ETE- 9.30.2011-Q3
Table of Contents

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2011
or
 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-32740
ENERGY TRANSFER EQUITY, L.P.
(Exact name of registrant as specified in its charter)
 
Delaware
 
30-0108820
(state or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
3738 Oak Lawn Avenue, Dallas, Texas 75219
(Address of principal executive offices) (zip code)
(214) 981-0700
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
ý
  
Accelerated filer
¨
 
 
 
 
Non-accelerated filer
£  (Do not check if a smaller reporting company)
  
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
At November 2, 2011, the registrant had units outstanding as follows:
Energy Transfer Equity, L.P. 222,972,708 Common Units

Table of Contents

FORM 10-Q
TABLE OF CONTENTS
Energy Transfer Equity, L.P. and Subsidiaries
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ITEM 4. [RESERVED]
 
 
 
 
 
 
 


i

Table of Contents

Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (“Energy Transfer Equity,” the “Partnership” or “ETE”) in periodic press releases and some oral statements of Energy Transfer Equity officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its general partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part II — Other Information – Item 1A. Risk Factors” in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011, as well as “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission (“SEC”) on February 28, 2011.
Definitions
The following is a list of certain acronyms and terms generally used throughout this document:

 
/d
  
per day
 
 
 
 
Bbls
  
barrels
 
 
 
 
Btu
  
British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used
 
 
 
 
Capacity
  
capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels
 
 
 
 
Mcf
  
thousand cubic feet
 
 
 
 
MMBtu
  
million British thermal units
 
 
 
 
MMcf
  
million cubic feet
 
 
 
 
Bcf
  
billion cubic feet
 
 
 
 
NGL
  
natural gas liquid, such as propane, butane and natural gasoline
 
 
 
 
Tcf
  
trillion cubic feet
 
 
 
 
LIBOR
  
London Interbank Offered Rate
 
 
 
 
NYMEX
  
New York Mercantile Exchange
 
 
 
 
Reservoir
  
a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs
 
 
 
 
WTI
  
West Texas Intermediate Crude


ii

Table of Contents

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
(unaudited)
 
 
September 30, 2011
 
December 31, 2010
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
167,715

 
$
86,264

Marketable securities
3,151

 
2,032

Accounts receivable, net of allowance for doubtful accounts of $7,123 and $6,706 as of September 30, 2011 and December 31, 2010, respectively
669,955

 
612,357

Accounts receivable from related companies
86,454

 
76,331

Inventories
328,841

 
366,384

Exchanges receivable
17,675

 
21,926

Price risk management assets
15,719

 
16,357

Other current assets
143,578

 
109,359

Total current assets
1,433,088

 
1,291,010

PROPERTY, PLANT AND EQUIPMENT
15,922,724

 
13,284,430

ACCUMULATED DEPRECIATION
(1,822,675
)
 
(1,431,698
)
 
14,100,049

 
11,852,732

ADVANCES TO AND INVESTMENTS IN AFFILIATES
1,515,604

 
1,359,979

LONG-TERM PRICE RISK MANAGEMENT ASSETS
23,523

 
13,971

GOODWILL
2,039,383

 
1,600,611

INTANGIBLE ASSETS, net
1,083,968

 
1,034,846

OTHER NON-CURRENT ASSETS, net
247,703

 
225,581

Total assets
$
20,443,318

 
$
17,378,730


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

1

Table of Contents


ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
(unaudited)

 
September 30, 2011
 
December 31, 2010
LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable
$
468,480

 
$
421,556

Accounts payable to related companies
24,618

 
27,351

Exchanges payable
15,758

 
16,003

Price risk management liabilities
76,615

 
13,172

Accrued and other current liabilities
794,660

 
567,688

Current maturities of long-term debt
424,119

 
35,305

Total current liabilities
1,804,250

 
1,081,075

LONG-TERM DEBT, less current maturities
11,252,745

 
9,346,067

SERIES A CONVERTIBLE PREFERRED UNITS (Note 10)
314,980

 
317,600

LONG-TERM PRICE RISK MANAGEMENT LIABILITIES
73,261

 
79,465

OTHER NON-CURRENT LIABILITIES
243,473

 
235,848

 
 
 
 
COMMITMENTS AND CONTINGENCIES (Note 14)

 

 
 
 
 
PREFERRED UNITS OF SUBSIDIARY (Note 10)
71,091

 
70,943

 
 
 
 
EQUITY:
 
 
 
General Partner
306

 
520

Limited Partners:
 
 
 
Common Unitholders
47,483

 
115,350

Accumulated other comprehensive income
2,736

 
4,798

Total partners’ capital
50,525

 
120,668

Noncontrolling interest
6,632,993

 
6,127,064

Total equity
6,683,518

 
6,247,732

Total liabilities and equity
$
20,443,318

 
$
17,378,730


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


2

Table of Contents

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except per unit data)
(unaudited)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2011
 
2010
 
2011
 
2010
REVENUES:
 
 
 
 
 
 
 
Natural gas operations
$
1,858,656

 
$
1,380,029

 
$
5,016,564

 
$
3,827,506

Retail propane
213,496

 
183,786

 
962,258

 
914,372

Other
25,714

 
23,992

 
83,070

 
80,438

Total revenues
2,097,866

 
1,587,807

 
6,061,892

 
4,822,316

COSTS AND EXPENSES:
 
 
 
 
 
 
 
Cost of products sold — natural gas operations
1,203,537

 
883,716

 
3,210,163

 
2,520,157

Cost of products sold — retail propane
141,868

 
104,533

 
587,460

 
519,796

Cost of products sold — other
7,632

 
6,856

 
20,992

 
20,470

Operating expenses
234,282

 
208,809

 
677,695

 
559,302

Depreciation and amortization
157,952

 
120,315

 
445,738

 
304,681

Selling, general and administrative
82,587

 
61,526

 
225,032

 
177,673

Total costs and expenses
1,827,858

 
1,385,755

 
5,167,080

 
4,102,079

OPERATING INCOME
270,008

 
202,052

 
894,812

 
720,237

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Interest expense, net of interest capitalized
(193,772
)
 
(209,871
)
 
(543,218
)
 
(460,578
)
Equity in earnings of affiliates
28,374

 
22,349

 
82,634

 
40,723

Losses on non-hedged interest rate derivatives
(68,497
)
 
(31,966
)
 
(65,094
)
 
(68,858
)
Impairment of investments in affiliates
(5,355
)
 

 
(5,355
)
 
(52,620
)
Other, net
33,231

 
14,379

 
21,081

 
10,819

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
63,989

 
(3,057
)
 
384,860

 
189,723

Income tax expense
3,290

 
2,093

 
18,417

 
11,357

INCOME (LOSS) FROM CONTINUING OPERATIONS
60,699

 
(5,150
)
 
366,443

 
178,366

Income from discontinued operations

 
324

 

 
410

NET INCOME (LOSS)
60,699

 
(4,826
)
 
366,443

 
178,776

LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST
(8,384
)
 
10,511

 
142,435

 
62,069

NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS
69,083

 
(15,337
)
 
224,008

 
116,707

GENERAL PARTNER’S INTEREST IN NET INCOME (LOSS)
214

 
(48
)
 
693

 
361

LIMITED PARTNERS’ INTEREST IN NET INCOME (LOSS)
$
68,869

 
$
(15,289
)
 
$
223,315

 
$
116,346

BASIC NET INCOME (LOSS) PER LIMITED PARTNER UNIT
$
0.31

 
$
(0.07
)
 
$
1.00

 
$
0.52

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING
222,972,708

 
222,941,172

 
222,966,763

 
222,941,151

DILUTED NET INCOME (LOSS) PER LIMITED PARTNER UNIT
$
0.31

 
$
(0.07
)
 
$
1.00

 
$
0.52

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING
222,972,708

 
222,941,172

 
222,966,763

 
222,941,151

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

3

Table of Contents

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
(unaudited)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2011
 
2010
 
2011
 
2010
Net income (loss)
$
60,699

 
$
(4,826
)
 
$
366,443

 
$
178,776

Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges
288

 
64,644

 
(13,129
)
 
67,199

Change in value of derivative instruments accounted for as cash flow hedges
16,412

 
25,791

 
9,403

 
30,291

Change in value of available-for-sale securities
(900
)
 
(732
)
 
(935
)
 
(3,785
)
 
15,800

 
89,703

 
(4,661
)
 
93,705

Comprehensive income
76,499

 
84,877

 
361,782

 
272,481

Less: Comprehensive income attributable to noncontrolling interest
4,323

 
32,197

 
139,836

 
89,915

Comprehensive income attributable to partners
$
72,176

 
$
52,680

 
$
221,946

 
$
182,566


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


4

Table of Contents

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2011
(Dollars in thousands)
(unaudited)
 
 
General
Partner    
 
Common
Unitholders    
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interest
 
Total    
Balance, December 31, 2010
$
520

 
$
115,350

 
$
4,798

 
$
6,127,064

 
$
6,247,732

Distributions to ETE partners
(1,194
)
 
(384,612
)
 

 

 
(385,806
)
Distributions to noncontrolling interest

 

 

 
(574,285
)
 
(574,285
)
Subsidiary units issued for cash
291

 
93,650

 

 
909,268

 
1,003,209

Subsidiary units issued in acquisition

 

 

 
3,000

 
3,000

Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings

 
846

 

 
32,328

 
33,174

Non-cash executive compensation

 
19

 

 
919

 
938

Other, net
(4
)
 
(1,085
)
 

 
(5,137
)
 
(6,226
)
Other comprehensive loss, net of tax

 

 
(2,062
)
 
(2,599
)
 
(4,661
)
Net income
693

 
223,315

 

 
142,435

 
366,443

Balance, September 30, 2011
$
306

 
$
47,483

 
$
2,736

 
$
6,632,993

 
$
6,683,518


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


5

Table of Contents

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
(unaudited)
 
 
Nine Months Ended September 30,
 
2011
 
2010
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES:
 
 
 
Net income
$
366,443

 
$
178,776

Reconciliation of net income to net cash provided by operating activities:
 
 
 
Impairment of investments in affiliates
5,355

 
52,620

Payments for termination of Parent Company interest rate derivatives

 
(168,550
)
Proceeds from termination of interest rate derivatives

 
26,495

Depreciation and amortization
445,738

 
304,681

Amortization of finance costs charged to interest
14,581

 
13,299

Non-cash unit-based compensation expense
33,491

 
22,547

Non-cash executive compensation expense
938

 
938

Losses on disposal of assets
3,272

 
408

Distributions in excess of equity in earnings of affiliates, net
2,177

 
71,026

Other non-cash
(3,211
)
 
(5,361
)
Changes in operating assets and liabilities, net of effects of acquisitions (Note 4)
234,176

 
430,804

Net cash provided by operating activities
1,102,960

 
927,683

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Cash paid for acquisitions, net of cash received
(1,971,438
)
 
(323,705
)
Capital expenditures (excluding allowance for equity funds used during construction)
(1,232,059
)
 
(1,125,104
)
Contributions in aid of construction costs
18,435

 
12,048

Advances to affiliates, net
(166,506
)
 
(44,968
)
Proceeds from the sale of assets
15,570

 
84,044

Net cash used in investing activities
(3,335,998
)
 
(1,397,685
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Proceeds from borrowings
6,429,107

 
2,927,042

Principal payments on debt
(4,130,493
)
 
(3,133,678
)
Subsidiary equity offering, net of issue costs
1,003,209

 
1,486,863

Distributions to partners
(385,806
)
 
(362,286
)
Debt issuance costs
(22,217
)
 
(35,612
)
Distributions to noncontrolling interest
(574,285
)
 
(390,805
)
Other, net
(5,026
)
 
(1,724
)
Net cash provided by financing activities
2,314,489

 
489,800

INCREASE IN CASH AND CASH EQUIVALENTS
81,451

 
19,798

CASH AND CASH EQUIVALENTS, beginning of period
86,264

 
68,315

CASH AND CASH EQUIVALENTS, end of period
$
167,715

 
$
88,113


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


6

Table of Contents

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar amounts, except per unit data, are in thousands)
(unaudited)
 
1.
OPERATIONS AND ORGANIZATION:
Energy Transfer Equity, L.P. (together with its subsidiaries, the “Partnership,” “we,” or “ETE”) is a publicly traded Delaware limited partnership that directly and indirectly owns equity interests in Energy Transfer Partners, L.P. (“ETP”) and Regency Energy Partners LP (“Regency”), both publicly traded master limited partnerships engaged in strategic diversified energy-related services.
At September 30, 2011, our equity interests consisted of:

 
General Partner
Interest
(as a % of total
partnership  interest)
 
Incentive
Distribution
Rights
(“IDRs”)
 
Common
Units
ETP
1.6
%
 
100
%
 
50,226,967

Regency
1.9
%
 
100
%
 
26,266,791


The unaudited consolidated financial statements of ETE presented herein for the three and nine month periods ended September 30, 2011 and 2010 include the results of operations of:
the Parent Company;
our controlled subsidiaries, ETP and Regency (see description of their respective operations below under “Business Operations”);
ETP’s and Regency’s wholly-owned subsidiaries; and
our wholly-owned subsidiaries that own the general partner and IDR interests in ETP and Regency.
ETE obtained control of Regency on May 26, 2010, and as such, the nine month period ended September 30, 2010 includes the results of Regency for the period from the acquisition date through the end of the period.
Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, Energy Transfer Partners GP, L.P. (“ETP GP”), the General Partner of ETP, ETP GP’s General Partner, Energy Transfer Partners, L.L.C. (“ETP LLC”), Regency, Regency GP LP (“Regency GP”), the General Partner of Regency, and Regency GP’s General Partner, Regency GP LLC (“Regency LLC”). References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
Business Operations
The Parent Company’s principal sources of cash flow are its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements, distributions to its partners and holders of the Series A Convertible Preferred Units (the “Preferred Units”) and at ETE’s election, capital contributions to ETP and Regency in respect of ETE’s general partner interests in ETP and Regency. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to fully understand the financial condition of the Parent Company on a stand-alone basis, see Note 19 for stand-alone financial information apart from that of the consolidated partnership information included herein.
The following is a brief description of ETP’s and Regency’s operations:
ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arizona, Arkansas, Colorado, Louisiana, New Mexico, Utah and West Virginia and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include gathering and transportation pipelines, treating and processing assets, and storage facilities located in Texas. ETP also holds a 70% interest in Lone Star NGL LLC (“Lone Star”), a joint venture that owns and operates NGL storage, fractionation and transportation assets in Texas, Louisiana and Mississippi. ETP is also one of the largest retail marketers of propane in the United States.
 

7

Table of Contents

Regency is a publicly traded partnership engaged in the gathering and processing, contract compression, treating, transportation, fractionation and storage of natural gas and NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville, and Marcellus shales, as well as the Permian Delaware basin. Its assets are located in California, Louisiana, Texas, Arkansas, Pennsylvania, Mississippi, Alabama and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.
Preparation of Interim Financial Statements
The accompanying consolidated balance sheet as of December 31, 2010, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of the Partnership, as of September 30, 2011 and for the three and nine month periods ended September 30, 2011 and 2010, have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim consolidated financial information and pursuant to the rules and regulations of the SEC. Accordingly, they do not include all the information and footnotes required by GAAP for complete consolidated financial statements. However, management believes that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the Partnership’s operations, maintenance activities of the Partnership’s subsidiaries and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting. Management has evaluated subsequent events through the date the financial statements were issued.
In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of the Partnership as of September 30, 2011, and the Partnership’s results of operations and cash flows for the three and nine months ended September 30, 2011 and 2010. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2010, as filed with the SEC on February 28, 2011.
Certain prior period amounts have been reclassified to conform to the 2011 presentation. These reclassifications had no impact on net income or total equity.

2.
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 the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for natural gas and NGL related operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

3.
ACQUISITIONS AND DIVESTITURES:
LDH Acquisition
On May 2, 2011, ETP-Regency Midstream Holdings, LLC (“ETP-Regency LLC”), a joint venture owned 70% by ETP and 30% by Regency, acquired all of the membership interest in LDH Energy Asset Holdings LLC (“LDH”), from Louis Dreyfus Highbridge Energy LLC (“Louis Dreyfus”) for approximately $1.98 billion in cash (the “LDH Acquisition”), including working capital adjustments. ETP contributed approximately $1.38 billion to ETP-Regency LLC to fund its 70% share of the purchase price, while Regency contributed approximately $592.7 million to fund its 30% share of the purchase price. Subsequent to closing, ETP-Regency LLC was renamed Lone Star.

8

Table of Contents

Lone Star owns and operates a natural gas liquids storage, fractionation and transportation business. Lone Star’s storage assets are primarily located in Mont Belvieu, Texas and its West Texas Pipeline transports NGLs through an intrastate pipeline system that originates in the Permian Basin in west Texas, passes through the Barnett Shale production area in north Texas and terminates at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana. The acquisition of LDH by Lone Star significantly expands ETP and Regency’s asset portfolios by adding a NGL platform with storage, transportation and fractionation capabilities. This acquisition is expected to provide ETP and Regency with additional consistent fee-based revenues.
ETP accounted for the LDH Acquisition using the acquisition method of accounting. Lone Star’s results of operations are consolidated into our ETP reporting segment, while Lone Star’s results are recorded as an equity method investment in our Regency reporting segment. Regency’s equity method investment in Lone Star is reflected by ETP as noncontrolling interest attributable to Lone Star. These amounts have been eliminated in our consolidated financial statements.
The following table summarizes the assets acquired and liabilities assumed recognized as of the acquisition date:
 
Total current assets
$
118,177

Property, plant and equipment(1)
1,419,591

Goodwill
432,026

Intangible assets
81,000

Other assets
157

 
2,050,951

 
 
Total current liabilities
74,964

Other long-term liabilities
438

 
75,402

Total consideration
1,975,549

Cash received
31,231

Total consideration, net of cash received
$
1,944,318

 
(1)Property, plant and equipment (and estimated useful lives) consists of the following:
Land and improvements
$
30,759

Buildings and improvements (10 to 40 years)
3,123

Pipelines and equipment (20 to 65 years)
662,881

Natural gas liquids storage (40 years)
682,419

Linepack
704

Vehicles (3 to 20 years)
242

Furniture and fixtures (3 to 10 years)
49

Other (5 to 10 years)
8,526

Construction work-in-process
30,888

Property, plant and equipment
$
1,419,591



9

Table of Contents

Pro Forma Results of Operations
The following unaudited pro forma consolidated results of operations for the three and nine months ended September 30, 2011 and 2010 are presented as if the acquisitions of LDH and Regency had been completed on January 1, 2010:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2011
 
2010
 
2011
 
2010
Revenues
$
2,097,866

 
$
1,656,950

 
$
6,170,481

 
$
5,558,813

Net income (loss)
60,669

 
(10,114
)
 
358,230

 
203,747

Net income attributable to partners
69,083

 
(16,777
)
 
221,972

 
162,889

Basic net income (loss) per Limited Partner unit
$
0.31

 
$
(0.08
)
 
$
1.00

 
$
0.73

Diluted net income (loss) per Limited Partner unit
$
0.31

 
$
(0.08
)
 
$
1.00

 
$
0.73

The pro forma consolidated results of operations include adjustments to:
include the results of LDH and Regency for all periods presented;
include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting;
include incremental interest expense related to financing the purchase price;
adjust for one-time expenses; and
adjust for relative changes in ownership resulting from both transactions.
The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.
Pending Acquisition
On July 19, 2011, we entered into a Second Amended and Restated Plan of Merger (the “Second Amended SUG Merger Agreement”) with Sigma Acquisition Corporation, a Delaware corporation and our wholly-owned subsidiary (“Merger Sub”), and Southern Union Company (“SUG”), a Delaware corporation. The Second Amended SUG Merger Agreement modifies certain terms of the Amended and Restated Agreement and Plan of Merger entered into by us, Merger Sub and SUG on July 4, 2011. Under the terms of the Second Amended SUG Merger Agreement, Merger Sub will merge with and into SUG, with SUG continuing as the surviving entity and becoming our wholly-owned subsidiary (the “SUG Merger”) subject to certain conditions to close. Pursuant to the Second Amended SUG Merger Agreement, ETE will acquire all of the outstanding shares of SUG in a transaction valued at $9.4 billion at the time of the execution of the Second Amended SUG Merger Agreement, including $5.7 billion in cash and ETE Common Units and $3.7 billion of existing SUG indebtedness. Stockholders of SUG may elect to exchange each share of SUG stock for either $44.25 in cash or 1.00 ETE Common Unit. The maximum cash component is 60% of the aggregate consideration and the common unit component can fluctuate between 40% and 50%. Elections in excess of either the cash or common unit limits will be subject to proration.
Consummation of the SUG Merger is subject to customary conditions, including, without limitation: (i) the adoption of the Second Amended SUG Merger Agreement by the stockholders of SUG, (ii) the receipt of required approvals from the Federal Energy Regulatory Commission (“FERC”), the Missouri Public Service Commission and, if required, the Massachusetts Department of Public Utilities, (iii) the effectiveness of a registration statement on Form S-4 relating to the ETE Common Units to be issued in the SUG Merger, and (iv) the absence of any law, injunction, judgment or ruling prohibiting or restraining the SUG Merger or making the consummation of the SUG Merger illegal. On July 28, 2011, the waiting period applicable to the SUG Merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act") expired. On September 23, 2011, the FERC issued a letter order authorizing the transfer of FERC-jurisdictional facilities resulting from the SUG Merger. On October 27, 2011, the registration statement on Form S-4 was declared effective by the SEC.
Citrus Transaction
On July 19, 2011, ETP entered into an Amended and Restated Agreement and Plan of Merger with us (the “Amended Citrus Merger Agreement”). The Amended Citrus Merger Agreement modifies certain terms of the Agreement and Plan of Merger entered into by ETP and us on July 4, 2011. Pursuant to the terms of the Second Amended SUG Merger Agreement, immediately prior to the effective time of the SUG Merger, we will assign and SUG will assume the benefits and obligations of us under

10

Table of Contents

the Amended Citrus Merger Agreement.
Under the Amended Citrus Merger Agreement, it is anticipated that SUG will cause the contribution to ETP of a 50% interest in Citrus Corp., which owns 100% of the Florida Gas Transmission pipeline system and is currently jointly owned by SUG and El Paso Corporation (the “Citrus Transaction”). The Citrus Transaction will be effected through the merger of Citrus ETP Acquisition, L.L.C., a Delaware limited liability company and wholly-owned subsidiary of SUG that indirectly owns a 50% interest in Citrus Corp. (“CrossCountry”). In exchange for the interest in Citrus Corp., SUG will receive approximately $2 billion, consisting of approximately $1.9 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 10 consecutive trading days ending immediately prior to the date that is three trading days prior to the closing date of the Citrus Transaction. In order to increase the expected accretion to be derived from the Citrus Transaction, we have agreed to relinquish our rights to approximately $220 million of incentive distributions from ETP that we would otherwise be entitled to receive over 16 consecutive quarters following the closing of the transaction.

The Amended Citrus Merger Agreement includes customer representations, warranties and covenants of ETP and us (including representations, warranties and covenants relating to SUG, CrossCountry and certain of CrossCountry’s affiliates). Consummation of the Citrus Transaction is subject to customary conditions, including, without limitation: (i) satisfaction or waiver of the closing conditions set forth in the Second Amended SUG Merger Agreement, (ii) the receipt by ETP of any necessary waivers or amendments to its credit agreements, (iii) the amendment of ETP’s partnership agreement to reflect the agreed upon relinquishment by us of incentive distributions from ETP discussed above, and (iv) the absence of any order, decree, injunction or law prohibiting or making the consummation of the transactions contemplated by the Amended Citrus Merger Agreement illegal. The Amended Citrus Merger Agreement contains certain termination rights for both us and ETP, including among others, the right to terminate if the Citrus Transaction is not completed by December 31, 2012 or if the Second Amended Merger SUG Agreement is terminated.
Pursuant to the Amended Citrus Merger Agreement, we have granted ETP a right of first offer with respect to any disposition by us or SUG of Southern Union Gas Services, a subsidiary of SUG that owns and operates a natural gas gathering and processing system serving the Permian Basin in West Texas and New Mexico.

Midcontinent Express Pipeline

In conjunction with the Regency Transactions in May 2010, Regency acquired an indirect 49.9% interest in the Midcontinent Express Pipeline LLC (“MEP”), and an option to acquire an additional 0.1% interest in MEP subsequent to May 2011. On September 1, 2011, Regency exercised its option to acquire the remaining 0.1% interest in MEP from ETP for approximately $1.2 million in cash.

Propane Operations

In October 2011, ETP entered into an agreement with AmeriGas Partners, L.P. (“AmeriGas”) to contribute its propane operations, consisting of Heritage Operating, L.P. (“HOLP”) and Titan Energy Partners, L.P. (“Titan”) (collectively, the “Propane Business”) to AmeriGas in exchange for consideration of approximately $2.9 billion. The consideration consists of $1.5 billion in cash and common units of AmeriGas valued at $1.32 billion at the time of the execution of the agreement, plus the assumption of certain liabilities of the Propane Business. One of ETP's closing deliverables under the agreement is that it enters into and delivers a support agreement with AmeriGas that ETP will provide contingent, residual support of senior notes issued by AmeriGas to finance the cash portion of the purchase price. The transaction is subject to customary closing conditions, including approval under the HSR Act, and is expected to close late 2011 or early 2012.

We have not reflected the Propane operations as discontinued operations as we expect to have a continuing involvement in this business as a result of the investment in AmeriGas that would be transferred to ETP as consideration for the transaction.

4.
CASH AND CASH EQUIVALENTS:
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

11

Table of Contents

The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities is comprised as follows:

 
Nine Months Ended September 30,
 
2011
 
2010
Accounts receivable
$
15,492

 
$
200,962

Accounts receivable from related companies
(8,401
)
 
(10,637
)
Inventories
50,096

 
113,790

Exchanges receivable
4,251

 
4,757

Other current assets
(15,992
)
 
21,250

Other non-current assets, net
7,406

 
8,538

Accounts payable
(26,696
)
 
(107,895
)
Accounts payable to related companies
(2,733
)
 
(5,741
)
Exchanges payable
(244
)
 
(8,340
)
Accrued and other current liabilities
165,277

 
52,127

Other non-current liabilities
1,244

 
(741
)
Price risk management assets and liabilities, net
44,476

 
162,734

Net change in operating assets and liabilities, net of effects of acquisitions
$
234,176

 
$
430,804


Non-cash investing and financing activities are as follows:
 
 
Nine Months Ended September 30,
 
2011
 
2010
NON-CASH INVESTING ACTIVITIES:
 
 
 
Accrued capital expenditures
$
154,378

 
$
83,834

Gain from subsidiary common unit transactions
$
93,941

 
$
343,714

NON-CASH FINANCING ACTIVITIES:
 
 
 
Subsidiary issuance of common units in connection with acquisition
$
3,000

 
$

Long-term debt assumed and non-compete agreement notes payable issued in acquisitions
$
4,166

 
$
1,240,481


5.
INVENTORIES:
Inventories consisted of the following:
 
 
September 30,
2011
 
December 31,
2010
Natural gas and NGLs, excluding propane
$
120,798

 
$
170,179

Propane
75,085

 
76,341

Appliances, parts and fittings and other
132,958

 
119,864

Total inventories
$
328,841

 
$
366,384


ETP utilizes commodity derivatives to manage price volatility associated with its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.

 

12

Table of Contents

6.
GOODWILL AND INTANGIBLE ASSETS:
A net increase in goodwill of $438.8 million was recorded during the nine months ended September 30, 2011 primarily due to the LDH Acquisition referenced in Note 3. This additional goodwill is expected to be deductible for tax purposes. In addition, ETP recorded customer contracts of $81 million with useful lives ranging from 3 to 15 years.
Components and useful lives of intangible assets were as follows:
 
 
September 30, 2011
 
December 31, 2010
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Gross
Carrying
Amount
 
Accumulated
Amortization
Amortizable intangible assets:
 
 
 
 
 
 
 
Customer relationships, contracts and agreements (3 to 46 years)
$
1,056,948

 
$
(122,257
)
 
$
971,657

 
$
(88,583
)
Trade names (20 years)
65,500

 
(4,367
)
 
65,500

 
(1,910
)
Noncompete agreements (3 to 15 years)
15,893

 
(7,900
)
 
21,165

 
(11,888
)
Patents (9 years)
750

 
(181
)
 
750

 
(118
)
Other (10 to 15 years)
1,320

 
(566
)
 
1,320

 
(492
)
Total amortizable intangible assets
1,140,411

 
(135,271
)
 
1,060,392

 
(102,991
)
Non-amortizable intangible assets:
 
 
 
 
 
 
 
Trademarks
78,828

 

 
77,445

 

Total intangible assets
$
1,219,239

 
$
(135,271
)
 
$
1,137,837

 
$
(102,991
)

Aggregate amortization expense of intangible assets was as follows:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2011
 
2010
 
2011
 
2010
Reported in depreciation and amortization
$
13,168

 
$
7,887

 
$
40,541

 
$
23,215


Estimated aggregate amortization expense related to intangible assets for the next five years is as follows:
 
Years Ending December 31:
 
2012
$
53,989

2013
49,652

2014
48,531

2015
47,644

2016
46,864


We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review goodwill and non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. Our annual impairment test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage, midstream and retail propane operations and as of December 31 for all others, including all of Regency’s reporting units. We have not completed our annual impairment tests for 2011 and have not recorded any impairments related to amortizable intangible assets during the nine months ended September 30, 2011.


13

Table of Contents

Recently Issued Accounting Standards

In September 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-08, Intangibles - Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“ASU 2011-08”), which simplifies how entities test goodwill for impairment. ASU 2011-08 gives entities the option, under certain circumstances, to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. ASU 2011-08 is effective for fiscal years beginning after December 15, 2011, and early adoption is permitted. We are currently evaluating early adoption of ASU 2011-08, but we do not expect adoption of this standard will materially impact our financial position or results of operations.

7.
FAIR VALUE MEASUREMENTS:
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.
Based on the estimated borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of September 30, 2011 was $12.27 billion and $11.68 billion, respectively. As of December 31, 2010, the aggregate fair value and carrying amount of our consolidated debt obligations was $10.23 billion and $9.38 billion, respectively.
We have marketable securities, commodity derivatives, interest rate derivatives, the Preferred Units and embedded derivatives in the Preferred Units of a Subsidiary (the “Regency Preferred Units”) that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider over-the-counter (“OTC”) commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 since we use a LIBOR curve based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements and discount the future cash flows accordingly, including the effects of credit risk. Level 3 inputs are unobservable. Derivatives related to the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. The fair value of the Preferred Units was based predominantly on an income approach model and is also considered Level 3.


14

Table of Contents

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2011 and December 31, 2010 based on inputs used to derive their fair values:

 
Fair Value Measurements  at
September 30, 2011 Using
 
Fair Value
Total
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 
 
 
 
 
 
Marketable securities
$
3,151

 
$
3,151

 
$

 
$

Interest rate derivatives
30,564

 

 
30,564

 

Commodity derivatives:
 
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
74,892

 
74,892

 

 

Swing Swaps IFERC
21,818

 
1,074

 
20,744

 

Fixed Swaps/Futures
73,076

 
70,112

 
2,964

 

Options — Puts
13,348

 

 
13,348

 

Forward Physical Swaps
738

 

 
738

 

NGLs — Forward Swaps
577

 

 
577

 

Propane — Forward Swaps
77

 

 
77

 

WTI Crude Oil
4,817

 

 
4,817

 

Total commodity derivatives
189,343

 
146,078

 
43,265

 

Total Assets
$
223,058

 
$
149,229

 
$
73,829

 
$

Liabilities:
 
 
 
 
 
 
 
Interest rate derivatives
$
(99,658
)
 
$

 
$
(99,658
)
 
$

Series A Convertible Preferred Units
(314,980
)
 

 

 
(314,980
)
Embedded derivatives in the Regency Preferred Units
(36,268
)
 

 

 
(36,268
)
Commodity derivatives:
 
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(68,918
)
 
(68,918
)
 

 

Swing Swaps IFERC
(22,707
)
 
(1,988
)
 
(20,719
)
 

Fixed Swaps/Futures
(48,287
)
 
(48,133
)
 
(154
)
 

Options — Puts
(423
)
 

 
(423
)
 

Options — Calls
(122
)
 

 
(122
)
 

Forward Physical Swaps
(482
)
 

 
(482
)
 

NGLs — Forward Swaps
(11,722
)
 

 
(11,722
)
 

Propane — Forward Swaps
(2,086
)
 

 
(2,086
)
 

Total commodity derivatives
(154,747
)
 
(119,039
)
 
(35,708
)
 

Total Liabilities
$
(605,653
)
 
$
(119,039
)
 
$
(135,366
)
 
$
(351,248
)


15

Table of Contents

 
Fair Value Measurements  at
December 31, 2010 Using
 
Fair Value
Total
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 
 
 
 
 
 
Marketable securities
$
2,032

 
$
2,032

 
$

 
$

Interest rate derivatives
20,790

 

 
20,790

 

Commodity derivatives:
 
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
15,756

 
15,756

 

 

Swing Swaps IFERC
1,682

 
1,562

 
120

 

Fixed Swaps/Futures
44,955

 
42,474

 
2,481

 

Options — Calls
75

 

 
75

 

Options — Puts
26,241

 

 
26,241

 

NGLs — Forward Swaps
192

 

 
192

 

Propane — Forward Swaps
6,864

 

 
6,864

 

Total commodity derivatives
95,765

 
59,792

 
35,973

 

Total Assets
$
118,587

 
$
61,824

 
$
56,763

 
$

Liabilities:
 
 
 
 
 
 
 
Interest rate derivatives
$
(20,922
)
 
$

 
$
(20,922
)
 
$

Series A Convertible Preferred Units
(317,600
)
 

 

 
(317,600
)
Embedded derivatives in the Regency Preferred Units
(57,023
)
 

 

 
(57,023
)
Commodity derivatives:
 
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(17,372
)
 
(17,372
)
 

 

Swing Swaps IFERC
(3,768
)
 
(3,520
)
 
(248
)
 

Fixed Swaps/Futures
(42,252
)
 
(41,825
)
 
(427
)
 

Options — Calls
(2,643
)
 

 
(2,643
)
 

Options — Puts
(7
)
 

 
(7
)
 

NGLs — Forward Swaps
(10,684
)
 

 
(10,684
)
 

WTI Crude Oil
(3,581
)
 

 
(3,581
)
 

Total commodity derivatives
(80,307
)
 
(62,717
)
 
(17,590
)
 

Total Liabilities
$
(475,852
)
 
$
(62,717
)
 
$
(38,512
)
 
$
(374,623
)

The following table presents a reconciliation of the beginning and ending balances for liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the nine months ended September 30, 2011. There were no transfers between the fair value hierarchy levels during the nine months ended September 30, 2011.

Balance, December 31, 2010
$
(374,623
)
Net unrealized gains included in other income (expense)
23,375

Balance, September 30, 2011
$
(351,248
)

  

16

Table of Contents

8.
NET INCOME (LOSS) PER LIMITED PARTNER UNIT:
A reconciliation of net income (loss) and weighted average units used in computing basic and diluted net income (loss) per unit is as follows:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2011
 
2010
 
2011
 
2010
Basic Net Income (Loss) per Limited Partner Unit:
 
 
 
 
 
 
 
Limited Partners’ interest in net income (loss)
$
68,869

 
$
(15,289
)
 
$
223,315

 
$
116,346

Weighted average Limited Partner units
222,972,708

 
222,941,172

 
222,966,763

 
222,941,151

Basic net income (loss) per Limited Partner unit
$
0.31

 
$
(0.07
)
 
$
1.00

 
$
0.52

Diluted Net Income (Loss) per Limited Partner Unit:
 
 
 
 
 
 
 
Limited Partners’ interest in net income (loss)
$
68,869

 
$
(15,289
)
 
$
223,315

 
$
116,346

Dilutive effect of equity-based compensation of subsidiaries
167

 

 
525

 
158

Diluted net income (loss) available to Limited Partners
$
68,702

 
$
(15,289
)
 
$
222,790

 
$
116,188

Weighted average Limited Partner units
222,972,708

 
222,941,172

 
222,966,763

 
222,941,151

Diluted net income (loss) per Limited Partner unit
$
0.31

 
$
(0.07
)
 
$
1.00

 
$
0.52


Discontinued operations per unit has been omitted as the impact rounds to $0.00 per unit for all relevant periods presented.
The calculation above for the three and nine months ended September 30, 2011 for diluted net income (loss) per limited partner unit excludes the impact of any ETE Common Units that would be issued upon conversion of the Preferred Units, because inclusion would have been antidilutive. The Preferred Units have a liquidation preference of $300 million and are subject to mandatory conversion as discussed in Note 10.

9.
DEBT OBLIGATIONS:
Senior Notes
ETP Senior Notes
In May 2011, ETP completed a public offering of $800 million aggregate principal amount of 4.65% Senior Notes due June 1, 2021 and $700 million aggregate principal amount of 6.05% Senior Notes due June 1, 2041. ETP used the proceeds, net of commissions, of $1.48 billion to repay all of the borrowings outstanding under its revolving credit facility (the “ETP Credit Facility”), to fund capital expenditures related to pipeline construction projects and for general partnership purposes. ETP may redeem some or all of the notes at any time and from time to time pursuant to the terms of the indenture subject to the payment of a “make-whole” premium. Interest will be paid semi-annually.
Regency Senior Notes
In May 2011, Regency issued $500 million aggregate principal amount of 6.50% Senior Notes due July 15, 2021 (the “Regency 2021 Notes”). Regency used the proceeds, net of commissions, of approximately $491.3 million to repay borrowings outstanding under its revolving credit facility (the “Regency Credit Facility”). Regency capitalized $9.8 million in debt issuance costs that will be amortized to interest expense, net over the term of the Regency 2021 Notes. Interest will be paid semi-annually.
At any time prior to July 15, 2016, Regency may redeem some or all of the Regency 2021 Notes at a redemption price equal to 100% of the principal amount plus a “make-whole” premium, plus accrued and unpaid interest to the redemption date. At any time before July 15, 2014, Regency may redeem up to 35% of the aggregate principal amount of the Regency 2021 Notes then outstanding at a redemption price equal to 106.5% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest to the redemption date.

17

Table of Contents

Upon the occurrence of a change of control event, as defined in the indenture, followed by a rating decline within 90 days, each holder of the Regency 2021 Notes will be entitled to require Regency to purchase all or a portion of its notes at a purchase price of 101% plus accrued interest and liquidated damages, if any. Regency’s ability to purchase the notes upon a change of control will be limited by the terms of its debt agreements, including Regency’s revolving credit facility.
The Regency 2021 Notes contain various covenants that limit, among other things, Regency’s ability, and the ability of certain of its subsidiaries to:
incur additional indebtedness;
pay distributions on, or repurchase or redeem equity interests;
make certain investments;
incur liens;
enter into certain types of transactions with affiliates; and
sell assets, consolidate or merge with or into other companies.
Revolving Credit Facilities
Parent Company Credit Agreement
The Parent Company has a $200 million senior secured revolving credit facility (the “Parent Company Credit Agreement”) available through September 20, 2015. The Parent Company Credit Agreement is secured by all tangible or intangible assets of ETE and certain of its subsidiaries. As of September 30, 2011, there were no outstanding borrowings under the Parent Company Credit Agreement.
ETP Credit Facility
The ETP Credit Facility provides for $2 billion of revolving credit capacity that is expandable to $3 billion (subject to obtaining the approval of the administrative agent and securing lender commitments for the increased borrowing capacity). The ETP Credit Facility matures on July 20, 2012, unless ETP elects the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments). As of September 30, 2011, ETP had a balance of $574.6 million outstanding under the ETP Credit Facility, and the amount available for future borrowings was $1.4 billion taking into account letters of credit of $24.3 million. The weighted average interest rate on the total amount outstanding as of September 30, 2011 was 0.80%.
On October 27, 2011, ETP amended and restated the ETP Credit Facility to, among other things, (i) allow for borrowings of up to $2.5 billion; (ii) extend the maturity date from July 20, 2012 to October 27, 2016 (which may be extended by one year with lender approval); (iii) allow for an increase in the size of the credit facility to $3.75 billion (subject to obtaining lender commitments for the additional borrowing capacity); and (iv) to adjust the interest rates and commitment fees to current market terms. Following this amendment and based on ETP's current ratings, the interest margin for LIBOR rate loans is 1.50% and the commitment fee for unused borrowing capacity is 0.25%.
Regency Credit Facility
The Regency Credit Facility has aggregate revolving commitments of $900 million that matures June 15, 2014. As of September 30, 2011, there was a balance outstanding under the Regency Credit Facility of $445 million in revolving credit loans and approximately $20 million in letters of credit. The total amount available under the Regency Credit Facility, as of September 30, 2011, which is reduced by any letters of credit, was approximately $435 million. The weighted average interest rate on the total amount outstanding as of September 30, 2011 was 3.03%.
Covenants Related to Our Credit Agreements
We, ETP and Regency are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of September 30, 2011.

 

18

Table of Contents


10.
REDEEMABLE PREFERRED UNITS:
ETE Preferred Units
In connection with the Regency Transactions completed in May 2010, ETE issued 3,000,000 Series A Convertible Preferred Units to an affiliate of GE Energy Financial Services, Inc. (“GE EFS”) having an aggregate liquidation preference of $300 million. These units are reflected as a non-current liability in our consolidated balance sheets as of September 30, 2011 and December 31, 2010. The Preferred Units are measured at fair value on a recurring basis. Changes in the estimated fair value of the ETE Preferred Units are recorded in other income (expense) on the consolidated statements of operations.
Regency Preferred Units
Regency has 4,371,586 Regency Preferred Units outstanding at September 30, 2011, which were convertible into 4,626,197 Regency Common Units. If outstanding on September 2, 2029, the Regency Preferred Units are mandatorily redeemable for $80 million plus all accrued but unpaid distributions thereon. Holders of the Regency Preferred Units receive fixed quarterly cash distributions of $0.445 per unit from Regency. Holders can elect to convert Regency Preferred Units to Regency Common Units at any time in accordance with Regency’s Partnership Agreement.
11.
EQUITY:
ETE Common Units Issued
The change in ETE Common Units during the nine months ended September 30, 2011 was as follows:
 
 
Number of
Units
Outstanding at December 31, 2010
222,941,172

Issuance of restricted common units under equity incentive plan
31,536

Outstanding at September 30, 2011
222,972,708

Sales of Common Units by Subsidiaries
The Parent Company accounts for the difference between the carrying amount of its investments in ETP and Regency and the underlying book value arising from the issuance or redemption of units by ETP or Regency (excluding transactions with the Parent Company) as capital transactions.
As a result of ETP’s and Regency’s issuances of Common Units during the nine months ended September 30, 2011, we recognized increases in partners’ capital of $93.9 million.
Sales of Common Units by ETP
On April 1, 2011, ETP issued 14,202,500 Common Units through a public offering. The proceeds, net of commissions, of approximately $695.5 million were used to repay amounts outstanding under the ETP Credit Facility, to fund capital expenditures related to pipeline construction projects and for general partnership purposes.
ETP has an Equity Distribution Agreement with Credit Suisse Securities (USA) LLC (“Credit Suisse”) under which ETP may offer and sell from time to time through Credit Suisse, as its sales agent, ETP Common Units having an aggregate offering price of up to $200 million. During the nine months ended September 30, 2011, ETP received proceeds from units issued pursuant to this agreement of approximately $96.3 million, net of commissions, which were used for general partnership purposes. Approximately $77.5 million of ETP Common Units remain available to be issued under the Equity Distribution Agreement based on trades initiated through September 30, 2011.
In April 2011, ETP filed a registration statement with the SEC covering ETP’s Distribution Reinvestment Plan (the “DRIP”). The DRIP provides Unitholders of record and beneficial owners of ETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional ETP Common Units. The registration statement covers the issuance of up to 5,750,000 ETP Common Units under the DRIP.
For the nine months ended September 30, 2011, distributions of approximately $7.6 million were reinvested under the DRIP resulting in the issuance of 175,863 Common Units.

19

Table of Contents

Sales of Common Units by Regency
In October 2011, Regency issued 11,500,000 Regency Common Units through a public offering. The proceeds, net of commissions, of approximately $231.9 million were used to repay borrowings outstanding under the Regency Credit Facility.
In May 2011, Regency issued 8,500,001 Regency Common Units in a private placement. The net proceeds of $203.9 million were used to fund a portion of Regency’s 30% ownership interest in Lone Star, as discussed in Note 3.
Parent Company Quarterly Distributions of Available Cash
The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Regency related to limited and general partnership interests, including IDRs. We currently have no independent operations outside of our interests in ETP and Regency.
Following are distributions declared and/or paid by us subsequent to December 31, 2010:
 
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
December 31, 2010
 
February 7, 2011
 
February 18, 2011
 
$
0.540

March 31, 2011
 
May 6, 2011
 
May 19, 2011
 
0.560

June 30, 2011
 
August 5, 2011
 
August 19, 2011
 
0.625

September 30, 2011
 
November 4, 2011
 
November 18, 2011
 
0.625

ETP Quarterly Distributions of Available Cash
Following are distributions declared and/or paid by ETP subsequent to December 31, 2010:

Quarter Ended
 
Record Date
 
Payment Date
 
Rate
December 31, 2010
 
February 7, 2011
 
February 14, 2011
 
$
0.89375

March 31, 2011
 
May 6, 2011
 
May 16, 2011
 
0.89375

June 30, 2011
 
August 5, 2011
 
August 15, 2011
 
0.89375

September 30, 2011
 
November 4, 2011
 
November 14, 2011
 
0.89375


Regency Quarterly Distributions of Available Cash
Following are distributions declared and/or paid by Regency subsequent to December 31, 2010:
 
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
December 31, 2010
 
February 7, 2011
 
February 14, 2011
 
$
0.445

March 31, 2011
 
May 6, 2011
 
May 13, 2011
 
0.445

June 30, 2011
 
August 5, 2011
 
August 12, 2011
 
0.450

September 30, 2011
 
November 7, 2011
 
November 14, 2011
 
0.455


Accumulated Other Comprehensive Income
The following table presents the components of accumulated other comprehensive income (“AOCI”), net of tax:
 
 
September 30, 2011
 
December 31, 2010
Net gains on commodity related hedges
$
10,420

 
$
14,146

Unrealized gains (losses) on available-for-sale securities
(17
)
 
918

Subtotal
10,403

 
15,064

Amounts attributable to noncontrolling interest
(7,667
)
 
(10,266
)
Total AOCI included in partners’ capital, net of tax
$
2,736

 
$
4,798

 
 

20

Table of Contents

12.
UNIT-BASED COMPENSATION PLANS:
We, ETP, and Regency have equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase common units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, and other unit-based awards.
ETE Long-Term Incentive Plan
During the nine months ended September 30, 2011, ETE employees were granted a total of 30,000 unvested awards with five-year service vesting requirements. The weighted average grant-date fair value of these awards was $39.82 per unit. As of September 30, 2011 a total of 105,713 unit awards remain unvested, including the new awards granted during the period. We expect to recognize a total of $1.4 million in compensation expense over a weighted average period of 1.9 years related to unvested awards.
ETP Unit-Based Compensation Plans
During the nine months ended September 30, 2011, ETP employees were granted a total of 556,700 unvested awards with five-year service vesting requirements, and directors were granted a total of 2,580 unvested awards with three-year service vesting requirements. The weighted average grant-date fair value of these awards was $53.12 per unit. As of September 30, 2011 a total of 2,349,540 unit awards remain unvested, including the new awards granted during the period. ETP expects to recognize a total of $58.3 million in compensation expense over a weighted average period of 1.7 years related to unvested awards.
Regency Unit-Based Compensation Plans
Common Unit Options
During the nine months ended September 30, 2011, no Regency Common Unit options were granted. As of September 30, 2011, a total of 156,850 Regency Common Unit options remain vested and exercisable, with a weighted average exercise price of $21.99 per Regency Common Unit option.
Phantom Units
During the nine months ended September 30, 2011, Regency employees and directors were granted 76,745 Regency phantom units with three-year service vesting requirements. As of September 30, 2011, a total of 713,225 Regency Phantom Units remain unvested, with a weighted average grant date fair value of $24.78. Regency expects to recognize a total of $12 million in compensation expense over a weighted average period of 4.0 years related to Regency’s unvested phantom units.

 
13.
INCOME TAXES:
The components of the federal and state income tax expense of our taxable subsidiaries are summarized as follows:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2011
 
2010
 
2011
 
2010
Current expense (benefit):
 
 
 
 
 
 
 
Federal
$
1,124

 
$
(3,182
)
 
$
6,787

 
$
(124
)
State
2,675

 
1,363

 
12,109

 
8,864

Total
3,799

 
(1,819
)
 
18,896

 
8,740

Deferred expense (benefit):
 
 
 
 
 
 
 
Federal
(41
)
 
3,286

 
(599
)
 
2,257

State
(468
)
 
626

 
120

 
360

Total
(509
)
 
3,912

 
(479
)
 
2,617

Total income tax expense
$
3,290

 
$
2,093

 
$
18,417

 
$
11,357


The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are not subject to federal and state income taxes at the Partnership level.

21

Table of Contents


14.
REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
Regulatory Matter
On September 29, 2006, the Transwestern Pipeline Company, LLC ("Transwestern") filed revised tariff sheets under Section 4(e) of the Natural Gas Act (“NGA”) proposing a general rate increase to be effective on November 1, 2006. In April 2007, the FERC approved a Stipulation and Agreement of Settlement that resolved the primary components of the rate case. Under the terms of the settlement, Transwestern was required to file a new general NGA Section 4 rate case no later than October 1, 2011. However, Transwestern sought and on September 2, 2011 was granted an extension of the filing date until December 1, 2011 to allow time for settlement discussions with shippers. On September 21, 2011, Transwestern filed a proposed settlement with the FERC, which was approved by the FERC on October 31, 2011. The settlement maintains the currently effective transportation and fuel tariff rates with the exception that it reduces certain San Juan Lateral fuel rates staggered over the three year period beginning in April 2012. The settlement also resolves certain non-rate matters and reflects a continuation of the accounting practices from the prior rate settlement. Under the settlement, Transwestern will be required to file a Section 4 rate case on October 1, 2014.
Guarantee — Fayetteville Express Pipeline LLC
Fayetteville Express Pipeline LLC (“FEP”), a joint venture entity in which ETP owns a 50% interest, had a credit agreement that provided for a $1.1 billion senior revolving credit facility (the “FEP Facility”). ETP guaranteed 50% of the obligations of FEP under the FEP Facility, with the remainder of FEP Facility obligations guaranteed by Kinder Morgan Energy Partners, L.P. (“KMP”). Amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate.
In July 2011, the FEP Facility was repaid with capital contributions from ETP and KMP totaling $390 million along with proceeds from a $600 million term loan credit facility maturing in July 2012 (which can be extended for one year at the option of FEP). Upon closing and funding of the term loan facility, the FEP Facility was terminated. FEP also entered into a $50 million revolving credit facility maturing in July 2015. FEP's indebtedness under its new credit facilities is not guaranteed by ETP or KMP.
NGL Pipeline Regulation
ETP and Regency have interests in NGL pipelines located in Texas. ETP and Regency believe that these pipelines do not provide interstate service and that they are thus not subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy of 1992. Under the ICA, tariffs must be just and reasonable and not unduly discriminatory or confer any undue preference. We cannot guarantee that the jurisdictional status of ETP’s and Regency’s NGL facilities will remain unchanged; however, should they be found jurisdictional, the FERC’s rate-making methodologies may limit ETP’s and Regency’s ability to set rates based on their actual costs, may delay or limit the use of rates that reflect increased costs and may subject ETP and Regency to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.
Commitments
In the normal course of our business, ETP and Regency purchase, process and sell natural gas pursuant to long-term contracts and enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETP has also entered into several propane purchase and supply commitments, which are typically one year agreements with varying terms as to quantities, prices and expiration dates. ETP believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.
ETP and Regency have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $7.3 million and $6 million for the three months ended September 30, 2011 and 2010, respectively. For the nine months ended September 30, 2011 and 2010, rental expense for operating leases totaled approximately $20.5 million and $17.7 million, respectively.
ETP’s propane operations have an agreement with Enterprise Products Partners L.P. (together with its subsidiaries “Enterprise”) (see Note 16) to supply a portion of its propane requirements. The agreement will continue until 2015 and includes an option to extend the agreement for an additional year.
In connection with the sale of ETP’s investment in M-P Energy in October 2007, ETP executed a propane purchase agreement for approximately 90 million gallons per year through 2015 at market prices plus a nominal fee.

22

Table of Contents

ETP’s and Regency’s joint venture agreements require that ETP and Regency fund their proportionate shares of capital contributions to their unconsolidated affiliates. Such capital contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and propane are flammable, combustible gases. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of September 30, 2011 and December 31, 2010, accruals of approximately $13.3 million and $10.2 million, respectively, were reflected on our balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
The outcome of these matters cannot be predicted with certainty, and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Further, we may revise accrual amounts prior to the resolution of a particular contingency based on changes in facts and circumstances or in the expected outcome.
No amounts have been recorded in our September 30, 2011 or December 31, 2010 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
Environmental Matters
Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities.
We are unable to estimate any losses or range of losses that could result from such developments. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Our operations are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we

23

Table of Contents

operate. In some states, these laws are administered by state agencies, and in others, they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations governing the transportation of hazardous materials under the Federal Motor Carrier Safety Act, administered by the U.S. Department of Transportation (“DOT”). We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in substantial compliance with applicable laws and regulations.
ETP Environmental Matters
ETP has adopted policies, practices and procedures in the areas of pollution control, product safety, occupational safety and health, and the handling, storage, use, and disposal of hazardous materials to prevent and minimize material environmental or other damage, and to limit the financial liability, which could result from such events. However, the risk of environmental or other damage is inherent in transporting, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products, as it is with other entities engaged in similar businesses.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of ETP’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, ETP believes that such costs will not have a material adverse effect on its financial position.
As of September 30, 2011 and December 31, 2010, accruals related to ETP on an undiscounted basis of $12.6 million and $13.8 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities related to environmental matters.
Based on information available at this time and reviews undertaken to identify potential exposure, ETP believes the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by polychlorinated biphenyls (“PCBs”). The costs of this work are not eligible for recovery in rates. ETP’s total accrued future estimated cost of remediation activities expected to continue through 2025 is $7.9 million, which is included in the aggregate environmental accruals discussed above. Transwestern received approval from the FERC for the continuation of rate recovery of projected soil and groundwater remediation costs not related to PCBs for the term of its rate case settlement.
Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCBs. Future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. However, such future costs are not expected to have a material impact on our financial position, results of operations or cash flows.
The U.S. Environmental Protection Agency’s (the “EPA”) Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of ETP’s facilities. ETP expects to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures to comply with the new rules. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but ETP believes such costs will not have a material adverse effect on its financial position, results of operations or cash flows.
Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites on which HOLP presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, HOLP obtained indemnification rights for expenses associated with any remediation from the former owners or related entities. ETP has not been named as a potentially responsible party at any of these sites, and ETP believes that its operations have not contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in our September 30, 2011 or December 31, 2010 consolidated balance sheets. Based on information currently available to us, the presence of contamination and remediation activities at these sites are not expected to have a material adverse effect on our financial condition or results of operations.
On August 20, 2010, the EPA published new regulations under the federal Clean Air Act ("CAA") to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require ETP to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment. In response to an industry group legal challenge to portions of the rule in the U.S. Court of Appeals for the D.C. Circuit and a Petition for

24

Table of Contents

Administrative Reconsideration to the EPA, on March 9, 2011, the EPA issued a new proposed rule and a direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. If no further changes to the standard are made as a result of comments to the proposed rule, ETP would not expect that the cost to comply with the rule's requirements will have a material adverse effect on its financial condition or results of operations. Compliance with the final rule is required by October 2013.
On June 29, 2011, the EPA finalized a rule under the CAA that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule became effective on August 29, 2011. The rule modifications may require ETP to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if it replaces equipment or expands existing facilities in the future. At this point, ETP is not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes ETP might make in the future.
ETP’s pipeline operations are subject to regulation by the DOT under the Pipeline Hazardous Materials Safety Administration (“PHMSA”), pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a 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 refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. For the three months ended September 30, 2011 and 2010, $4.2 million and $5.8 million, respectively, of capital costs and $3.9 million of operating and maintenance costs have been incurred for pipeline integrity testing. For the nine months ended September 30, 2011 and 2010, $9.7 million and $10.8 million, respectively, of capital costs and $9.8 million and $10.2 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

 
15.
PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:
Commodity Price Risk
We are exposed to market risks related to the volatility of natural gas, NGL and propane prices. To manage the impact of volatility from these prices, our subsidiaries utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. Following is a description of price risk management activities by segment as well as tables detailing the outstanding commodity-related derivatives as of September 30, 2011 and December 31, 2010 by segment.
Investment in ETP
ETP injects and holds natural gas in its Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price) and uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, ETP will lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP will value the hedged natural gas inventory at current spot market prices along with the financial derivative it uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from ETP’s derivative instruments using mark-to-market accounting, with changes in the fair value of its derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as ETP enters the winter months, the spread converges so that it recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdrawal of natural gas.

25

Table of Contents

ETP is also exposed to market risk on natural gas it retains for fees in its intrastate transportation and storage operations and operational gas sales in its interstate transportation operations. ETP uses financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statements of operations.
Derivatives are utilized in ETP’s midstream operations in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. ETP attempts to maintain balanced positions in its marketing activities to protect itself from the volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, is expected to provide most of the gas required by its long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, are expected to be offset with financial contracts to balance ETP’s positions. To the extent open commodity positions exist, fluctuating commodity prices can impact its financial position and results of operations, either favorably or unfavorably.
ETP’s propane operations permit customers to guarantee the propane delivery price for the next heating season. As ETP executes fixed sales price contracts with its customers, it may enter into propane futures contracts to fix the purchase price related to these sales contracts, thereby locking in a gross profit margin. Additionally, ETP may use propane futures contracts to secure the purchase price of its propane inventory for a percentage of its anticipated propane sales.
The following table details ETP’s outstanding commodity-related derivatives:
 
 
September 30, 2011
 
December 31, 2010
 
Notional
Volume
 
Maturity
 
Notional
Volume
 
Maturity
Mark-to-Market Derivatives
 
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX (MMBtu)
(39,952,500
)
 
2011-2013
 
(38,897,500
)
 
2011
Swing Swaps IFERC (MMBtu)
30,517,500

 
2011-2013
 
(19,720,000
)
 
2011
Fixed Swaps/Futures (MMBtu)
(15,517,500
)
 
2011-2012
 
(2,570,000
)
 
2011
Forward Physical Contracts (MMBtu)
12,324,054

 
2011-2012
 

 

Options — Calls (MMBtu)

 

 
(3,000,000
)
 
2011
Propane:
 
 
 
 
 
 
 
Forwards/Swaps (Gallons)
52,668,000

 
2011-2012
 
1,974,000

 
2011
Fair Value Hedging Derivatives
 
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX (MMBtu)
(19,685,000
)
 
2011-2012
 
(28,050,000
)
 
2011
Fixed Swaps/Futures (MMBtu)
(29,837,500
)
 
2011-2012
 
(39,105,000
)
 
2011
Hedged Item — Inventory (MMBtu)
29,837,500

 
2011
 
39,105,000

 
2011
Cash Flow Hedging Derivatives
 
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
 
 
Fixed Swaps/Futures (MMBtu)
460,000

 
2011
 
(210,000
)
 
2011
Options — Puts (MMBtu)
9,390,000

 
2011-2012
 
26,760,000

 
2011-2012
Options — Calls (MMBtu)
(9,390,000
)
 
2011-2012
 
(26,760,000
)
 
2011-2012
Propane:
 
 
 
 
 
 
 
Forwards/Swaps (Gallons)

 

 
32,466,000

 
2011

We expect gains of $11.6 million related to ETP’s commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

26

Table of Contents

Investment in Regency
Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand, as well as market forces. Regency’s profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions are prohibited under Regency’s policy.
Regency is exposed to market risks associated with commodity prices, counterparty credit, and interest rates. Regency’s management and the board of directors of Regency’s General Partner have established comprehensive risk management policies and procedures to monitor and manage these market risks. Regency’s General Partner is responsible for delegation of transaction authority levels, and the Risk Management Committee of Regency’s General Partner is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. Regency’s Risk Management Committee receives regular briefings on positions and exposures, credit exposures, and overall risk management in the context of market activities.
Regency’s Preferred Units (see Note 10) contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and Regency’s call option. These embedded derivatives are accounted for using mark-to-market accounting. Regency does not expect the embedded derivatives to affect its cash flows.
The following table details Regency’s outstanding commodity-related derivatives:

 
September 30, 2011
 
December 31, 2010
 
Notional
Volume
 
Maturity
 
Notional
Volume
 
Maturity
Cash Flow Hedging Derivatives
 
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
 
 
Fixed Swaps/Futures (MMBtu)
2,934,000

 
2012
 
3,830,000

 
2011
Propane:
 
 
 
 
 
 
 
Forwards/Swaps (Gallons)
15,204,000

 
2013
 
18,648,000

 
2011-2012
Natural Gas Liquids:
 
 
 
 
 
 
 
Forwards/Swaps (Barrels)
771,000

 
2013
 
1,212,110

 
2011-2012
WTI Crude Oil:
 
 
 
 
 
 
 
Forwards/Swaps (Barrels)
417,000

 
2014
 
373,655

 
2011-2012

We expect losses of $5.3 million related to Regency’s commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

27

Table of Contents

Interest Rate Risk
We are exposed to market risk for changes in interest rates. In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We manage our current interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of anticipated debt issuances. The following is a summary of interest rate swaps outstanding as of September 30, 2011 and December 31, 2010, none of which were designated as hedges for accounting purposes:

 
 
 
 
 
 
Notional Amount
Outstanding
Entity
 
Term
 
Type(1)
 
September 30, 2011
 
December 31, 2010
ETP
 
May 2012 (2)
 
Forward starting to pay a fixed rate of 2.59% and receive a floating rate
 
$
350,000

 
$

ETP
 
August 2012 (2)
 
Forward starting to pay a fixed rate of 3.51% and receive a floating rate
 
500,000

 
400,000

ETP
 
July 2013 (2)
 
Forward starting to pay a fixed rate of 4.02% and receive a floating rate
 
300,000

 

ETP
 
July 2018
 
Pay a floating rate plus a spread of 4.01% and receive a fixed rate of 6.70%
 
500,000

 
500,000

Regency
 
April 2012
 
Pay a fixed rate of 1.325% and receive a floating rate
 
250,000

 
250,000

 
(1)As of September 30, 2011. Floating rates are based on 3-month LIBOR.
(2) 
These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.
Credit Risk
We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposures associated with a single counterparty.
Our counterparties consist primarily of petrochemical companies, other industrial, mid-size to major oil and gas companies and power companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty performance.
ETP utilizes master netting agreements and has maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on the settlement date for non-exchange traded derivatives. ETP exchanges margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in our consolidated balance sheets. ETP had net deposits with counterparties of $56.4 million and $52.2 million as of September 30, 2011 and December 31, 2010, respectively.
Regency is exposed to credit risk from its derivative counterparties. Although Regency does not require collateral from these counterparties, Regency deals primarily with financial institutions when entering into financial derivatives, and utilizes master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

28

Table of Contents

Derivative Summary
The following table provides a balance sheet overview of consolidated derivative assets and liabilities as of September 30, 2011 and December 31, 2010:
 
 
Fair Value of Derivative Instruments
 
Asset Derivatives
 
Liability Derivatives
 
September 30, 2011
 
December 31, 2010
 
September 30, 2011
 
December 31, 2010
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Commodity derivatives (margin deposits)
$
43,337

 
$
35,031

 
$
(461
)
 
$
(6,631
)
Commodity derivatives
8,358

 
9,263

 
(11,876
)
 
(14,692
)
 
51,695

 
44,294

 
(12,337
)
 
(21,323
)
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity derivatives (margin deposits)
$