
Total assets:
 
 
 
 
 
 
Transportation and Storage
 
$
5,288,967

 
$
5,224,992

 
 
Gathering and Processing
 
1,742,516

 
1,700,598

 
 
Distribution
 
1,075,253

 
1,135,352

 
 
Total segment assets
 
8,106,736

 
8,060,942

 
 
Corporate and other activities
 
164,123

 
177,601

 
 
Total assets
 
$
8,270,859

 
$
8,238,543

 
 
 
 
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(In thousands)
Expenditures for long-lived assets:
 
 
 
 
 
 
Transportation and Storage
 
$
101,852

 
$
145,674

 
$
247,097

Gathering and Processing
 
113,864

 
95,577

 
70,221

Distribution
 
50,780

 
41,484

 
46,090

Total segment expenditures for long-lived assets
 
266,496

 
282,735

 
363,408

Corporate and other activities
 
2,491

 
4,690

 
30,141

Total expenditures for long-lived assets (1)
 
$
268,987

 
$
287,425

 
$
393,549


_______________________
(1)
­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­ Related cash impact includes the net reduction in capital accruals totaling $23 million, $9.5 million and $22 million for the years ended December 31, 2011, 2010 and 2009, respectively.

F-54

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Significant Customers and Credit Risk.  The following tables provide summary information of significant customers for Panhandle and SUGS by applicable segment and on a consolidated basis for the periods presented.  The Distribution segment has no single customer, or group of customers under common control, that accounted for ten percent or more of the Company’s Distribution segment or consolidated operating revenues for the periods presented.
 
 
Percent of Transportation and
Storage Segment Revenues
Years Ended December 31,
 
Percent of Consolidated
Company Total Operating Revenues
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
2011
 
2010
 
2009
BG LNG Services
 
30
%
 
29
%
 
22
%
 
9
%
 
9
%
 
8
%
ProLiance
 
13

 
13

 
13

 
4

 
4

 
4

Other top 10 customers
 
21

 
23

 
26

 
6

 
7

 
9

Remaining customers
 
36

 
35

 
39

 
10

 
11

 
13

Total percentage
 
100
%
 
100
%
 
100
%
 
29
%
 
31
%
 
34
%
 
 
Percent of Gathering and
 
Percent of Consolidated
 
 
Processing Segment Revenues
 
Company Total Operating Revenues
 
 
Years Ended December 31,
 
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
2011
 
2010
 
2009
ConocoPhillips Company (1)
 
62
%
 
54
%
 
7
%
 
27
%
 
22
%
 
2
%
Lone Star NGL Product Services, LLC
 
12

 
12

 
12

 
5

 
5

 
4

Other top 10 customers
 
20

 
24

 
48

 
9

 
10

 
17

Remaining customers
 
6

 
10

 
33

 
3

 
5

 
12

Total percentage
 
100
%
 
100
%
 
100
%
 
44
%
 
42
%
 
35
%

_____________
(1)
For the five-year period ending December 31, 2014, SUGS has contracted to sell its entire owned or controlled output of NGL to Conoco Phillips Company (Conoco).  Pricing for the NGL equity volumes sold to Conoco throughout the contract period will be OPIS pricing based at Mont Belvieu, Texas delivery points.  SUGS has an option to extend the sales agreement for an additional five-year period.
19.  Regulation and Rates
Panhandle.  Trunkline LNG commenced construction of an enhancement at its LNG terminal in February 2007.  The key components of the enhancement are an ambient air vaporizer system and NGL recovery units.  On March 11, 2010, Trunkline LNG received approval from FERC to place the infrastructure enhancement construction project in service.  Total construction costs were approximately $440 million plus capitalized interest, which includes additional costs incurred during final commissioning.  The negotiated rate with the project’s customer, BG LNG Services, has been adjusted based on final capital costs pursuant to a contract-based formula.  In addition, Trunkline LNG and BG LNG Services have extended the existing terminal and pipeline services agreements to coincide with the infrastructure enhancement construction project contract, which runs 20 years from the in-service date.
On August 31, 2009, Sea Robin filed with FERC to implement a rate surcharge to recover Hurricane Ike-related costs not otherwise recovered from insurance proceeds or from other third parties.  The surcharge is primarily related to recovery of property, plant and equipment costs.  On September 30, 2009, FERC approved the surcharge to be effective March 1, 2010, subject to refund and the outcome of hearings with FERC to explore issues set forth in certain customer protests, including the costs to be included and the applicability of the surcharge to discounted contracts.  The Administrative Law Judge (ALJ) issued an initial decision on December 13, 2010, approving the surcharge for recovery from all shippers, including discounted and non-discounted shippers, over a recovery period of 21.4 years and including applicable carrying charges.  The Company, as well as other parties, filed briefs for exception on certain aspects of the decision.  On December 15, 2011, FERC issued an order changing the 21.4 year recovery period to a four-year recovery period and held that the commencement of carrying charges should begin the later of August 31, 2009 and the date the associated cost is incurred.  FERC also determined that Sea Robin’s discount agreements with certain shippers permit it to recover the surcharge from those shippers.

F-55

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In December 2011, Sea Robin reversed all outstanding reserves for refund associated with the surcharge filing, approximately $17.7 million of which had been reserved as of September 30, 2011.  As of December 31, 2011, Sea Robin has incurred approximately $44 million of costs remaining to be recovered via the surcharge, including carrying charges and net of insurance and surcharge recoveries to date.
In October 2011, Trunkline and Sea Robin jointly filed with FERC to transfer all of Trunkline’s offshore facilities, and certain related onshore facilities, by abandonment and sale to Sea Robin to consolidate and streamline the ownership and operation of all regulated offshore assets under one entity and better position the offshore assets competitively.  Several parties have filed interventions and protests of this filing.  The Company is responding to information requests from FERC on this filing.  The transfer is subject to approval by FERC. 
In November 2011, FERC commenced an audit of PEPL to evaluate its compliance with the Uniform System of Accounts as prescribed by FERC, annual and quarterly financial reporting to FERC, reservation charge crediting policy and record retention.  The audit is related to the period from January 1, 2010 to present and is estimated to take approximately one year to complete.
On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule defines as HCAs. This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The rule requires operators to identify HCAs along their pipelines and to complete baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessment, by December 2012. Operators were required to rank the risk of their pipeline segments containing HCAs; assessments are generally conducted on the higher risk segments first.  In addition, some system modifications will be necessary to accommodate the in-line inspections. As of December 31, 2011, Panhandle had completed approximately 93 percent of the baseline risk assessments required to be completed by December 2012. While identification and location of all the HCAs has been completed, it is not practicable to determine with certainty the total scope of required remediation activities prior to completion of the assessments and inspections. The required modifications and inspections are currently estimated to be in the range of approximately $20 million to $30 million per year through 2012.
Missouri Gas Energy.  On July 13, 2011, a joint application was filed by Southern Union, Merger Sub and ETE requesting that the MPSC authorize Southern Union to take certain actions to allow ETE to acquire the equity interests of Southern Union.  The parties filed an amended application on September 15, 2011.  On February 16, 2012, the parties filed with the MPSC a Stipulation among Southern Union, ETE and the MPSC Staff.  Pursuant to the Stipulation, the parties recommend that the MPSC issue an order finding that, subject to the conditions therein, the merger of Merger Sub with and into Southern Union is not detrimental to the public interest and authorizing the undertaking of the Merger and related transactions.  The Office of Public Counsel has indicated that it does not oppose the Stipulation.  Southern Union and ETE have requested that the MPSC consider the Stipulation expeditiously.  For additional related information, see Note 3 – ETE Merger.
On June 10, 2011, Missouri Gas Energy filed an application with the MPSC requesting authority to defer the financial impact of the tornado that struck Joplin, Missouri on May 22, 2011, on the grounds that the tornado constituted a material, extraordinary and non-recurring event with respect to Missouri Gas Energy’s operations.  On January 25, 2012, the MPSC issued its Report and Order in which it granted Missouri Gas Energy’s request to defer as a regulatory asset for consideration of recovery in a future rate proceeding the incremental costs occasioned by the tornado but denied Missouri Gas Energy’s request to defer as a regulatory asset for consideration of recovery in a future rate proceeding the lost fixed cost recovery occasioned by the tornado.

F-56

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On April 2, 2009, Missouri Gas Energy made a filing with the MPSC seeking to implement an annual base rate increase of approximately $32.4 million.  On February 10, 2010, the MPSC issued its Report and Order in this case, authorizing a revenue increase of $16.2 million and approving distribution rate structures for Missouri Gas Energy’s residential and small general service customers (which comprised approximately 99 percent of its total customers and approximately 91 percent of its net operating revenues at the time the rates went into effect) that eliminate the impact of weather and conservation for residential and small general service margin revenues and related earnings in Missouri.  The new rates became effective February 28, 2010.  Judicial review of the MPSC’s Report and Order is being sought by the Office of the Public Counsel, with respect to rate structure issues, and by Missouri Gas Energy, with respect to cost of capital issues.  Those judicial review proceedings are expected to be completed in 2012, and the results of such proceedings are not expected to have a material adverse impact on the Company’s consolidated financial position, results of operations or cash flows.
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 percent of the amount by which its 2007 earnings fell below a return on equity of 7 percent.  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, 2009, New England Gas Company made a similar filing with the MDPU, also pursuant to the above-referenced settlement, to recover approximately $1.7 million, representing 50 percent of the amount by which its 2008 earnings deficiency fell below a return on equity of 7 percent.  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 $4.1 million is the appropriate ESA amount for recovery related to calendar year 2007 and that such amount should be recovered over a 12-month period beginning November 1, 2011; and (ii) investigate New England Gas Company’s request for recovery of an ESA amount of $1.7 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.  The 2008 ESA is awaiting further action by the MDPU.
On May 13, 2011, the independent auditor selected by the MDPU submitted the final audit report pertaining to 2007 cost of service information as ordered by the MDPU in connection with New England Gas Company’s 2008 base rate proceeding.  On December 15, 2011, the MDPU issued its order accepting the audit report and closing the docket with no further action.
20.  Leases
The Company leases certain facilities, equipment and office space under cancelable and non-cancelable operating leases.  The minimum annual rentals under operating leases for the next five years ending December 31 are as follows: 2012—$15.2 million; 2013— $17.3 million; 2014—$15.6 million; 2015— $14.3 million; 2016—$13.4 million; and $59 million in total thereafter.  Rental expense was $20.9 million, $20.1 million and $22.7 million for the years ended December 31, 2011, 2010 and 2009, respectively.
21.  Asset Retirement Obligations
The Company’s recorded asset retirement obligations are primarily related to owned natural gas storage wells and offshore lines and platforms.  At the end of the useful life of these underlying assets, the Company is legally or contractually required to abandon in place or remove the asset. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated.   Although a number of other onshore assets in the Company’s system are subject to agreements or regulations that give rise to an ARO upon the Company’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. 

F-57

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  The Company has in place a rigorous repair and maintenance program that keeps the pipeline and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipeline and the natural gas gathering and processing systems themselves will remain intact indefinitely.
The following table is a general description of ARO and associated long-lived assets at December 31, 2011.
 
In Service
 
 
ARO Description
Date
Long-Lived Assets
Amount
 
 
 
(In thousands)
 
 
 
 
Retire natural gas storage wells
Various
Natural gas storage wells
$
517

Retire offshore platforms and lines
Various
Offshore lines
$
3,180

Other
Various
Mainlines, compressors and gathering plants
$
4,941

As of December 31, 2011, the Company had no legally restricted funds for the purpose of settling AROs.
The following table is a reconciliation of the carrying amount of the ARO liability for the periods presented.  Changes in assumptions regarding the timing, amount, and probabilities associated with the expected cash flows, as well as the difference in actual versus estimated costs, will result in a change in the amount of the liability recognized.
 
 
Years Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(In thousands)
Beginning balance
 
$
61,280

 
$
61,667

 
$
51,641

Incurred
 
1,162

 
29,872

 
10,770

Revisions
 
(412
)
 
(11,395
)
 
(3,246
)
Settled
 
(16,836
)
 
(19,858
)
 
(1,557
)
Accretion expense
 
384

 
994

 
4,059

Ending balance
 
$
45,578

 
$
61,280

 
$
61,667

In 2010, additional AROs of $28.6 million were established primarily for  the Company’s offshore assets.  During 2010, the Company largely completed its assessment and repairs of the property damaged by Hurricane Ike in 2008, which resulted in accelerated abandonments of such property, and determined that the estimated third party abandonment costs for all of its offshore property needed to be increased.  Also in 2010, the Company recorded an $11.4 million downward revision to its prior ARO liability estimates, primarily for the costs of abandoning certain other specific offshore properties as a result of favorable weather conditions, changes in equipment used, and some changes in scope of the respective projects, which were primarily related to abandonments required as a results of permanent damage from Hurricane Ike.  The ARO liability associated with Hurricane Ike was further reduced by settlements of $19.7 million.  Such revisions and settlements were primarily associated with AROs of $8.3 million and $33.8 million recorded in 2009 and 2008, respectively, associated with damage caused by Hurricane Ike.  During 2011, the Company recorded settlements of approximately $16.6 million, primarily associated with the abandonment of certain offshore properties damaged by Hurricane Ike.  See Note 15 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage for additional related information.

F-58

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

22.  Other Income and Expense Items
Other, net income for the year ended December 31, 2009 totaling $21.4 million consists primarily of $20.3 million of settlements with insurance companies related to certain environmental matters and collection of a $1.9 million settlement amount awarded to the Company related to the Southwest Gas litigation action filed by the Company in 2002 against former Arizona Corporation Commissioner James Irvin.  These contingent gains were recognized in 2009 when the related settlement awards were received.
23.  Discontinued Operations
In October 2004, New England Gas Company discovered that one of its facilities, formerly associated with discontinued operations 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 RCRA and notification requirements under the federal 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. The payment of the fine and community service amounts were stayed while the Company pursued an appeal.
On December 22, 2010, a United States Court of Appeals for the First Circuit (First Circuit) panel affirmed the conviction and the sentence. On February 17, 2011, the First Circuit denied the Company’s petition for en banc rehearing.  With regard to the sentence, the First Circuit panel ruled that although the jury’s verdict was necessarily limited to a single day’s violation of RCRA (carrying a maximum fine of $50,000), the trial judge was nevertheless authorized for sentencing purposes independently to find the number of days the Company purportedly violated RCRA.  In its decision, the Panel noted that the sentencing issue as applied to criminal fines was a novel one in the First Circuit and that, if the First Circuit panel's application of judicial precedents is incorrect, it would not be harmless error to the Company and the case must be remanded to the District Court for resentencing.
The Company thereafter filed a petition for a writ of certiorari review of the sentence by the United States Supreme Court (Supreme Court) in which the Company argued that the sentence, which went beyond the fine authorized by the jury’s verdict, violated the Company’s jury trial rights under the Fifth and Sixth Amendments, and was contrary to Supreme Court precedent.  The Supreme Court granted the Company’s petition, and briefing of the Company’s appeal is now in process.  The Supreme Court will hear oral argument on the Company’s appeal on March 19, 2012.
In light of the First Circuit's decisions, the Company recorded a charge to earnings of approximately $18.1 million in 2010 and reported such charge as Loss from discontinued operations in the Consolidated Statement of Operations. The earnings charge is nondeductible for federal and state income tax purposes.

F-59

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

24.  Quarterly Operations (Unaudited)
The following table presents the operating results for each quarter of the year ended December 31, 2011.
 
 
Quarters Ended
 
 
March 31
 
June 30
 
September 30
 
December 31
 
 
(In thousands, except per share amounts)
Operating revenues
 
$
746,822

 
$
631,607

 
$
617,211

 
$
670,314

Operating income
 
108,032

 
115,022

 
110,526

 
144,278

Net earnings
 
60,662

 
59,773

 
58,032

 
76,957

Net earnings available for common
 
 

 
 

 
 

 
 

stockholders
 
60,662

 
59,773

 
58,032

 
76,957

Basic earnings per share:
 
$
0.49

 
$
0.48

 
$
0.47

 
$
0.62

Dilutive earnings per share:
 
$
0.48

 
$
0.47

 
$
0.46

 
$
0.61

The following table presents the operating results for each quarter of the year ended December 31, 2010.
 
 
Quarters Ended
 
 
March 31
 
June 30
 
September 30
 
December 31
 
 
(In thousands, except per share amounts)
Operating revenues
 
$
758,994

 
$
573,096

 
$
487,527

 
$
670,296

Operating income
 
119,278

 
131,744

 
76,407

 
133,186

Net earnings from continuing operations
 
56,460

 
74,889

 
37,331

 
73,968

Loss from discontinued operations
 
—

 
—

 
—

 
(18,100
)
Net earnings available for common
 
 

 
 

 
 

 
 

stockholders
 
54,289

 
69,424

 
36,632

 
55,868

Basic earnings per share:
 
 

 
 

 
 

 
 

Continuing operations
 
$
0.44

 
$
0.56

 
$
0.29

 
$
0.59

Available for common stockholders
 
$
0.43

 
$
0.55

 
$
0.29

 
$
0.45

Dilutive earnings per share:
 
 

 
 

 
 

 
 

Continuing operations
 
$
0.44

 
$
0.56

 
$
0.29

 
$
0.59

Available for common stockholders
 
$
0.43

 
$
0.55

 
$
0.29

 
$
0.45

The sum of EPS by quarter in the above tables may not equal the net earnings per common and common share equivalents for the applicable year due to variations in the weighted average common and common share equivalents outstanding used in computing such amounts.


F-60

SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm



To the Stockholders and Board of Directors
of Southern Union Company: 

In our opinion, the accompanying consolidated balance sheets and the related consolidated statement of operations, of stockholder's equity and comprehensive income and of cash flows present fairly, in all material respects, the financial position of Southern Union Company and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
/s/ PricewaterhouseCoopers LLP
 
Houston, Texas
February 24, 2012



F-61

Energy Transfer LP Reports

Also read