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EX-32.1 - EXHIBIT 32.1 - Energy Transfer Equity, L.P.ete-3312015ex321.htm

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2015
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 May 1, 2015, the registrant had 539,234,023 Common Units outstanding.
 



FORM 10-Q
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
 


i


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,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “believe,” “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, estimated or expressed, forecasted, projected or expected in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2014 filed with the Securities and Exchange Commission on March 2, 2015.
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
 
/d
 
per day
 
 
 
 
AmeriGas
 
AmeriGas Partners, L.P.
 
 
 
 
 
AOCI
 
accumulated other comprehensive income (loss)
 
 
 
 
 
Bbls
 
barrels
 
 
 
 
Bcf
 
billion cubic feet
 
 
 
 
 
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 content
 
 
 
 
 
Citrus
 
Citrus LLC
 
 
 
 
 
CrossCountry
 
CrossCountry Energy LLC, which owns an indirect 50% interest in Citrus
 
 
 
 
 
ETC OLP
 
La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
 
 
 
 
 
ETP
 
Energy Transfer Partners, L.P.
 
 
 
 
 
ETP Holdco
 
ETP Holdco Corporation
 
 
 
 
 
Exchange Act
 
Securities Exchange Act of 1934
 
 
 
 
 
FEP
 
Fayetteville Express Pipeline LLC
 
 
 
 
 
FERC
 
Federal Energy Regulatory Commission
 
 
 
 
 
FGT
 
Florida Gas Transmission Company, LLC
 
 
 
 
 
GAAP
 
accounting principles generally accepted in the United States of America
 
 
 
 
 
HPC
 
RIGS Haynesville Partnership Co.
 
 
 
 
 
IDRs
 
incentive distribution rights
 
 
 
 
 
Lake Charles LNG
 
Lake Charles LNG Company, LLC
 
 
 
 
 
LIBOR
 
London Interbank Offered Rate
 
 
 
 
 
LNG
 
liquefied natural gas
 
 
 
 
 
Lone Star
 
Lone Star NGL LLC
 
 
 
 
 
MEP
 
Midcontinent Express Pipeline LLC
 
 
 
 

ii


 
MMBtu
 
million British thermal units
 
 
 
 
 
MTBE
 
methyl tertiary butyl ether
 
 
 
 
 
NGL
 
natural gas liquid, such as propane, butane and natural gasoline
 
 
 
 
NYMEX
 
New York Mercantile Exchange
 
 
 
 
 
OSHA
 
Federal Occupational Safety and Health Act
 
 
 
 
OTC
 
over-the-counter
 
 
 
 
 
Panhandle
 
Panhandle Eastern Pipe Line Company, LP
 
 
 
 
 
PCBs
 
polychlorinated biphenyl
 
 
 
 
 
PEPL Holdings
 
PEPL Holdings, LLC, a wholly-owned subsidiary of ETP
 
 
 
 
 
PHMSA
 
Pipeline Hazardous Materials Safety Administration
 
 
 
 
 
Regency
 
Regency Energy Partners LP
 
 
 
 
 
Regency Preferred Units
 
Regency’s Series A Convertible Preferred Units, the Preferred Units of a Subsidiary
 
 
 
 
 
Retail Holdings
 
ETP Retail Holdings, a joint venture between subsidiaries of ETC OLP and Sunoco, Inc.
 
 
 
 
 
SEC
 
Securities and Exchange Commission
 
 
 
 
 
Southern Union
 
Southern Union Company
 
 
 
 
 
Sunoco Logistics
 
Sunoco Logistics Partners L.P.
 
 
 
 
 
Sunoco LP
 
Sunoco LP (previously named Susser Petroleum Partners, LP)
 
 
 
 
 
Susser
 
Susser Holdings Corporation
 
 
 
 
 
Transwestern
 
Transwestern Pipeline Company, LLC
 
 
 
 
 
WTI
 
West Texas Intermediate Crude
Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.

iii


PART I — FINANCIAL INFORMATION

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

CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)
 
 
March 31,
2015
 
December 31, 2014
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
1,863

 
$
847

Accounts receivable, net
2,863

 
3,378

Accounts receivable from related companies
69

 
35

Inventories
1,461

 
1,467

Exchanges receivable
45

 
44

Price risk management assets
77

 
81

Other current assets
411

 
301

Total current assets
6,789

 
6,153

 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
47,400

 
45,018

ACCUMULATED DEPRECIATION
(5,058
)
 
(4,726
)
 
42,342

 
40,292

 
 
 
 
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES
3,656

 
3,659

NON-CURRENT PRICE RISK MANAGEMENT ASSETS
9

 
10

GOODWILL
7,702

 
7,865

INTANGIBLE ASSETS, net
5,553

 
5,582

OTHER NON-CURRENT ASSETS, net
953

 
908

Total assets
$
67,004

 
$
64,469


















The accompanying notes are an integral part of these consolidated financial statements.
1



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

 
March 31,
2015
 
December 31, 2014
LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable
$
2,865

 
$
3,349

Accounts payable to related companies
12

 
19

Exchanges payable
156

 
184

Price risk management liabilities
17

 
21

Accrued and other current liabilities
2,008

 
2,201

Current maturities of long-term debt
269

 
1,008

Total current liabilities
5,327

 
6,782

 
 
 
 
LONG-TERM DEBT, less current maturities
33,158

 
29,653

DEFERRED INCOME TAXES
4,139

 
4,325

NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES
228

 
154

OTHER NON-CURRENT LIABILITIES
1,313

 
1,193

 
 
 
 
COMMITMENTS AND CONTINGENCIES

 

 
 
 
 
PREFERRED UNITS OF SUBSIDIARY
33

 
33

REDEEMABLE NONCONTROLLING INTEREST
15

 
15

 
 
 
 
EQUITY:
 
 
 
General Partner
(1
)
 
(1
)
Limited Partners:
 
 
 
Common Unitholders
695

 
648

Class D Units
18

 
22

Accumulated other comprehensive loss
(5
)
 
(5
)
Total partners’ capital
707

 
664

Noncontrolling interest
22,084

 
21,650

Total equity
22,791

 
22,314

Total liabilities and equity
$
67,004

 
$
64,469












The accompanying notes are an integral part of these consolidated financial statements.
2


ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
(unaudited)
 
Three Months Ended
March 31,
 
2015
 
2014
REVENUES:
 
 
 
Natural gas sales
$
1,035

 
$
1,430

NGL sales
981

 
1,254

Crude sales
2,208

 
4,093

Gathering, transportation and other fees
1,046

 
872

Refined product sales
3,656

 
4,478

Other
1,454

 
953

Total revenues
10,380

 
13,080

COSTS AND EXPENSES:
 
 
 
Cost of products sold
8,487

 
11,442

Operating expenses
628

 
424

Depreciation, depletion and amortization
493


373

Selling, general and administrative
155

 
131

Total costs and expenses
9,763

 
12,370

OPERATING INCOME
617

 
710

OTHER INCOME (EXPENSE):
 
 
 
Interest expense, net of interest capitalized
(371
)

(315
)
Equity in earnings of unconsolidated affiliates
57

 
104

Losses on interest rate derivatives
(77
)

(2
)
Gain on sale of AmeriGas common units

 
70

Other, net
7

 
2

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
233

 
569

Income tax expense from continuing operations
12


145

INCOME FROM CONTINUING OPERATIONS
221

 
424

Income from discontinued operations


24

NET INCOME
221

 
448

LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST
(63
)
 
280

NET INCOME ATTRIBUTABLE TO PARTNERS
284

 
168

General Partner’s interest in net income
1

 

Class D Unitholder’s interest in net income
1

 
1

Limited Partners’ interest in net income
$
282

 
$
167

INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
 
 
 
Basic
$
0.52

 
$
0.30

Diluted
$
0.52

 
$
0.30

NET INCOME PER LIMITED PARTNER UNIT:
 
 
 
Basic
$
0.52

 
$
0.30

Diluted
$
0.52

 
$
0.30


The accompanying notes are an integral part of these consolidated financial statements.
3


ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
(unaudited)
 
 
Three Months Ended
March 31,
 
2015
 
2014
Net income
$
221

 
$
448

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

 
4

Change in value of derivative instruments accounted for as cash flow hedges
1

 
(4
)
Change in value of available-for-sale securities
1

 

Actuarial gain (loss) relating to pension and other postretirement benefits
45

 
(1
)
Foreign currency translation adjustments
(2
)
 
(3
)
Change in other comprehensive income from unconsolidated affiliates
(2
)
 
(7
)
 
43

 
(11
)
Comprehensive income
264

 
437

Less: Comprehensive income (loss) attributable to noncontrolling interest
(20
)
 
272

Comprehensive income attributable to partners
$
284

 
$
165






























The accompanying notes are an integral part of these consolidated financial statements.
4


ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF EQUITY
FOR THE THREE MONTHS ENDED MARCH 31, 2015
(Dollars in millions)
(unaudited)
 
 
General
Partner    
 
Common
Unitholders    
 
Class D Units
 
Accumulated
Other
Comprehensive
Loss
 
Non-
controlling
Interest
 
Total    
Balance, December 31, 2014
$
(1
)
 
$
648

 
$
22

 
$
(5
)
 
$
21,650

 
$
22,314

Distributions to partners
(1
)
 
(242
)
 
(1
)
 

 

 
(244
)
Distributions to noncontrolling interest

 

 

 

 
(565
)
 
(565
)
Subsidiary units issued for cash

 

 

 

 
857

 
857

Conversion of Class D Units to ETE Common Units

 
7

 
(7
)
 

 

 

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

 
1

 
3

 

 
12

 
16

Capital contributions received from noncontrolling interest

 

 

 

 
219

 
219

Sale of noncontrolling interest in Rover Pipeline LLC to AE–Midco Rover, LLC

 

 

 

 
64

 
64

Sunoco Logistics acquisition of noncontrolling interest

 

 

 

 
(129
)
 
(129
)
Other comprehensive income, net of tax

 

 

 

 
43

 
43

Other, net

 
(1
)
 

 

 
(4
)
 
(5
)
Net income (loss)
1

 
282

 
1

 

 
(63
)
 
221

Balance, March 31, 2015
$
(1
)
 
$
695

 
$
18

 
$
(5
)
 
$
22,084

 
$
22,791




















The accompanying notes are an integral part of these consolidated financial statements.
5


ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
(unaudited)
 
Three Months Ended
March 31,
 
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net income
$
221

 
$
448

Reconciliation of net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
493

 
373

Deferred income taxes
20

 
(109
)
Amortization included in interest expense
(10
)
 
(12
)
Non-cash compensation expense
23

 
20

Gain on sale of AmeriGas common units

 
(70
)
Inventory valuation adjustments
34

 
(14
)
Equity in earnings of unconsolidated affiliates
(57
)
 
(104
)
Distributions from unconsolidated affiliates
64

 
67

Other non-cash
(9
)
 
(16
)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations
(204
)
 
246

Net cash provided by operating activities
575

 
829

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Cash paid for acquisitions, net of cash received
(370
)
 
(214
)
Cash paid for acquisition of noncontrolling interest
(129
)
 

Cash proceeds from sale of noncontrolling interest in Rover Pipeline LLC to AE–Midco Rover, LLC
64

 

Cash proceeds from the sale of AmeriGas common units

 
381

Capital expenditures (excluding allowance for equity funds used during construction)
(2,158
)
 
(942
)
Contributions in aid of construction costs
4

 
7

Contributions to unconsolidated affiliates
(34
)
 
(50
)
Distributions from unconsolidated affiliates in excess of cumulative earnings
33

 
27

Proceeds from the sale of assets
9

 
11

Other
(4
)
 
(21
)
Net cash used in investing activities
(2,585
)
 
(801
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Proceeds from borrowings
8,731

 
3,170

Repayments of long-term debt
(5,938
)
 
(1,977
)
Subsidiary equity offerings, net of issue costs
857

 
175

Distributions to partners
(244
)
 
(195
)
Debt issuance costs
(33
)
 
(17
)
Distributions to noncontrolling interest
(565
)
 
(397
)
Capital contributions received from noncontrolling interest
219

 

Units repurchased under buyback program

 
(366
)
Other, net
(1
)
 
(1
)
Net cash provided by financing activities
3,026

 
392

INCREASE IN CASH AND CASH EQUIVALENTS
1,016

 
420

CASH AND CASH EQUIVALENTS, beginning of period
847

 
590

CASH AND CASH EQUIVALENTS, end of period
$
1,863

 
$
1,010


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


ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)
(unaudited)
1.
ORGANIZATION AND BASIS OF PRESENTATION:
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
The consolidated financial statements of ETE presented herein 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 consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDRs in ETP and Regency; and
our wholly-owned subsidiary, Lake Charles LNG.
The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 17 for stand-alone financial information apart from that of the consolidated partnership information included herein.
Our activities are primarily conducted through our operating subsidiaries as follows:
ETP is a publicly traded partnership whose operations are conducted through the following subsidiaries:
ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through its Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through its Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star.
ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:
Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.
ETC Fayetteville Express Pipeline, LLC, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.
ETC Tiger Pipeline, LLC, a Delaware limited liability company engaged in interstate transportation of natural gas.
CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline.
ETC Compression, LLC, a Delaware limited liability company engaged in natural gas compression services and related equipment sales.
ETP Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco, Inc. Panhandle and Sunoco, Inc. operations are described as follows:

7


Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. In January 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle, and PEPL Holdings, the sole limited partner of Panhandle, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle, with Panhandle surviving the merger.
Sunoco, Inc. owns and operates retail marketing assets, which sell gasoline and middle distillates at retail locations and operates convenience stores primarily on the east coast and in the midwest region of the United States. Effective June 1, 2014, ETP combined certain Sunoco, Inc. retail assets with another wholly-owned subsidiary of ETP to form a limited liability company owned by ETP and Sunoco, Inc.
Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products, crude oil and NGL pipelines, terminalling and storage assets, and refined products, crude oil and NGL acquisition and marketing assets.
ETP owns an indirect 100% equity interest in Susser and the general partner interest, incentive distribution rights and a 44% limited partner interest in Sunoco LP. Susser operates convenience stores in Texas, New Mexico and Oklahoma. Sunoco LP distributes motor fuels to convenience stores and retail fuel outlets in Texas, New Mexico, Oklahoma, Kansas, Louisiana, Maryland, Virginia, Tennessee, Georgia and Hawaii and other commercial customers.
Regency is a master limited partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; natural gas and NGL marketing and trading, and the management of coal and natural resource properties in the United States. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, Avalon and Granite Wash shales. Regency also holds a 30% interest in Lone Star.
Lake Charles LNG operates a LNG import terminal, which has approximately 9.0 Bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Lake Charles LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC.
Our financial statements reflect the following reportable business segments:
Investment in ETP, including the consolidated operations of ETP.
Investment in Regency, including the consolidated operations of Regency.
Investment in Lake Charles LNG, including the operations of Lake Charles LNG.
Corporate and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.
The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
Certain prior period amounts have been reclassified to conform to the 2015 presentation. These reclassifications had no impact on net income or total equity.

8


We record the collection of taxes to be remitted to government authorities on a net basis except for ETP’s retail marketing operations, in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and cost of products sold in the consolidated statements of operations, with no net impact on net income. Excise taxes collected by ETP’s retail marketing operations were $736 million and $530 million for the three months ended March 31, 2015 and 2014, respectively.
New Accounting Pronouncement
In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810) (“ASU 2015-02”), which changed the requirements for consolidations analysis.  Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities.  ASU 2015-02 is effective for fiscal years beginning after December 15, 2015, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2016, and we are currently evaluating the impact that it will have on our consolidated financial statements and related disclosures.
2.
ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
2015 Transactions
Regency Merger
In April 2015, ETP and Regency completed the previously announced merger of an indirect subsidiary of ETP, with and into Regency, with Regency surviving the merger as a wholly-owned subsidiary of ETP (the “Regency Merger”). As part of the merger consideration, each Regency common unit and Class F unit was converted into the right to receive 0.4124 ETP Common Units. Based on the Regency units outstanding, ETP issued approximately 172.2 million ETP Common Units to Regency unitholders, including approximately 15.5 million units issued to ETP subsidiaries. The approximately 1.9 million outstanding Regency Series A Preferred Units were converted into corresponding new ETP Series A Preferred Units.
In connection with the transaction, ETE, which owns the general partner and 100% of the incentive distribution rights of ETP, will reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy will be $80 million in the first year post-closing and $60 million per year for the following four years.
Dropdown of Sunoco, LLC Interests
In April 2015, Sunoco LP completed the acquisition of a 31.58% equity interest in Sunoco, LLC from Retail Holdings. Sunoco, LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. The transaction was valued at approximately $816 million. Sunoco LP paid $775 million in cash and issued $41 million of Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015.
Bakken Pipeline Transaction
In March 2015, ETE transferred 30.8 million ETP Common Units, ETE’s 45% interest in the Bakken pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. The IDR subsidies from ETE to ETP, including the impact from distributions on ETP Class I Units, will be reduced by $55 million in 2015 and $30 million in 2016.
Discontinued Operations
Discontinued operations for the three months ended March 31, 2014 included the results of operations for a marketing business that had been recently acquired and was sold effective April 1, 2014.

9


3.
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
The following investments in unconsolidated affiliates are reflected in our consolidated financial statements using the equity method:
AmeriGas. In January 2014, ETP recognized a gain on the sale of 9.2 million AmeriGas common units that were originally received in connection with the contribution of ETP’s propane business to AmeriGas in 2012. As of March 31, 2015, ETP’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.
Citrus. ETP owns a 50% interest in Citrus, which owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.
FEP. ETP owns a 50% interest in the FEP, which owns a natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company, LLC in Panola County, Mississippi.
HPC. Regency owns a 49.99% interest in HPC, which, through its ownership of the Regency Intrastate Gas System, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through an intrastate pipeline system.
MEP. Regency owns a 50% interest in MEP, which owns natural gas pipelines that extend from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama.
The following table presents aggregated selected income statement data for our unconsolidated affiliates listed above (on a 100% basis for all periods presented).
 
Three Months Ended
March 31,
 
2015
 
2014
Revenue
$
1,428

 
$
1,819

Operating income
553

 
464

Net income
437

 
344

In addition to the equity method investments described above, our subsidiaries have other equity method investments, which are not significant to our consolidated financial statements.
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.
Non-cash investing and financing activities were as follows:
 
Three Months Ended
March 31,
 
2015
 
2014
NON-CASH INVESTING ACTIVITIES:
 
 
 
Accrued capital expenditures
$
658

 
$
192

Net gains from subsidiary common unit issuances
$

 
$
603

NON-CASH FINANCING ACTIVITIES:
 
 
 
Subsidiary issuances of common units in connection with acquisitions
$

 
$
4,015

Long-term debt assumed in PVR Acquisition
$

 
$
1,887


10


5.
INVENTORIES:
Inventories consisted of the following:
 
March 31,
2015
 
December 31,
2014
Natural gas and NGLs
$
294

 
$
392

Crude oil
470

 
364

Refined products
367

 
392

Other
330

 
319

Total inventories
$
1,461

 
$
1,467

6.
FAIR VALUE MEASUREMENTS:
We have commodity derivatives, interest rate derivatives and embedded derivatives in 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 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 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 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements, and we 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. During the three months ended March 31, 2015, no transfers were made between any levels within the fair value hierarchy.
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value of our consolidated debt obligations as of March 31, 2015 and December 31, 2014 was $35.15 billion and $31.68 billion, respectively. As of March 31, 2015 and December 31, 2014, the aggregate carrying amount of our consolidated debt obligations was $33.43 billion and $30.66 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

11


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 March 31, 2015 and December 31, 2014 based on inputs used to derive their fair values:
 
Fair Value Measurements at
March 31, 2015
 
Fair Value
Total
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 
 
 
 
 
 
Interest rate derivatives
$
6

 
$

 
$
6

 
$

Commodity derivatives:
 
 
 
 
 
 
 
Condensate — Forward Swaps
35

 

 
35

 

Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
11

 
11

 

 

Swing Swaps IFERC
2

 

 
2

 

Fixed Swaps/Futures
317

 
295

 
22

 

Forward Physical Swaps
1

 

 
1

 

Natural Gas Liquids — Forwards/Swaps
42

 
25

 
17

 

Power:
 
 
 
 
 
 
 
Forwards
5

 

 
5

 

Futures
4

 
4

 

 

Options — Calls
2

 
2

 

 

Refined Products — Futures
7

 
7

 

 

Crude – Futures
2

 
2

 

 

Total commodity derivatives
428

 
346

 
82

 

Total assets
$
434

 
$
346

 
$
88

 
$

Liabilities:
 
 
 
 
 
 
 
Interest rate derivatives
$
(226
)
 
$

 
$
(226
)
 
$

Embedded derivatives in the Regency Preferred Units
(14
)
 

 

 
(14
)
Commodity derivatives:
 
 
 
 
 
 
 
Condensate — Forward Swaps
(1
)
 

 
(1
)
 

Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(10
)
 
(10
)
 

 

Swing Swaps IFERC
(4
)
 
(1
)
 
(3
)
 

Fixed Swaps/Futures
(293
)
 
(293
)
 

 

Natural Gas Liquids — Forwards/Swaps
(22
)
 
(22
)
 

 

Power:
 
 
 
 
 
 
 
Forwards
(4
)
 

 
(4
)
 

Futures
(3
)
 
(3
)
 

 

Options — Puts
(4
)
 
(4
)
 

 

Refined Products — Futures
(5
)
 
(5
)
 

 

Crude — Futures
(3
)
 
(3
)
 

 

Total commodity derivatives
(349
)
 
(341
)
 
(8
)
 

Total liabilities
$
(589
)
 
$
(341
)
 
$
(234
)
 
$
(14
)

12


 
Fair Value Measurements at
December 31, 2014
 
Fair Value
Total
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 
 
 
 
 
 
Interest rate derivatives
$
3

 
$

 
$
3

 
$

Commodity derivatives:
 
 
 
 
 
 
 
Condensate — Forward Swaps
36

 

 
36

 

Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
19

 
19

 

 

Swing Swaps IFERC
26

 
1

 
25

 

Fixed Swaps/Futures
566

 
541

 
25

 

Forward Physical Contracts
1

 

 
1

 

Power:
 
 
 
 
 
 
 
Forwards
3

 

 
3

 

Futures
4

 
4

 

 

Natural Gas Liquids — Forwards/Swaps
69

 
46

 
23

 

Refined Products — Futures
21

 
21

 

 

Total commodity derivatives
745

 
632

 
113

 

Total assets
$
748

 
$
632

 
$
116

 
$

Liabilities:
 
 
 
 
 
 
 
Interest rate derivatives
$
(155
)
 
$

 
$
(155
)
 
$

Embedded derivatives in the Regency Preferred Units
(16
)
 

 

 
(16
)
Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(18
)
 
(18
)
 

 

Swing Swaps IFERC
(25
)
 
(2
)
 
(23
)
 

Fixed Swaps/Futures
(490
)
 
(490
)
 

 

Power:
 
 
 
 
 
 
 
Forwards
(4
)
 

 
(4
)
 

Futures
(2
)
 
(2
)
 

 

Natural Gas Liquids — Forwards/Swaps
(32
)
 
(32
)
 

 

Refined Products — Futures
(7
)
 
(7
)
 

 

Total commodity derivatives
(578
)
 
(551
)
 
(27
)
 

Total liabilities
$
(749
)
 
$
(551
)
 
$
(182
)
 
$
(16
)
The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the three months ended March 31, 2015.
Balance, December 31, 2014
$
(16
)
Net unrealized gains included in other income (expense)
2

Balance, March 31, 2015
$
(14
)


13


7.
NET INCOME PER LIMITED PARTNER UNIT:
A reconciliation of income from continuing operations and weighted average units used in computing basic and diluted income from continuing operations per unit is as follows:
 
Three Months Ended
March 31,
 
2015
 
2014
Income from continuing operations
$
221

 
$
424

Less: Income from continuing operations attributable to noncontrolling interest
(63
)
 
259

Income from continuing operations, net of noncontrolling interest
284

 
165

Less: General Partner’s interest in income from continuing operations
1

 

Less: Class D Unitholder’s interest in income from continuing operations
1

 
1

Income from continuing operations available to Limited Partners
$
282

 
$
164

Basic Income from Continuing Operations per Limited Partner Unit:
 
 
 
Weighted average limited partner units
538.8

 
557.7

Basic income from continuing operations per Limited Partner unit
$
0.52

 
$
0.30

Basic income from discontinued operations per Limited Partner unit
$
0.00

 
$
0.00

Diluted Income from Continuing Operations per Limited Partner Unit:
 
 
 
Income from continuing operations available to Limited Partners
$
282

 
$
164

Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder
(1
)
 
(1
)
Diluted income from continuing operations available to Limited Partners
$
281

 
$
163

Weighted average limited partner units
538.8

 
557.7

Dilutive effect of unconverted unit awards
0.7

 
0.7

Weighted average limited partner units, assuming dilutive effect of unvested unit awards
539.5

 
558.4

Diluted income from continuing operations per Limited Partner unit
$
0.52

 
$
0.30

Diluted income from discontinued operations per Limited Partner unit
$
0.00

 
$
0.00

8.
DEBT OBLIGATIONS:
Parent Company Indebtedness
The Parent Company’s indebtedness, including its senior notes, senior secured term loan and senior secured revolving credit facility, is secured by all of its and certain of its subsidiaries’ tangible and intangible assets.
ETE Term Loan Facility
In March 2015, the Parent Company entered into a Senior Secured Term Loan C Agreement (the “ETE Term Loan C Agreement” and, together with the Parent Company’s other term loan agreements, the “ETE Term Loan Facility”), which increased the aggregate principal amount under the ETE Term Loan Facility to $2.25 billion, an increase of $850 million. The Parent Company used the proceeds (i) to fund the cash consideration for the Bakken Pipeline Transaction, (ii) to repay amounts outstanding under the Partnership’s revolving credit facility, and (iii) to pay transaction fees and expenses related to the Bakken Pipeline Transaction, the Term Loan Facility and other transactions incidental thereto. Under the ETE Term Loan C Agreement, interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of the Parent Company for each interest period. The applicable margin for LIBOR rate loans is 3.25% and the applicable margin for base rate loans is 2.25%.
Revolving Credit Facility
The Parent Company’s revolving credit facility has a capacity of $1.5 billion. As of March 31, 2015, there were $925 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $575 million.

14


Senior Notes
The Parent Company currently has outstanding an aggregate of $1.19 billion in principal amount of 7.5% senior notes due 2020 and $1.15 billion in principal amount of 5.875% senior notes due 2024.
Subsidiary Indebtedness
ETP Senior Notes
In March 2015, ETP issued $1.0 billion aggregate principal amount of 4.05% senior notes due March 2025, $500 million aggregate principal amount of 4.90% senior notes due March 2035, and $1.0 billion aggregate principal amount of 5.15% senior notes due March 2045. ETP used the $2.48 billion net proceeds from the offering to pay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes.
Sunoco LP Senior Notes
In April 2015, Sunoco LP issued $800 million aggregate principal amount of 6.375% senior notes due April 2023. The net proceeds from the offering were used to fund the cash portion of the dropdown of Sunoco, LLC interests.
Subsidiary Credit Facilities
ETP Credit Facility
The ETP Credit Facility allows for borrowings of up to $3.75 billion and expires in November 2019. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of ETP’s current and future unsecured debt. As of March 31, 2015, the ETP Credit Facility had no outstanding borrowings.
On April 30, 2015, ETP borrowed $1.5 billion under the ETP Credit Facility to partially fund the repayment of the Regency Credit Facility.
Regency Credit Facility
The Regency Credit Facility allowed for borrowings of $2.5 billion and would have expired on November 25, 2019. As of March 31, 2015, the Regency Credit Facility had a balance outstanding of $2.09 billion in outstanding borrowings and approximately $16 million in letters of credit. On April 30, 2015, in connection with the Regency Merger, the Regency Credit Facility was paid off in full and terminated.
Sunoco Logistics Credit Facilities
In March 2015, Sunoco Logistics amended and restated its $1.5 billion unsecured credit facility, which was scheduled to mature in November 2018. The amended and restated credit facility is a $2.5 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $3.25 billion under certain conditions. As of March 31, 2015, the Sunoco Logistics Credit Facility had $350 million of outstanding borrowings.
Sunoco LP Credit Facility
Sunoco LP maintains a $1.25 billion revolving credit facility (the “Sunoco LP Credit Facility”), which expires in September 2019. The Sunoco LP Credit Facility can be increased from time to time upon Sunoco LP’s written request, subject to certain conditions, up to an additional $250 million. As of March 31, 2015, the Sunoco LP Credit Facility had $685 million of outstanding borrowings.
In April 2015, Sunoco LP amended the Sunoco LP Credit Facility to allow for borrowings of up to $1.5 billion.
Compliance with Our Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of March 31, 2015.
9.
REDEEMABLE NONCONTROLLING INTERESTS:
The noncontrolling interest holders in one of Sunoco Logistics’ consolidated subsidiaries have the option to sell their interests to Sunoco Logistics. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on our consolidated balance sheets.

15


10.
EQUITY:
ETE Common Unit Activity
The change in ETE Common Units during the three months ended March 31, 2015 was as follows:
 
Number of
Units
Outstanding at December 31, 2014
538.8

Conversion of Class D Units to ETE Common Units
0.5

Outstanding at March 31, 2015
539.3

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.
Sales of Common Units by ETP
During the three months ended March 31, 2015, ETP received proceeds of $76 million, net of commissions of $1 million, from the issuance of units pursuant to equity distribution agreements, which were used for general partnership purposes. As of March 31, 2015, approximately $1.33 billion of ETP Common Units remained available to be issued under an equity distribution agreement.
During the three months ended March 31, 2015, distributions of $59 million were reinvested under ETP’s Distribution Reinvestment Plan resulting in the issuance of 1.0 million ETP Common Units. As of March 31, 2015, a total of 6.3 million ETP Common Units remain available to be issued under the existing registration statement.
ETP Class H and Class I Units
In March 2015, ETE transferred 30.8 million ETP Common Units, ETE’s 45% interest in the Bakken pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics. In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. The IDR subsidies from ETE to ETP, including the impact from distributions on ETP Class I Units, will be reduced by $55 million in 2015 and $30 million in 2016.
The impact of (i) the IDR subsidy adjustments and (ii) the ETP Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “ETP Quarterly Distributions of Available Cash.”
Sales of Common Units by Regency
In January 2015, Regency entered into an equity distribution agreement with another group of banks and investment companies under which Regency may offer and sell common units for an aggregate offering price of up to $1 billion.
For the three months ended March 31, 2015, Regency received proceeds of $34 million from units issued pursuant to its equity distribution agreements, which proceeds were used for general partnership purposes. Regency did not issue any common units under the distribution agreement subsequent to March 31, 2015, and the equity distribution agreement terminated as a result of the merger with ETP in April 2015.
Sales of Common Units by Sunoco Logistics
In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. During the three months ended March 31, 2015, Sunoco Logistics received proceeds of $142 million, net of commissions of $1 million, which were used for general partnership purposes.
Additionally, Sunoco Logistics completed a public offering of 13.5 million common units for net proceeds of $547 million in March 2015. The net proceeds from this offering were used to repay outstanding borrowings under the $2.5 billion Sunoco

16


Logistics Credit Facility and for general partnership purposes. In April 2015, an additional 2.0 million common units were issued for net proceeds of $82 million related to the exercise of an option in connection with the March 2015 offering.
Parent Company Quarterly Distributions of Available Cash
Following are distributions declared and/or paid by us subsequent to December 31, 2014:
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
December 31, 2014
 
February 6, 2015
 
February 19, 2015
 
$
0.4500

March 31, 2015
 
May 8, 2015
 
May 19, 2015
 
0.4900

ETP Quarterly Distributions of Available Cash
Following are distributions declared and/or paid by ETP subsequent to December 31, 2014:
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
December 31, 2014
 
February 6, 2015
 
February 13, 2015
 
$
0.9950

March 31, 2015
 
May 8, 2015
 
May 15, 2015
 
1.0150

In connection with previous transactions, including the Regency Merger, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on ETP Class I Units.
 
 
Total Year
2015 (remainder)
 
$
84

2016
 
137

2017
 
145

2018
 
140

2019
 
130

2020
 
35

2021
 
35

2022
 
35

2023
 
35

2024
 
18

Regency Quarterly Distributions of Available Cash
Following are distributions declared and/or paid by Regency subsequent to December 31, 2014:
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
December 31, 2014
 
February 6, 2015
 
February 13, 2015
 
$
0.5025

ETP’s acquisition of Regency closed on April 30, 2015; therefore, no distributions in relation to the quarter ended March 31, 2015 will be paid by Regency.
Sunoco Logistics Quarterly Distributions of Available Cash
Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2014:
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
December 31, 2014
 
February 9, 2015
 
February 13, 2015
 
$
0.4000

March 31, 2015
 
May 11, 2015
 
May 15, 2015
 
0.4190


17


Sunoco LP Quarterly Distributions of Available Cash
Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2014:
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
December 31, 2014
 
February 17, 2015
 
February 27, 2015
 
$
0.6000

March 31, 2015
 
May 19, 2015
 
May 29, 2015
 
0.6450

Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
 
March 31,
2015
 
December 31, 2014
Available-for-sale securities
$
4

 
$
3

Foreign currency translation adjustment
(5
)
 
(3
)
Net loss on commodity related hedges

 
(1
)
Actuarial loss related to pensions and other postretirement benefits
(12
)
 
(57
)
Investments in unconsolidated affiliates, net

 
2

Subtotal
(13
)
 
(56
)
Amounts attributable to noncontrolling interest
8

 
51

Total AOCI, net of tax
$
(5
)
 
$
(5
)
11.
INCOME TAXES:
For the three months ended March 31, 2015, the Partnership’s income tax expense from continuing operations included favorable state income tax adjustments of $14 million. For the three months ended March 31, 2014, the Partnership’s income tax expense from continuing operations included unfavorable income tax adjustments of $85 million related to the Lake Charles LNG Transaction, which was treated as a sale for tax purposes.
During the three months ended March 31, 2015, Sunoco received a notice of disallowance denying previously filed refund claims related to certain government incentive payments. However, Sunoco intends to file a refund suit with the United States Court of Federal Claims or the United States District Court having jurisdiction. In preparation for filing its complaint to the Court, Sunoco formalized its claims by filing amended Federal income tax returns with the Internal Revenue Service on March 10, 2015. The amended returns include an increase in the claims of $92 million, bringing the total claimed amount to $464 million. This increase relates primarily to the inclusion of certain tax years that were previously regarded as closed for purposes of calculating the potential refund. Consistent with prior treatment, Sunoco has established a reserve for the full amount of the increase due to the uncertain nature of the claims.
12.
REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus
Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million, representing the amount of the judgment, plus interest, in a case tried in 2011.
On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011.

18


FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs.
Contingent Residual Support Agreement — AmeriGas
In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchases.
Panhandle Holdings Guarantee of Collection
Panhandle guarantees the collections of the payment of $600 million of Regency 4.50% senior notes due 2023.
NGL Pipeline Regulation
ETP has interests in NGL pipelines located in Texas and New Mexico. ETP commenced the interstate transportation of NGLs in 2013, which is subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariff rates must be just and reasonable and not unduly discriminatory and pipelines may not confer any undue preference. The tariff rates established for interstate services were based on a negotiated agreement; however, the FERC’s rate-making methodologies may limit ETP’s ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect ETP’s business, revenues and cash flow.
Transwestern Rate Case
On October 1, 2014, Transwestern filed a general NGA Section 4 rate case pursuant to a 2011 settlement agreement with its shippers.  On December 2, 2014, the FERC issued an order accepting and suspending the rates to be effective April 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in August 2015.
FGT Rate Case
On October 31, 2014, FGT filed a general NGA Section 4 rate case pursuant to a 2010 settlement agreement with its shippers. On November 28, 2014, the FERC issued an order accepting and suspending the rates to be effective May 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in late 2015.
Commitments
In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and we enter into long-term transportation and storage agreements.  Such contracts contain terms that are customary in the industry.  We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058.  The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
 
Three Months Ended
March 31,
 
2015
 
2014
Rental expense(1)
$
52

 
$
32

Less: Sublease rental income
(8
)
 
(8
)
Rental expense, net
$
44

 
$
24

(1) 
Includes contingent rentals totaling $4 million and $3 million for the three months ended March 31, 2015 and 2014, respectively.

19


Certain of our subsidiaries’ joint venture agreements require that they fund their proportionate shares of capital contributions to their unconsolidated affiliates.  Such 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 crude oil are flammable and combustible.  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.
MTBE Litigation
Sunoco, Inc., along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater.  The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities.  The plaintiffs are asserting primarily product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices.  The plaintiffs in all of the cases are seeking to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.
As of March 31, 2015, Sunoco, Inc. is a defendant in five cases, including cases initiated by the States of New Jersey, Vermont, the Commonwealth of Pennsylvania, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico and Pennsylvania cases assert natural resource damage claims.
Fact discovery has concluded with respect to an initial set of 19 sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. Insufficient information has been developed about the plaintiffs’ legal theories or the facts with respect to statewide natural resource damage claims to provide an analysis of the ultimate potential liability of Sunoco, Inc. in these matters. It is reasonably possible that a loss may be realized; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that an adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position.
Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation
On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.  The jury also found that ETP owed Enterprise approximately $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims.  Enterprise has filed a notice of appeal. In accordance with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed.
Other Litigation and Contingencies
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 March 31, 2015 and December 31, 2014, accruals of approximately $39 million and $37 million, respectively, were reflected on our balance sheets related to these contingent

20


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.  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. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.
No amounts have been recorded in our March 31, 2015 or December 31, 2014 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
Attorney General of the Commonwealth of Massachusetts v. New England Gas Company.
On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries.  The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities.  In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including:  (i) the prudence of any and all legal fees, totaling approximately $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Southern Union former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery.  Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel.  The hearing officer has deferred consideration of Southern Union’s motion to dismiss.  The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Panhandle (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses.
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.  Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, 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.
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 our 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, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.

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Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs.  PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
Currently operating Sunoco, Inc. retail sites.
Legacy sites related to Sunoco, Inc., that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.
Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”).  As of March 31, 2015, Sunoco, Inc. had been named as a PRP at approximately 51 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law.  Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site.  Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets.  In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers.  To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.
The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable.  Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
 
March 31,
2015
 
December 31, 2014
Current
$
48

 
$
41

Non-current
340

 
360

Total environmental liabilities
$
388

 
$
401

In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
During the three months ended March 31, 2015 and 2014, the Partnership recorded $7 million and $8 million, respectively, of expenditures related to environmental cleanup programs.
On June 29, 2011, the U.S. Environmental Protection Agency finalized a rule under the Clean Air Act 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 us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if we replace equipment or expand existing facilities in the future.  At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future.
Our pipeline operations are subject to regulation by the U.S. Department of Transportation under the 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

22


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.  Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
Our operations are also subject to the requirements of the 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.
13.
PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity 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 operating entity.
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). ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, ETP locks 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 values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP 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 ETP’s 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 we enter the winter months, the spread converges so that ETP recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.
ETP is also exposed to market risk on natural gas it retains for fees in ETP’s intrastate transportation and storage segment and operational gas sales on ETP’s interstate transportation and storage segment. 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 statement of operations.
ETP is also exposed to commodity price risk on NGLs and residue gas it retains for fees in ETP’s midstream segment whereby ETP’s subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. ETP uses NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. 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 statement of operations.
ETP may use derivatives in ETP’s liquids transportation and services segment to manage ETP’s storage facilities and the purchase and sale of purity NGLs.

23


Sunoco Logistics utilizes derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products, crude and NGLs. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing Sunoco Logistics to transfer this price risk to counterparties who are able and willing to bear it. Sunoco Logistics does not designate any of its derivative contracts as hedges for accounting purposes. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period.
ETP also uses derivatives to hedge a variety of price risks in its retail marketing operations. Futures and swaps are used to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs. The derivatives used in ETP’s retail marketing operations represent economic hedges; however, ETP has elected not to designate any of these derivative contracts as hedges in these operations. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period.
ETP’s trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to ETP’s transportation and storage segment’s operations and are netted in cost of products sold in the consolidated statements of operations. Additionally, ETP also has trading and marketing activities related to power and natural gas in its other operations which are also netted in cost of products sold. As a result of ETP’s trading activities and the use of derivative financial instruments in ETP’s transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. ETP attempts to manage this volatility through the use of daily position and profit and loss reports provided to ETP’s risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in ETP’s commodity risk management policy.

24


The following table details ETP’s outstanding commodity-related derivatives:
 
March 31, 2015
 
December 31, 2014
 
Notional
Volume
 
Maturity
 
Notional
Volume
 
Maturity
Mark-to-Market Derivatives
 
 
 
 
 
 
 
(Trading)
 
 
 
 
 
 
 
Natural Gas (MMBtu):
 
 
 
 
 
 
 
Fixed Swaps/Futures
775,000

 
2015
 
(232,500
)
 
2015
Basis Swaps IFERC/NYMEX (1)
3,842,500

 
2015-2016
 
(13,907,500
)
 
2015-2016
Options – Calls
5,000,000

 
2015
 
5,000,000

 
2015
Power (Megawatt):
 
 
 
 
 
 
 
Forwards
225,131

 
2015
 
288,775

 
2015
Futures
168,992

 
2015
 
(156,000
)
 
2015
Options — Puts
(177,942
)
 
2015
 
(72,000
)
 
2015
Options — Calls
1,742,117

 
2015
 
198,556

 
2015
(Non-Trading)
 
 
 
 
 
 
 
Natural Gas (MMBtu):
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
13,292,500

 
2015-2016
 
57,500

 
2015
Swing Swaps IFERC
51,465,000

 
2015-2016
 
46,150,000

 
2015
Fixed Swaps/Futures
1,705,000

 
2015-2016
 
(8,779,000
)
 
2015-2016
Forward Physical Contracts
23,903,779

 
2015
 
(9,116,777
)
 
2015
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps
(768,100
)
 
2015-2016
 
(2,179,400
)
 
2015
Refined Products (Bbls) — Futures
(1,019,000
)
 
2015
 
13,745,755

 
2015
Fair Value Hedging Derivatives
 
 
 
 
 
 
 
(Non-Trading)
 
 
 
 
 
 
 
Natural Gas (MMBtu):
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(23,295,000
)
 
2016
 
(39,287,500
)
 
2015
Fixed Swaps/Futures
(23,475,000
)
 
2016
 
(39,287,500
)
 
2015
Hedged Item — Inventory
23,475,000

 
2016
 
39,287,500

 
2015
(1) 
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
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.
Commodity Derivative Instruments - Marketing & Trading. Regency conducts natural gas marketing and trading activities through its Logistics and Trading subsidiary. Regency engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. Regency’s activities are governed by its risk policy. As part of its natural gas marketing and trading activities, Regency enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by

25


removing index spread risk on the combined physical and financial transaction. Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales. Through Regency’s natural gas marketing activity, Regency will have credit exposure to additional counterparties. Regency minimizes the credit risk associated with natural gas marketing by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, Regency’s natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, Regency nets the open positions of each counterparty.
The following table details Regency’s outstanding commodity-related derivatives:
 
March 31, 2015
 
December 31, 2014
 
Notional
Volume
 
Maturity
 
Notional
Volume
 
Maturity
Mark-to-Market Derivatives
 
 
 
 
 
 
 
(Non-Trading)
 
 
 
 
 
 
 
Natural Gas (MMBtu) — Fixed Swaps/Futures
(17,875,000
)
 
2015
 
(25,525,000
)
 
2015
Propane (Gallons) — Forwards/Swaps
(21,966,000
)
 
2015
 
(29,148,000
)
 
2015
NGLs (Barrels) — Forwards/Swaps
(220,000
)
 
2015
 
(292,000
)
 
2015
WTI Crude Oil (Barrels) — Forwards/Swaps
(1,060,000
)
 
2015-2016
 
(1,252,000
)
 
2015-2016
Regency had swap contracts settled against certain NGLs, condensate and natural gas market prices. In April 2015, Regency terminated all outstanding swap contracts and received net proceeds of $56 million.
Interest Rate Risk
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and floating rate debt. We also manage our interest rate exposures by utilizing interest rate swaps to achieve a desired mix of fixed and floating rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of anticipated debt issuances.

26


The following table summarizes our interest rate swaps outstanding none of which were designated as hedges for accounting purposes:
 
 
 
 
 
 
Notional Amount
Outstanding
Entity
 
Term
 
Type(1)
 
March 31,
2015
 
December 31, 2014
ETP
 
July 2015(2)
 
Forward-starting to pay a fixed rate of 3.40% and receive a floating rate
 
$
100

 
$
200

ETP
 
July 2016(3)
 
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
 
200

 
200

ETP
 
July 2017(4)
 
Forward-starting to pay a fixed rate of 3.84% and receive a floating rate
 
300

 
300

ETP
 
July 2018(4)
 
Forward-starting to pay a fixed rate of 4.00% and receive a floating rate
 
200

 
200

ETP
 
July 2019(4)
 
Forward-starting to pay a fixed rate of 3.01% and receive a floating rate
 
500

 
300

ETP
 
March 2019
 
Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.53%
 
600

 

ETP
 
February 2023
 
Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60%
 

 
200

(1) 
Floating rates are based on 3-month LIBOR.
(2) 
Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.
(3) 
Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.
(4) 
Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.
Credit Risk
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern ETP’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, ETP may at times require collateral under certain circumstances to mitigate credit risk as necessary. ETP also implements the use of industry standard commercial agreements which allow for the netting of positive and negative exposures associated with transactions executed under a single commercial agreement. Additionally, ETP utilizes master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
ETP’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, utilities and midstream companies. ETP’s overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that could impact its counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
ETP has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to ETP on or about the settlement date for non-exchange traded derivatives, and 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 the consolidated balance sheets.
Regency is exposed to credit risk from its derivative counterparties. Regency does not require collateral from these counterparties as it deals primarily with financial institutions when entering into financial derivatives, and enters into master

27


netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If Regency’s counterparties failed to perform under existing swap contracts, Regency’s maximum loss as of March 31, 2015 would be $72 million, which would be reduced by $1 million, due to the netting features. Regency has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets for it derivate contracts outside of its marketing and trading operations.
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.
Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
 
Fair Value of Derivative Instruments
 
Asset Derivatives
 
Liability Derivatives
 
March 31, 2015
 
December 31, 2014
 
March 31, 2015
 
December 31, 2014
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Commodity derivatives (margin deposits)
$
3

 
$
43

 
$

 
$

 
3

 
43

 

 

Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity derivatives (margin deposits)
$
347

 
$
617

 
$
(346
)
 
$
(577
)
Commodity derivatives
94

 
107

 
(19
)
 
(23
)
Interest rate derivatives
6

 
3

 
(226
)
 
(155
)
Embedded derivatives in Regency Preferred Units

 

 
(14
)
 
(16
)
 
447

 
727

 
(605
)
 
(771
)
Total derivatives
$
450

 
$
770

 
$
(605
)
 
$
(771
)
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
 
 
 
 
Asset Derivatives
 
Liability Derivatives
 
 
Balance Sheet Location
 
March 31, 2015
 
December 31, 2014
 
March 31, 2015
 
December 31, 2014
Derivatives in offsetting agreements:
 
 
 
 
 
 
 
 
OTC contracts
 
Price risk management asset (liability)
 
$
20