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EX-32.2 - EXHIBIT 32.2 - Energy Transfer, LPetp-03x31x2016xexx322.htm
EX-32.1 - EXHIBIT 32.1 - Energy Transfer, LPetp-03x31x2016xexx321.htm
EX-31.2 - EXHIBIT 31.2 - Energy Transfer, LPetp-03x31x2016xexx312.htm
EX-31.1 - EXHIBIT 31.1 - Energy Transfer, LPetp-03x31x2016xexx311.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, 2016
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-11727
ENERGY TRANSFER PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
Delaware
 
73-1493906
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
8111 Westchester Drive, Suite 600, Dallas, Texas 75225
(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 April 29, 2016, the registrant had 518,715,341 Common Units outstanding.
 



FORM 10-Q
ENERGY TRANSFER PARTNERS, 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 Partners, L.P. (the “Partnership,” or “ETP”) in periodic press releases and some oral statements of the Partnership’s officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its general partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations, or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, projected or expected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I – Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2015 filed with the Securities and Exchange Commission on February 29, 2016.
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
 
 
 
 
Btu
 
British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used
 
 
 
 
Capacity
 
capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels
 
 
 
 
 
Citrus
 
Citrus, LLC
 
 
 
 
 
CrossCountry
 
CrossCountry Energy, LLC
 
 
 
 
 
ETC Compression
 
ETC Compression, LLC
 
 
 
 
 
ETC FEP
 
ETC Fayetteville Express Pipeline, LLC
 
 
 
 
 
ETC MEP
 
ETC Midcontinent Express Pipeline, L.L.C.
 
 
 
 
 
ETC OLP
 
La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
 
 
 
 
 
ETC Tiger
 
ETC Tiger Pipeline, LLC
 
 
 
 
 
ETE
 
Energy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC
 
 
 
 
 
ET Interstate
 
Energy Transfer Interstate Holdings, LLC
 
 
 
 
 
ET Rover
 
ET Rover Pipeline LLC
 
 
 
 
 
ETP Credit Facility
 
ETP’s $3.75 billion revolving credit facility
 
 
 
 
 
ETP GP
 
Energy Transfer Partners GP, L.P., the general partner of ETP
 
 
 
 
 
ETP Holdco
 
ETP Holdco Corporation
 
 
 
 
 
ETP LLC
 
Energy Transfer Partners, L.L.C., the general partner of ETP GP
 
 
 
 
Exchange Act
 
Securities Exchange Act of 1934
 
 
 
 
 
FEP
 
Fayetteville Express Pipeline LLC
 
 
 
 
 
FERC
 
Federal Energy Regulatory Commission


ii


 
 
 
 
 
FGT
 
Florida Gas Transmission Company, LLC
 
 
 
 
 
GAAP
 
accounting principles generally accepted in the United States of America
 
 
 
 
 
HPC
 
RIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP
 
 
 
 
 
IDRs
 
incentive distribution rights
 
 
 
 
 
Lake Charles LNG
 
Lake Charles LNG Company, LLC (previously named Trunkline LNG Company, LLC), a subsidiary of ETE
 
 
 
 
 
LIBOR
 
London Interbank Offered Rate
 
 
 
 
 
LNG
 
liquefied natural gas
 
 
 
 
 
Lone Star
 
Lone Star NGL LLC
 
 
 
 
 
MEP
 
Midcontinent Express Pipeline LLC
 
 
 
 
 
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 and its subsidiaries
 
 
 
 
 
PCBs
 
polychlorinated biphenyls
 
 
 
 
 
PES
 
Philadelphia Energy Solutions
 
 
 
 
 
PHMSA
 
Pipeline Hazardous Materials Safety Administration
 
 
 
 
 
Preferred Units
 
ETP Series A cumulative convertible preferred units
 
 
 
 
 
Regency
 
Regency Energy Partners LP
 
 
 
 
 
Retail Holdings
 
ETP Retail Holdings, LLC, a joint venture between subsidiaries of ETC OLP and Sunoco, Inc.
 
 
 
 
 
Sea Robin
 
Sea Robin Pipeline Company, LLC, a subsidiary of Panhandle
 
 
 
 
 
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)
 
 
 
 
 
Transwestern
 
Transwestern Pipeline Company, LLC
 
 
 
 
 
Trunkline
 
Trunkline Gas Company, LLC, a subsidiary of Panhandle
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, losses on extinguishments 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 PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)
 
March 31, 2016
 
December 31, 2015
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
715

 
$
527

Accounts receivable, net
2,080

 
2,118

Accounts receivable from related companies
173

 
268

Inventories
1,147

 
1,213

Derivative assets
24

 
40

Other current assets
620

 
532

Total current assets
4,759

 
4,698

 
 
 
 
Property, plant and equipment
51,761

 
50,869

Accumulated depreciation and depletion
(5,974
)
 
(5,782
)
 
45,787

 
45,087

 
 
 
 
Advances to and investments in unconsolidated affiliates
5,020

 
5,003

Non-current derivative assets
16

 

Other non-current assets, net
514

 
536

Intangible assets, net
4,080

 
4,421

Goodwill
4,139

 
5,428

Total assets
$
64,315

 
$
65,173


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


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)
 
March 31, 2016
 
December 31, 2015
LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
2,002

 
$
1,859

Accounts payable to related companies
46

 
25

Derivative liabilities
74

 
63

Accrued and other current liabilities
1,864

 
2,048

Current maturities of long-term debt
925

 
126

Total current liabilities
4,911

 
4,121

 
 
 
 
Long-term debt, less current maturities
26,769

 
28,553

Long-term notes payable – related company
223

 
233

Non-current derivative liabilities
213

 
137

Deferred income taxes
4,495

 
4,082

Other non-current liabilities
939

 
968

 
 
 
 
Commitments and contingencies

 

Series A Preferred Units
33

 
33

Redeemable noncontrolling interests
15

 
15

 
 
 
 
Equity:
 
 
 
General Partner
314

 
306

Limited Partners:
 
 
 
Common Unitholders
16,343

 
17,043

Class H Unitholder
3,471

 
3,469

Class I Unitholder
2

 
14

Accumulated other comprehensive income (loss)
(10
)
 
4

Total partners’ capital
20,120

 
20,836

Noncontrolling interest
6,597

 
6,195

Total equity
26,717

 
27,031

Total liabilities and equity
$
64,315

 
$
65,173


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


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
(unaudited)
 
Three Months Ended
March 31,
 
2016
 
2015
REVENUES:
 
 
 
Natural gas sales
$
838

 
$
1,034

NGL sales
940

 
981

Crude sales
1,210

 
2,208

Gathering, transportation and other fees
960

 
993

Refined product sales
245

 
3,656

Other
288

 
1,454

Total revenues
4,481

 
10,326

COSTS AND EXPENSES:
 
 
 
Cost of products sold
2,968

 
8,496

Operating expenses
348

 
610

Depreciation, depletion and amortization
470

 
479

Selling, general and administrative
81

 
133

Total costs and expenses
3,867

 
9,718

OPERATING INCOME
614

 
608

OTHER INCOME (EXPENSE):
 
 
 
Interest expense, net
(319
)
 
(310
)
Equity in earnings of unconsolidated affiliates
76

 
57

Losses on interest rate derivatives
(70
)
 
(77
)
Other, net
17

 
7

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)
318

 
285

Income tax expense (benefit)
(58
)
 
17

NET INCOME
376

 
268

Less: Net income (loss) attributable to noncontrolling interest
65

 
(6
)
Less: Net loss attributable to predecessor

 
(7
)
NET INCOME ATTRIBUTABLE TO PARTNERS
311

 
281

General Partner’s interest in net income
297

 
242

Class H Unitholder’s interest in net income
79

 
54

Class I Unitholder’s interest in net income
2

 
33

Common Unitholders’ interest in net loss
$
(67
)
 
$
(48
)
NET LOSS PER COMMON UNIT:
 
 
 
Basic
$
(0.15
)
 
$
(0.17
)
Diluted
$
(0.15
)
 
$
(0.17
)

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


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
(unaudited)
 
Three Months Ended
March 31,
 
2016
 
2015
Net income
$
376

 
$
268

Other comprehensive income (loss), net of tax:
 
 
 
Change in value of derivative instruments accounted for as cash flow hedges

 
1

Change in value of available-for-sale securities
2

 
1

Actuarial gain (loss) relating to pension and other postretirement benefit plans
(9
)
 
45

Foreign currency translation adjustments
(1
)
 
(2
)
Change in other comprehensive income from unconsolidated affiliates
(6
)
 
(2
)
 
(14
)
 
43

Comprehensive income
362

 
311

Less: Comprehensive income (loss) attributable to noncontrolling interest
65

 
(6
)
Less: Comprehensive loss attributable to predecessor

 
(7
)
Comprehensive income attributable to partners
$
297

 
$
324


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


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF EQUITY
FOR THE THREE MONTHS ENDED MARCH 31, 2016
(Dollars in millions)
(unaudited)
 
 
 
Limited Partners
 
 
 
 
 
 
 
General Partner
 
Common Units
 
Class H Units
 
Class I Units
 
Accumulated Other Comprehensive Income (Loss)
 
Noncontrolling Interest
 
Total
Balance, December 31, 2015
$
306

 
$
17,043

 
$
3,469

 
$
14

 
$
4

 
$
6,195

 
$
27,031

Distributions to partners
(289
)
 
(517
)
 
(77
)
 
(14
)
 

 

 
(897
)
Distributions to noncontrolling interest

 

 

 

 

 
(100
)
 
(100
)
Units issued for cash

 
363

 

 

 

 

 
363

Subsidiary units issued for cash

 
5

 

 

 

 
296

 
301

Capital contributions from noncontrolling interest

 

 

 

 

 
132

 
132

Sunoco, Inc. retail business to Sunoco LP transaction

 
(496
)
 

 

 

 

 
(496
)
Other comprehensive income, net of tax

 

 

 

 
(14
)
 

 
(14
)
Other, net

 
12

 

 

 

 
9

 
21

Net income (loss)
297

 
(67
)
 
79

 
2

 

 
65

 
376

Balance, March 31, 2016
$
314

 
$
16,343

 
$
3,471

 
$
2

 
$
(10
)
 
$
6,597

 
$
26,717


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


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
(unaudited)
 
Three Months Ended
March 31,
 
2016
 
2015
OPERATING ACTIVITIES
 
 
 
Net income
$
376

 
$
268

Reconciliation of net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
470

 
479

Deferred income taxes
(57
)
 
26

Amortization included in interest expense
(7
)
 
(13
)
Inventory valuation adjustments
26

 
34

Unit-based compensation expense
19

 
20

Distributions on unvested awards
(7
)
 
(3
)
Equity in earnings of unconsolidated affiliates
(76
)
 
(57
)
Distributions from unconsolidated affiliates
84

 
64

Other non-cash
(12
)
 
(11
)
Net change in operating assets and liabilities, net of effects of acquisition
144

 
(207
)
Net cash provided by operating activities
960

 
600

INVESTING ACTIVITIES
 
 
 
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction
2,200

 

Proceeds from Bakken Pipeline Transaction

 
980

Proceeds from sale of noncontrolling interest

 
64

Cash paid for acquisition of a noncontrolling interest

 
(129
)
Cash paid for all other acquisitions

 
(370
)
Capital expenditures, excluding allowance for equity funds used during construction
(1,819
)
 
(2,149
)
Contributions in aid of construction costs
10

 
4

Contributions to unconsolidated affiliates
(31
)
 
(34
)
Distributions from unconsolidated affiliates in excess of cumulative earnings
51

 
34

Proceeds from the sale of assets
8

 
9

Change in restricted cash
(1
)
 

Other
(3
)
 
(6
)
Net cash provided by (used in) investing activities
415

 
(1,597
)
FINANCING ACTIVITIES
 
 
 
Proceeds from borrowings
2,938

 
7,039

Repayments of long-term debt
(3,914
)
 
(5,073
)
Units issued for cash
363

 
135

Subsidiary units issued for cash
301

 
689

Predecessor units issued for cash

 
34

Capital contributions from noncontrolling interest
132

 
219

Distributions to partners
(897
)
 
(558
)
Predecessor distributions to partners

 
(203
)
Distributions to noncontrolling interest
(100
)
 
(77
)
Debt issuance costs

 
(23
)
Other
(10
)
 

Net cash provided by (used in) financing activities
(1,187
)
 
2,182

Increase in cash and cash equivalents
188

 
1,185

Cash and cash equivalents, beginning of period
527

 
663

Cash and cash equivalents, end of period
$
715

 
$
1,848


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


ENERGY TRANSFER PARTNERS, 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
Organization
Energy Transfer Partners, L.P., a publicly traded Delaware master limited partnership, and its subsidiaries (collectively, the “Partnership,” “we,” “us,” “our” or “ETP”) are managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC. The consolidated financial statements of the Partnership presented herein include our operating subsidiaries described below.
Our activities are primarily conducted through our operating subsidiaries (collectively, the “Operating Companies”) as follows:
ETC OLP, a Texas limited partnership primarily 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 our 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 our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets.
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 FEP, 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, 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 MEP, a Delaware limited liability company that directly owns a 50% interest in MEP.
ETC Compression, 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 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. Sunoco, Inc. owned and operated retail marketing assets, which were contributed to Sunoco LP in March 2016, as discussed in Note 2. Subsequent to this transaction, Sunoco Inc.’s assets primarily consist of its ownership in Retail Holdings, which owns noncontrolling interests in Sunoco LP and PES.
Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary crude oil, NGLs, and refined products pipeline, terminalling, and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.
Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP LLC, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETE transferred to ETP 21 million ETP common units. These operations were reported within the retail marketing segment. In connection with this transaction, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method. Additionally, in March 2016 and as discussed in Note 2, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business.
Our financial statements reflect the following reportable business segments:
intrastate transportation and storage;


7


interstate transportation and storage;
midstream;
liquids transportation and services;
investment in Sunoco Logistics;
retail marketing; and
all other.
Basis of Presentation
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, 2015. 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.
Certain prior period amounts have been reclassified to conform to the current year presentation. These reclassifications had no impact on net income or total equity.
Merger with Regency. On April 30, 2015, a wholly-owned subsidiary of the Partnership merged with Regency, with Regency surviving as a wholly-owned subsidiary of the Partnership (the “Regency Merger”). The Regency Merger was a combination of entities under common control; therefore, Regency’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Regency for all prior periods subsequent to May 26, 2010 (the date ETE acquired Regency’s general partner).
Use of Estimates
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.
Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. In March 2016, FASB issued Accounting Standards Update No. 2016-08 to clarify the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued Accounting Standards Update No. 2016-10 to clarify guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.
In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“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. The Partnership adopted this standard on January 1, 2016, and the adoption did not impact the Partnership’s financial position or results of operations.
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. ASU 2016-02 is effective for fiscal years beginning


8


after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Partnership is currently evaluating the impact that it will have on the consolidated financial statements and related disclosures.
In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Stock Compensation (Topic 718) (“ASU 2016-09”). The objective of the update is to reduce complexity in accounting standards. The areas for simplification in this update involve several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. In addition, the amendments in this update eliminate the guidance in Topic 718 that was indefinitely deferred shortly after the issuance of FASB Statement No. 123 (revised 2004), Share-Based Payment. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that it will have on the consolidated financial statements and related disclosures.
2.
CONTRIBUTION TRANSACTION
Sunoco Retail to Sunoco LP
In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment, and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016. In connection with this transaction, the Partnership deconsolidated the legacy Sunoco, Inc. retail business, including goodwill of $1.29 billion and intangible assets of $294 million. The results of Sunoco LLC and the legacy Sunoco, Inc. retail business’ operations have not been presented as discontinued operations and Sunoco, Inc.’s retail business assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements.
3.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
The net change in operating assets and liabilities, net of acquisitions and deconsolidations, included in cash flows from operating activities is comprised as follows:
 
Three Months Ended
March 31,
 
2016
 
2015
Accounts receivable
$
(9
)
 
$
464

Accounts receivable from related companies
90

 
46

Inventories
(11
)
 
(35
)
Exchanges receivable
3

 
(1
)
Other current assets
(102
)
 
(115
)
Other non-current assets, net
11

 
35

Accounts payable
51

 
(487
)
Accounts payable to related companies
(2
)
 
(103
)
Exchanges payable
21

 
(28
)
Accrued and other current liabilities
(17
)
 
(179
)
Other non-current liabilities
21

 
118

Derivative assets and liabilities, net
88

 
78

Net change in operating assets and liabilities, net of effects of acquisition
$
144

 
$
(207
)


9


Non-cash investing and financing activities are as follows:

Three Months Ended
March 31,

2016
 
2015
NON-CASH INVESTING ACTIVITIES:
 
 
 
Accrued capital expenditures
$
826

 
$
658

Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP
194

 

Net gains from subsidiary common unit issuances
5

 
72

NON-CASH FINANCING ACTIVITIES:
 
 
 
Issuance of Class H Units in connection with the Bakken Pipeline Transaction
$

 
$
1,926

Redemption of common units in connection with the Bakken Pipeline Transaction

 
979

4.
INVENTORIES
Inventories consisted of the following:
 
March 31, 2016
 
December 31, 2015
Natural gas and NGLs
$
331

 
$
415

Crude oil
453

 
424

Refined products
132

 
104

Other
231

 
270

Total inventories
$
1,147

 
$
1,213

We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
5.
FAIR VALUE MEASURES
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 and carrying amount of our consolidated debt obligations as of March 31, 2016 was $25.49 billion and $27.69 billion, respectively. As of December 31, 2015, the aggregate fair value and carrying amount of our consolidated debt obligations was $25.71 billion and $28.68 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
We have commodity derivatives, interest rate derivatives and embedded derivatives in the Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider 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. Level 3 inputs are unobservable. Derivatives related to the embedded derivatives in our 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, 2016, no transfers were made between any levels within the fair value hierarchy.



10


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, 2016 and December 31, 2015 based on inputs used to derive their fair values:
 
 
 
Fair Value Measurements at
March 31, 2016
 
Fair Value Total
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 
 
 
 
 
 
Interest rate derivatives
$
25

 
$

 
$
25

 
$

Commodity derivatives:
 
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
6

 
6

 

 

Swing Swaps IFERC
1

 

 
1

 

Fixed Swaps/Futures
67

 
67

 

 

Forward Physical Swaps
3

 

 
3

 

Power:
 
 
 
 
 
 
 
Forwards
22

 

 
22

 

Futures
1

 
1

 

 

Options – Calls
2

 
2

 

 

Natural Gas Liquids – Forwards/Swaps
34

 
34

 

 

Refined Products – Futures
3

 
3

 

 

Crude – Futures
12

 
12

 

 

Total commodity derivatives
151

 
125

 
26

 

Total assets
$
176

 
$
125

 
$
51

 
$

Liabilities:
 
 
 
 
 
 
 
Interest rate derivatives
$
(267
)
 
$

 
$
(267
)
 
$

Embedded derivatives in the Preferred Units
(5
)
 

 

 
(5
)
Commodity derivatives:
 
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(9
)
 
(9
)
 

 

Swing Swaps IFERC
(2
)
 
(1
)
 
(1
)
 

Fixed Swaps/Futures
(50
)
 
(50
)
 

 

Power:
 
 
 
 
 
 
 
Forwards
(26
)
 

 
(26
)
 

Futures
(1
)
 
(1
)
 

 

Natural Gas Liquids – Forwards/Swaps
(33
)
 
(33
)
 

 

Refined Products – Futures
(4
)
 
(4
)
 

 

Crude – Futures
(5
)
 
(5
)
 

 

Total commodity derivatives
(130
)
 
(103
)
 
(27
)
 

Total liabilities
$
(402
)
 
$
(103
)
 
$
(294
)
 
$
(5
)


11


 
 
 
Fair Value Measurements at
December 31, 2015
 
Fair Value Total
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
$
16

 
$
16

 
$

 
$

Swing Swaps IFERC
10

 
2

 
8

 

Fixed Swaps/Futures
274

 
274

 

 

Forward Physical Swaps
4

 

 
4

 

Power:


 
 
 
 
 
 
Forwards
22

 

 
22

 

Futures
3

 
3

 

 

Options – Puts
1

 
1

 

 

Options – Calls
1

 
1

 

 

Natural Gas Liquids – Forwards/Swaps
99

 
99

 

 

Refined Products – Futures
9

 
9

 

 

Crude – Futures
9

 
9

 

 

Total commodity derivatives
448

 
414

 
34

 

Total assets
$
448

 
$
414

 
$
34

 
$

Liabilities:
 
 
 
 
 
 
 
Interest rate derivatives
$
(171
)
 
$

 
$
(171
)
 
$

Embedded derivatives in the Preferred Units
(5
)
 

 

 
(5
)
Commodity derivatives:
 
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(16
)
 
(16
)
 

 

Swing Swaps IFERC
(12
)
 
(2
)
 
(10
)
 

Fixed Swaps/Futures
(203
)
 
(203
)
 

 

Power:


 
 
 
 
 
 
Forwards
(22
)
 

 
(22
)
 

Futures
(2
)
 
(2
)
 

 

Options – Puts
(1
)
 
(1
)
 

 

Natural Gas Liquids – Forwards/Swaps
(89
)
 
(89
)
 

 

Crude – Futures
(5
)
 
(5
)
 

 

Total commodity derivatives
(350
)
 
(318
)
 
(32
)
 

Total liabilities
$
(526
)
 
$
(318
)
 
$
(203
)
 
$
(5
)
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, 2016.
Balance, December 31, 2015
$
(5
)
Net unrealized gains included in other income (expense)

Balance, March 31, 2016
$
(5
)
6.
NET LOSS PER LIMITED PARTNER UNIT
Net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to the General Partner, the holder of the IDRs pursuant to the Partnership Agreement, which


12


are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests. Loss attributable to predecessor represents amounts allocated to the former Regency partners and have no impact on net income (loss) per unit for the periods prior to the Regency Merger.
A reconciliation of net income and weighted average units used in computing basic and diluted net loss per unit is as follows:
 
Three Months Ended
March 31,
 
2016
 
2015
Net income
$
376

 
$
268

Less: Income (loss) attributable to noncontrolling interest
65

 
(6
)
Less: Loss attributable to predecessor

 
(7
)
Net income, net of noncontrolling interest and predecessor income
311

 
281

General Partner’s interest in net income
297

 
242

Class H Unitholder’s interest in net income
79

 
54

Class I Unitholder’s interest in net income
2

 
33

Common Unitholders’ interest in net loss
(67
)
 
(48
)
Additional earnings allocated to General Partner
(3
)
 
(2
)
Distributions on employee unit awards, net of allocation to General Partner
(5
)
 
(4
)
Net loss available to Common Unitholders
$
(75
)
 
$
(54
)
Weighted average Common Units – basic and diluted (1)
490.2

 
323.8

Basic net loss per Common Unit
$
(0.15
)
 
$
(0.17
)
Diluted net loss per Common Unit
$
(0.15
)
 
$
(0.17
)
(1)    Excludes Common Units owned by the Partnership’s consolidated subsidiaries.
7.
DEBT OBLIGATIONS
Revolving 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, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. As of March 31, 2016, the ETP Credit Facility had $4 million of outstanding borrowings.
Sunoco Logistics Credit Facilities
Sunoco Logistics maintains 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, 2016, the Sunoco Logistics Credit Facility had $942 million of outstanding borrowings.
Compliance with Our Covenants
We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of March 31, 2016.


13


8.
EQUITY
ETP
The changes in outstanding common units during the three months ended March 31, 2016 were as follows:
 
 
Number of Units
Number of common units at December 31, 2015
 
505.6

Common units issued in connection with equity distribution agreements
 
11.2

Common units issued in connection with the distribution reinvestment plan
 
1.8

Number of common units at March 31, 2016
 
518.6

During the three months ended March 31, 2016, the Partnership received proceeds of $324 million, net of $3 million commissions, from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes. As of March 31, 2016, none of the Partnership’s common units were available to be issued under an equity distribution agreement.
During the three months ended March 31, 2016, distributions of $39 million were reinvested under the distribution reinvestment plan. As of March 31, 2016, a total of 9.7 million common units remain available to be issued under the existing registration statement in connection with the distribution reinvestment plan.
Sunoco Logistics
During the three months ended March 31, 2016, Sunoco Logistics received proceeds of $301 million, net of $3 million commissions, from the issuance of Sunoco Logistics common units pursuant to equity distribution agreements, which were used for general partnership purposes. As a result of Sunoco Logistics’ issuances of common units during the three months ended March 31, 2016, the Partnership recognized increases in partners’ capital of $5 million.
Quarterly Distributions of Available Cash
Following are distributions declared and/or paid by the Partnership subsequent to December 31, 2015:
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
December 31, 2015
 
February 8, 2016
 
February 16, 2016
 
$
1.0550

March 31, 2016
 
May 6, 2016
 
May 16, 2016
 
1.0550

ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on Class I Units.
 
 
Total Year
2016 (remainder)
 
$
103

2017
 
128

2018
 
105

2019
 
95

Sunoco Logistics Quarterly Distributions of Available Cash
Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2015:
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
December 31, 2015
 
February 8, 2016
 
February 12, 2016
 
$
0.4790

March 31, 2016
 
May 9, 2016
 
May 13, 2016
 
0.4890



14


Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
 
March 31, 2016
 
December 31, 2015
Available-for-sale securities
$
2

 
$

Foreign currency translation adjustment
(5
)
 
(4
)
Net loss on interest rate derivative hedges
(6
)
 

Actuarial gain related to pensions and other postretirement benefits
(1
)
 
8

Total AOCI, net of tax
$
(10
)
 
$
4

9.
INCOME TAXES
For the three months ended March 31, 2016, the Partnership’s effective income tax rate decreased from the prior year primarily due to lower earnings among the Partnership’s consolidated corporate subsidiaries. The three months ended March 31, 2016 also reflected a benefit of $20 million of net state tax benefit attributable to statutory state rate changes resulting from the contribution by ETP to Sunoco LP of its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business.
10.
REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
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 purchasers.
ETP Retail Holdings Guarantee of Sunoco LP Notes
Retail Holdings has provided a guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019.
NGL Pipeline Regulation
We have interests in NGL pipelines located in Texas and New Mexico. We 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 our 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 our business, revenues and cash flow.
FERC Audit
In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. 
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.


15


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,
 
2016
 
2015
Rental expense(1)
$
18

 
$
52

Less: Sublease rental income

 
(8
)
Rental expense, net
$
18

 
$
44

(1) 
Includes contingent rentals totaling $14 million and $4 million for the three months ended March 31, 2016 and 2015, respectively.
Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our 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 primarily assert 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 seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.
As of March 31, 2016, Sunoco, Inc. is a defendant in five cases, including cases initiated by the States of New Jersey, Vermont, 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, Vermont, 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.
Regency Merger Litigation
Following the January 26, 2015 announcement of the definitive merger agreement with Regency, purported Regency unitholders filed lawsuits in state and federal courts in Dallas, Texas and Delaware state court asserting claims relating to the proposed transaction. All Regency merger related lawsuits have been dismissed, though one lawsuit remains pending on


16


appeal. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the Court of Chancery of the State of Delaware. The lawsuit alleges that the transaction did not comply with the Regency partnership agreement because the conflicts committee was not properly formed. Defendants filed a motion to dismiss, and on March 29, 2016, the Delaware court granted Defendants’ motion and dismissed the lawsuit. On April 26, 2016, Plaintiff filed its Notice of Appeal to the Supreme Court of Delaware. This appeal is styled Adrian Dieckman v. Regency GP LP, et al., No. 208, 2016, in the Supreme Court of the State of Delaware.
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 with the Texas Court of Appeals, and briefing by Enterprise and ETP is complete. Oral argument was held on April 20, 2016. The Court of Appeals is taking the briefs under advisement. 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, 2016 and December 31, 2015, accruals of approximately $59 million and $40 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. 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, 2016 or December 31, 2015 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.


17


Compliance Orders from the New Mexico Environmental Department
Regency received a Notice of Violation from the New Mexico Environmental Department on September 23, 2015 for allegations of violations of New Mexico air regulations related to Jal #3. The Partnership has accrued $250,000 related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses.
Lone Star NGL Fractionators Notice of Enforcement
Lone Star NGL Fractionators received a Notice of Enforcement from the Texas Commission on Environmental Quality on August 28, 2015 for allegations of violations of Texas air regulations related to its Mont Belvieu Gas Plant. The Partnership has accrued $300,000 related to the claim. As of April 2016, the Agreed Order is in the approval process with the Texas Commission on Environmental Quality and includes a $21,000 penalty and a $21,000 Supplemental Environmental Project. 
Environmental Matters
Our operations are subject to extensive federal, tribal, 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 investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas 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.
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, 2016, Sunoco, Inc. had been named as a PRP at approximately 48 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


18


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, 2016
 
December 31, 2015
Current
$
33

 
$
41

Non-current
293

 
326

Total environmental liabilities
$
326

 
$
367

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, 2016 and 2015, Sunoco, Inc. recorded $6 million and $7 million, respectively, of expenditures related to environmental cleanup programs.
On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (TRC) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closing time period.  On January 2, 2013, USEPA issued a Finding of Violation (FOV) to TRC and, on September 30, 2013, EPA issued an NOV/FOV to TRC alleging Clean Air Act violations.  To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery.  Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.
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 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.
In April 2016, the PHMSA issued a Notice of Probable Violation ("NOPV"), Proposed Civil Penalty and Proposed Compliance Order related to certain procedures carried out during construction of Sunoco Logistics’ Permian Express 2 pipeline system in Texas. The correspondence proposes penalties in excess of $0.1 million, and Sunoco Logistics is currently in discussions with PHMSA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows, or financial position.
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 past costs for OSHA required activities, including general


19


industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.
11.
DERIVATIVE 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, we 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.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices 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.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our 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 NGL. These contracts are not designated as hedges for accounting purposes.
We use derivatives in our liquids transportation and services segment to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
Sunoco Logistics utilizes swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. These contracts are not designated as hedges for accounting purposes.
We use futures and swaps 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 in our retail marketing segment. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.
The following table details our outstanding commodity-related derivatives:
 
March 31, 2016
 
December 31, 2015
 
Notional Volume
 
Maturity
 
Notional Volume
 
Maturity
Mark-to-Market Derivatives
 
 
 
 
 
 
 
(Trading)
 
 
 
 
 
 
 
Natural Gas (MMBtu):
 
 
 
 
 
 
 
Fixed Swaps/Futures
1,712,500

 
2016-2017
 
(602,500
)
 
2016-2017
Basis Swaps IFERC/NYMEX(1)
63,825,000

 
2016-2017
 
(31,240,000
)
 
2016-2017
Power (Megawatt):
 
 
 
 
 
 
 
Forwards
(344,954
)
 
2016-2017
 
357,092

 
2016-2017
Futures
2,675,597

 
2016-2017
 
(109,791
)
 
2016
Options – Puts
(227,600
)
 
2016
 
260,534

 
2016
Options – Calls
1,011,600

 
2016
 
1,300,647

 
2016
Crude (Bbls):
 
 
 
 
 
 
 
Futures
(616,000
)
 
2016-2017
 
(591,000
)
 
2016-2017
Options – Puts
(300,000
)
 
2016
 

 
Options – Calls
300,000

 
2016
 

 
(Non-Trading)
 
 
 
 
 
 
 
Natural Gas (MMBtu):
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(9,175,000
)
 
2016-2017
 
(6,522,500
)
 
2016-2017
Swing Swaps IFERC
105,170,000

 
2016-2017
 
71,340,000

 
2016-2017
Fixed Swaps/Futures
(6,862,500
)
 
2016-2018
 
(14,380,000
)
 
2016-2018
Forward Physical Contracts
26,156,570

 
2016-2017
 
21,922,484

 
2016-2017
Natural Gas Liquid (Bbls) – Forwards/Swaps
(6,273,000
)
 
2016
 
(8,146,800
)
 
2016-2018
Refined Products (Bbls) – Futures
(2,042,000
)
 
2016-2017
 
(993,000
)
 
2016-2017
Corn (Bushels) – Futures

 
 
1,185,000

 
2016
Fair Value Hedging Derivatives
 
 
 
 
 
 
 
(Non-Trading)
 
 
 
 
 
 
 
Natural Gas (MMBtu):
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(23,215,000
)
 
2016
 
(37,555,000
)
 
2016
Fixed Swaps/Futures
(23,215,000
)
 
2016
 
(37,555,000
)
 
2016
Hedged Item – Inventory
23,215,000

 
2016
 
37,555,000

 
2016
(1) 
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
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 variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.


20


The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:
Term
 
Type(1)
 
Notional Amount Outstanding
March 31, 2016
 
December 31, 2015
July 2016(2)
 
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
 
$
200

 
$
200

July 2017(3)
 
Forward-starting to pay a fixed rate of 3.84% and receive a floating rate
 
300

 
300

July 2018(3)
 
Forward-starting to pay a fixed rate of 4.00% and receive a floating rate
 
200

 
200

December 2018
 
Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%
 
1,200

 
1,200

March 2019
 
Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%
 
300

 
300

July 2019(3)
 
Forward-starting to pay a fixed rate of 3.25% and receive a floating rate
 
200

 
200

(1) 
Floating rates are based on 3-month LIBOR.
(2) 
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.
(3) 
Represents the effective date. These forward-starting swaps have terms 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 the Partnership’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, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our 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.
The Partnership 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 us on or about the settlement date for non-exchange traded derivatives, and we exchange 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.
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.


21


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, 2016
 
December 31, 2015
 
March 31, 2016
 
December 31, 2015
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
 
Commodity derivatives (margin deposits)
 
$
4

 
$
38

 
$

 
$
(3
)
 
 
4

 
38

 

 
(3
)
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
 
Commodity derivatives (margin deposits)
 
115

 
353

 
(98
)
 
(306
)
Commodity derivatives
 
32

 
57

 
(32
)
 
(41
)
Interest rate derivatives
 
25

 

 
(267
)
 
(171
)
Embedded derivatives in ETP Preferred Units
 

 

 
(5
)
 
(5
)
 
 
172

 
410

 
(402
)
 
(523
)
Total derivatives
 
$
176

 
$
448

 
$
(402
)
 
$
(526
)
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, 2016
 
December 31, 2015
 
March 31, 2016
 
December 31, 2015
Derivatives without offsetting agreements
 
Derivative assets (liabilities)
 
$
25

 
$

 
$
(272
)
 
$
(176
)
Derivatives in offsetting agreements:
 
 
 
 
 
 
 
 
OTC contracts
 
Derivative assets (liabilities)
 
32

 
57

 
(32
)
 
(41
)
Broker cleared derivative contracts
 
Other current assets
 
119

 
391

 
(98
)
 
(309
)
Total gross derivatives
 
176

 
448

 
(402
)
 
(526
)
Offsetting agreements:
 
 
 
 
 
 
 
 
Counterparty netting
 
Derivative assets (liabilities)
 
(17
)
 
(17
)
 
17

 
17

Payments on margin deposit
 
Other current assets
 
(98
)
 
(309
)
 
98

 
309

Total net derivatives
 
$
61

 
$
122

 
$
(287
)
 
$
(200
)
We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.


22


The following tables summarize the amounts recognized with respect to our derivative financial instruments:
 
 
Change in Value Recognized in OCI on Derivatives
(Effective Portion)
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
Derivatives in cash flow hedging relationships:
 
 
 
 
Commodity derivatives
 
$

 
$
1

Total
 
$

 
$
1

 
Location of Gain/(Loss) Recognized in Income on Derivatives
 
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
 
 
 
Three Months Ended
March 31,
 
 
 
 
2016
 
2015
 
Derivatives in fair value hedging relationships (including hedged item):
 
 
 
 
 
 
Commodity derivatives
Cost of products sold
 
$
(4
)
 
$
(3
)
 
Total
 
 
$
(4
)
 
$
(3
)
 
 
Location of Gain/(Loss) Recognized in Income on Derivatives
 
Amount of Gain/(Loss) Recognized in Income on Derivatives
 
 
 
Three Months Ended
March 31,
 
 
 
2016
 
2015
Derivatives not designated as hedging instruments:
 
 
 
 
 
Commodity derivatives – Trading
Cost of products sold
 
$
(9