Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
☒
☒
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31,June 30, 2020
or
☐
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-31219
Energy Transfer Operating, 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)
Registrant’sRegistrant’s telephone number, including area code: (214) 981-0700
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes   ýý       No   ¨¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).       Yes   ýý       No   ¨¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large“large accelerated filer,” “accelerated” “accelerated filer,” “smaller” “smaller reporting company”company” and “emerging“emerging growth company”company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
¨
¨
 
Accelerated filer
 
☐
☐
Non-accelerated filer
 
ý
ý
 
Smaller reporting company
 
☐
☐
 
 
 
 
Emerging growth company
 
☐
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).      Yes   ☐☐         No   ýý
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Trading Symbol(s)
 
Name of each exchange on which registered
7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
 
ETPprC
 
New York Stock Exchange
7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
 
ETPprD
 
New York Stock Exchange
7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
 
ETPprE
 
New York Stock Exchange
4.250% Senior Notes due 2023
 
ETP 23
 
New York Stock Exchange
5.875% Senior Notes due 2024
 
ETP 24
 
New York Stock Exchange
5.500% Senior Notes due 2027
 
ETP 27
 
New York Stock Exchange
 


Table of Contents

FORM 10-Q
ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
PART I –– FINANCIAL INFORMATION
 
 
 
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
 
 
 
Consolidated Balance Sheets
1
 
 
Consolidated Statements of Operations
3
 
 
Consolidated Statements of Comprehensive Income (Loss)
4
 
 
Consolidated Statements of Equity
5
 
 
Consolidated Statements of Cash Flows
67
 
 
Notes to Consolidated Financial Statements
78
 
 
ITEM 2. MANAGEMENT’SMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
3437
 
 
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
5564
 
 
ITEM 4. CONTROLS AND PROCEDURES
5765
 
 
PART II –– OTHER INFORMATION
 
 
 
ITEM 1. LEGAL PROCEEDINGS
5867
 
 
ITEM 1A. RISK FACTORS
5867
 
 
ITEM 6. EXHIBITS
6068
 
 
SIGNATURE
6270


i
Table of Contents

Definitions
References to the “Partnership”“Partnership” or “ETO”“ETO” refer to Energy Transfer Operating, L.P. In addition, the following is a list of certain acronyms and terms used throughout this document:
 
/d
 
per day
 
 
 
 
 
AOCI
 
accumulated other comprehensive income (loss)
 
 
 
 
 
BBtu
 
billion British thermal units
 
 
 
 
 
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
 
 
 
 
 
CDM
Citrus
 
CDM Resource ManagementCitrus, LLC and CDM Environmental & Technical Services LLC, collectively
 
 
 
 
 
Citrus
DOJ
 
Citrus, LLC
 
 
 
 
 
DOJ
 
United States Department of Justice
 
 
 
 
 
EPA
 
United States Environmental Protection Agency
 
 
 
 
 
ET
 
Energy Transfer LP, the parent company of ETO
 
 
 
 
 
ETC Sunoco
 
ETC Sunoco Holdings LLC (formerly, Sunoco, Inc.), a wholly-owned subsidiary of ETO
 
 
 
 
 
ETP GP
 
Energy Transfer Partners GP, L.P., the general partner of ETO
 
 
 
 
 
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
 
 
 
 
 
FGT
 
Florida Gas Transmission Company, LLC, a wholly-owned subsidiary of Citrus
 
 
 
 
 
GAAP
 
accounting principles generally accepted in the United States of America
 
 
 
 
 
HFOTCO
 
Houston Fuel Oil Terminal Company, a wholly-owned subsidiary of ETO, which owns the Houston Terminal
 
 
 
 
 
IDRs
 
incentive distribution rights
 
 
 
 
 
Lake Charles LNG
 
Lake Charles LNG Company, LLC, (previously named Trunkline LNG Company, LLC), a wholly-owned subsidiary of ETO
 
 
 
 
 
LIBOR
 
London Interbank Offered Rate
 
 
 
 
 
MBbls
 
thousand barrels
 
 
 
 
 
MEP
 
Midcontinent Express Pipeline LLC
 
 
 
 
 
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, wholly-owned by ETO
 
 
 
 
 
PES
 
Philadelphia Energy Solutions Refining and Marketing LLC, non-controlling interest owned by ETO
 
 
 
 
 
Preferred Unitholders
 
Unitholders of the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units and Series G Preferred Units, collectively
 
 
 
 
 
Regency
 
Regency Energy Partners LP, a wholly-owned subsidiary of ETO
RoverRover Pipeline LLC, a less than wholly-owned subsidiary of ETO
SECSecurities and Exchange Commission
SemCAMSSemCAMS Midstream ULC, a less than wholly-owned subsidiary of ETO
SemGroupSemGroup, LLC (formerly SemGroup Corporation)


ii
Table of Contents

 
 
 
 
 
RIGS
 
Regency Intrastate Gas System, a wholly-owned subsidiary of ETO
 
 
 
 
 
Rover
 
Rover Pipeline LLC, a less than wholly-owned subsidiary of ETO
 
 
 
 
 
SEC
 
Securities and Exchange Commission
 
 
 
 
 
SemGroup
 
SemGroup Corporation
 
 
 
 
 
Series A Preferred Units
 
6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
 
 
 
 
 
Series B Preferred Units
 
6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
 
 
 
 
 
Series C Preferred Units
 
7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
 
 
 
 
 
Series D Preferred Units
 
7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
 
 
 
 
 
Series E Preferred Units
 
7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
 
 
 
 
 
Series F Preferred Units
 
6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
 
 
 
 
 
Series G Preferred Units
 
7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
 
 
 
 
 
SPLP
 
Sunoco Pipeline L.P., a wholly-owned subsidiary of ETO
 
 
 
 
 
Sunoco Logistics Operations
 
Sunoco Logistics Partners Operations L.P., a wholly-owned subsidiary of ETO
 
 
 
 
 
Sunoco R&M
&M
 
Sunoco (R&M)&M), LLC
 
 
 
 
 
Southwest Gas
Transwestern
 
Pan Gas Storage LLC (d.b.a. Southwest Gas Storage Company)
 
 
 
 
 
Transwestern
 
Transwestern Pipeline Company, LLC, a wholly-owned subsidiary of ETO
 
 
 
 
 
Trunkline
 
Trunkline Gas Company, LLC, a wholly-owned subsidiary of Panhandle
 
 
 
 
 
USAC
 
USA Compression Partners, LP, a wholly-owned subsidiary of ETO
 
 
 
 
 
USAC Preferred Units
 
USAC Series A Preferred Units
 
White Cliffs
 
White Cliffs Pipeline
 
 
 
 



iii
Table of Contents

PART I –– FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)
March 31, 2020
 
December 31, 2019*
June 30,
2020		 December 31, 2019*
ASSETS
 
 
 
   
Current assets:
 
 
 
   
Cash and cash equivalents
$
189

 
$
265

$152
 $288
Accounts receivable, net
3,268

 
4,921

2,955
 5,038
Accounts receivable from related companies
138

 
175

139
 167
Inventories
1,024

 
1,532

1,593
 1,532
Income taxes receivable
115

 
141

68
 147
Derivative assets
25

 
23

14
 23
Other current assets
297

 
287

245
 291
Total current assets
5,056

 
7,344

5,166
 7,486
 
 
 
   
Property, plant and equipment
89,132

 
87,886

91,774
 89,294
Accumulated depreciation and depletion
(16,161
)
 
(15,395
)
(17,125) (15,398)
72,971

 
72,491

74,649
 73,896
 
 
 
   
Advances to and investments in unconsolidated affiliates
3,313

 
3,435

3,306
 3,454
Lease right-of-use assets, net
1,026

 
956

1,112
 964
Other non-current assets, net
1,493

 
1,547

1,511
 1,572
Notes receivable from related company
5,299

 
5,926

2,865
 3,603
Intangible assets, net
5,948

 
5,974

6,007
 6,154
Goodwill
3,807

 
5,132

3,868
 5,167
Total assets
$
98,913

 
$
102,805

$98,484
 $102,296
*As adjusted. See Note 1.


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

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)
March 31, 2020
 
December 31, 2019*
June 30,
2020		 December 31, 2019*
LIABILITIES AND EQUITY
 
 
 
   
Current liabilities:
 
 
 
   
Accounts payable
$
2,378

 
$
4,099

$2,138
 $4,119
Accounts payable to related companies
1,037

 
1,112

36
 31
Derivative liabilities
9

 
147

24
 147
Operating lease current liabilities
54

 
57

54
 60
Accrued and other current liabilities
3,888

 
3,245

2,730
 3,339
Current maturities of long-term debt
16

 
12

34
 25
Total current liabilities
7,382

 
8,672

5,016
 7,721
 
 
 
   
Long-term debt, less current maturities
49,909

 
50,560

51,179
 50,905
Non-current derivative liabilities
573

 
273

577
 273
Non-current operating lease liabilities
821

 
895

903
 901
Deferred income taxes
3,180

 
3,113

3,277
 3,171
Other non-current liabilities
1,161

 
1,134

1,216
 1,161
 
 
 
   
Commitments and contingencies

 


 

Redeemable noncontrolling interests
492

 
492

750
 739
 
 
 
   
Equity:
 
 
 
   
Limited Partners:
 
 
 
   
Preferred Unitholders
4,748

 
3,174

4,764
 3,174
Common Unitholders
22,804

 
24,226

22,510
 24,226
Accumulated other comprehensive loss
(37
)
 
(18
)
(21) (18)
Total partners’ capital
27,515

 
27,382

Total partners’ capital27,253
 27,382
Noncontrolling interests
7,880

 
8,018

8,313
 8,018
Predecessor equity
—

 
2,266

—
 2,025
Total equity
35,395

 
37,666

35,566
 37,425
Total liabilities and equity
$
98,913

 
$
102,805

$98,484
 $102,296
*As adjusted. See Note 1.


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

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
(unaudited)
Three Months Ended
March 31,
Three Months Ended
June 30,		 Six Months Ended
June 30,
2020
 
2019*
2020 2019* 2020 2019*
REVENUES:
 
 
 
       
Refined product sales
$
3,232

 
$
3,726

$2,000
 $4,477
 $5,232
 $8,203
Crude sales
3,543

 
3,525

1,329
 4,346
 4,872
 7,871
NGL sales
1,689

 
2,402

1,254
 1,996
 2,943
 4,398
Gathering, transportation and other fees
2,326

 
2,267

2,137
 2,035
 4,522
 4,302
Natural gas sales
588

 
964

514
 763
 1,102
 1,727
Other
190

 
237

104
 260
 294
 497
Total revenues
11,568

 
13,121

7,338
 13,877
 18,965
 26,998
COSTS AND EXPENSES:
 
 
 
       
Cost of products sold
8,291

 
9,477

4,117
 10,301
 12,408
 19,778
Operating expenses
848

 
808

770
 792
 1,649
 1,600
Depreciation, depletion and amortization
851

 
771

934
 781
 1,799
 1,552
Selling, general and administrative
192

 
149

171
 175
 373
 324
Impairment losses
1,325

 
50

4
 —
 1,329
 50
Total costs and expenses
11,507

 
11,255

5,996
 12,049
 17,558
 23,304
OPERATING INCOME
61

 
1,866

1,342
 1,828
 1,407
 3,694
OTHER INCOME (EXPENSE):
 
 
 
       
Interest expense, net of interest capitalized
(595
)
 
(527
)
(578) (578) (1,178) (1,105)
Equity in earnings (losses) of unconsolidated affiliates
(7
)
 
65

Equity in earnings of unconsolidated affiliates85
 77
 78
 142
Losses on extinguishments of debt
(59
)
 
(2
)
—
 —
 (59) (2)
Losses on interest rate derivatives
(329
)
 
(74
)
(3) (122) (332) (196)
Other, net
75

 
17

(29) 112
 16
 129
INCOME (LOSS) BEFORE INCOME TAX EXPENSE
(854
)
 
1,345

817
 1,317
 (68) 2,662
Income tax expense
53

 
126

98
 35
 127
 161
NET INCOME (LOSS)
(907
)
 
1,219

719
 1,282
 (195) 2,501
Less: Net income (loss) attributable to noncontrolling interests
(200
)
 
256

Less: Net income attributable to noncontrolling interests225
 266
 25
 522
Less: Net income attributable to redeemable noncontrolling interests
12

 
13

13
 13
 25
 26
Less: Net loss attributable to predecessor equity—
 —
 (6) —
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS
$
(719
)
 
$
950

$481
 $1,003
 $(239) $1,953
*As adjusted. See Note 1.


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

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
(unaudited)
Three Months Ended
March 31,
Three Months Ended
June 30,		 Six Months Ended
June 30,
2020
 
2019*
2020 2019* 2020 2019*
Net income (loss)
$
(907
)
 
$
1,219

$719
 $1,282
 $(195) $2,501
Other comprehensive income (loss), net of tax:
 
 
 
       
Change in value of available-for-sale securities
(9
)
 
5

9
 3
 —
 8
Actuarial gain related to pension and other postretirement benefit plans
6

 
7

8
 3
 14
 10
Change in other comprehensive income from unconsolidated affiliates
(16
)
 
(4
)
Foreign currency translation adjustments30
 —
 30
 —
Change in other comprehensive loss from unconsolidated affiliates—
 (5) (16) (9)
(19
)
 
8

47
 1
 28
 9
Comprehensive income (loss)
(926
)
 
1,227

766
 1,283
 (167) 2,510
Less: Comprehensive income (loss) attributable to noncontrolling interests
(200
)
 
256

Less: Comprehensive income attributable to noncontrolling interests225
 266
 25
 522
Less: Comprehensive income attributable to redeemable noncontrolling interests
12

 
13

13
 13
 25
 26
Less: Comprehensive loss attributable to predecessor equity—
 —
 (6) —
Comprehensive income (loss) attributable to partners
$
(738
)
 
$
958

$528
 $1,004
 $(211) $1,962
*As adjusted. See Note 1.


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

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)
(unaudited)
Limited Partners
 
 
 
 
 
 
 
 
Limited Partners        
Preferred Unitholders
 
Common Unitholders
 
AOCI
 
Non-controlling Interests
 
Predecessor Equity
 
Total
Preferred Unitholders Common Unitholders AOCI Noncontrolling Interests Predecessor Equity Total
Balance, December 31, 2019*
$
3,174

 
$
24,226

 
$
(18
)
 
$
8,018

 
$
2,266

 
$
37,666

$3,174
 $24,226
 $(18) $8,018
 $2,025
 $37,425
Distributions to partners
(80
)
 
(2,550
)
 
—

 
—

 
—

 
(2,630
)
(80) (2,550) —
 —
 —
 (2,630)
Distributions to noncontrolling interests
—

 
—

 
—

 
(340
)
 
—

 
(340
)
—
 —
 —
 (340) (25) (365)
Units issued for cash
1,580

 
—

 
—

 
—

 
—

 
1,580

1,580
 —
 —
 —
 —
 1,580
Capital contributions from noncontrolling interests
—

 
—

 
—

 
66

 
—

 
66

—
 —
 —
 66
 30
 96
SemGroup contribution (See Note 2)
—

 
1,933

 
—

 
333

 
(2,266
)
 
—

—
 1,840
 (2) 333
 (2,171) —
Other comprehensive loss, net of tax
—

 
—

 
(19
)
 
—

 
—

 
(19
)
—
 —
 (19) —
 (38) (57)
Other, net
(3
)
 
(9
)
 
—

 
3

 
—

 
(9
)
(3) (8) —
 3
 (10) (18)
Net income (loss), excluding amounts attributable to redeemable noncontrolling interests
77

 
(796
)
 
—

 
(200
)
 
—

 
(919
)
77
 (797) —
 (200) (6) (926)
Balance, March 31, 2020
$
4,748

 
$
22,804

 
$
(37
)
 
$
7,880

 
$
—

 
$
35,395

Balance, March 31, 2020*4,748
 22,711
 (39) 7,880
 (195) 35,105
Distributions to partners(67) —
 —
 —
 —
 (67)
Distributions to noncontrolling interests—
 —
 —
 (340) —
 (340)
Capital contributions from noncontrolling interests—
 —
 —
 82
 —
 82
SemGroup contribution (See Note 2)—
 (630) (20) 455
 195
 —
Other comprehensive income, net of tax—
 —
 38
 9
 —
 47
Other, net(1) 32
 —
 2
 —
 33
Net income, excluding amounts attributable to redeemable noncontrolling interests84
 397
 —
 225
 —
 706
Balance, June 30, 2020$4,764
 $22,510
 $(21) $8,313
 $—
 $35,566
 
Limited Partners
 
 
 
 
 
 
 
Preferred Unitholders
 
Common Unitholders
 
AOCI
 
Non-controlling Interests
 
Total
Balance, December 31, 2018*
$
2,388

 
$
26,539

 
$
(42
)
 
$
7,903

 
$
36,788

Distributions to partners
(64
)
 
(1,450
)
 
—

 
—

 
(1,514
)
Distributions to noncontrolling interests
—

 
—

 
—

 
(361
)
 
(361
)
Capital contributions from noncontrolling interests
—

 
—

 
—

 
140

 
140

Sale of noncontrolling interest in subsidiary
—

 
—

 
—

 
93

 
93

Other comprehensive income, net of tax
—

 
—

 
8

 
—

 
8

Other, net
—

 
15

 
—

 
13

 
28

Net income, excluding amounts attributable to redeemable noncontrolling interest
40

 
910

 
—

 
256

 
1,206

Balance, March 31, 2019*
$
2,364

 
$
26,014

 
$
(34
)
 
$
8,044

 
$
36,388

*As adjusted. See Note 1.

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

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWSEQUITY
(Dollars in millions)
(unaudited)
 
Three Months Ended
March 31,
 
2020
 
2019*
OPERATING ACTIVITIES
 
 
 
Net income (loss)
$
(907
)
 
$
1,219

Reconciliation of net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
851

 
771

Deferred income taxes
66

 
98

Inventory valuation adjustments
227

 
(93
)
Non-cash compensation expense
18

 
29

Impairment losses
1,325

 
50

Losses on extinguishments of debt
59

 
2

Distributions on unvested awards
(2
)
 
(1
)
Equity in (earnings) losses of unconsolidated affiliates
7

 
(65
)
Distributions from unconsolidated affiliates
58

 
66

Other non-cash
11

 
107

Net change in operating assets and liabilities, net of effects of acquisitions
113

 
(337
)
Net cash provided by operating activities
1,826

 
1,846

INVESTING ACTIVITIES
 
 
 
Cash proceeds from sale of noncontrolling interest in subsidiary
—

 
93

Cash paid for all other acquisitions, net of cash received
—

 
(5
)
Capital expenditures, excluding allowance for equity funds used during construction
(1,621
)
 
(1,150
)
Contributions in aid of construction costs
25

 
15

Contributions to unconsolidated affiliates
(9
)
 
(28
)
Distributions from unconsolidated affiliates in excess of cumulative earnings
52

 
13

Proceeds from the sale of other assets
2

 
4

Other
(6
)
 
(40
)
Net cash used in investing activities
(1,557
)
 
(1,098
)
FINANCING ACTIVITIES
 
 
 
Proceeds from borrowings
12,088

 
11,295

Repayments of debt
(12,769
)
 
(9,513
)
Cash received from (paid to) related company
611

 
(613
)
Preferred units issued for cash
1,580

 
—

Capital contributions from noncontrolling interests
66

 
140

Distributions to partners
(1,530
)
 
(1,514
)
Distributions to noncontrolling interests
(340
)
 
(361
)
Debt issuance costs
(51
)
 
(84
)
Net cash used in financing activities
(345
)
 
(650
)
Increase (decrease) in cash and cash equivalents
(76
)
 
98

Cash and cash equivalents, beginning of period
265

 
418

Cash and cash equivalents, end of period
$
189

 
$
516

 Limited Partners      
 Preferred Unitholders Common Unitholders AOCI Noncontrolling Interests Total
Balance, December 31, 2018*$2,388
 $26,539
 $(42) $7,903
 $36,788
Distributions to partners(64) (1,450) —
 —
 (1,514)
Distributions to noncontrolling interests—
 —
 —
 (361) (361)
Capital contributions from noncontrolling interests—
 —
 —
 140
 140
Sale of noncontrolling interest in subsidiary—
 —
 —
 93
 93
Other comprehensive income, net of tax—
 —
 8
 —
 8
Other, net—
 15
 —
 13
 28
Net income, excluding amounts attributable to redeemable noncontrolling interest40
 910
 —
 256
 1,206
Balance, March 31, 2019*2,364
 26,014
 (34) 8,044
 36,388
Distributions to partners(18) (1,625) —
 —
 (1,643)
Distributions to noncontrolling interests—
 —
 —
 (370) (370)
Units issued for cash780
 —
 —
 —
 780
Capital contributions from noncontrolling interests—
 —
 —
 66
 66
Other comprehensive income, net of tax—
 —
 1
 —
 1
Other, net(1) (36) —
 —
 (37)
Net income, excluding amounts attributable to redeemable noncontrolling interest53
 950
 —
 266
 1,269
Balance, June 30, 2019*$3,178
 $25,303
 $(33) $8,006
 $36,454
*As adjusted. See Note 1.


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

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
(unaudited)
 Six Months Ended
June 30,
 2020 2019*
OPERATING ACTIVITIES:   
Net income (loss)$(195) $2,501
Reconciliation of net income (loss) to net cash provided by operating activities:   
Depreciation, depletion and amortization1,799
 1,552
Deferred income taxes126
 140
Inventory valuation adjustments137
 (97)
Non-cash compensation expense63
 58
Impairment losses1,329
 50
Losses on extinguishments of debt59
 2
Distributions on unvested awards(3) (3)
Equity in earnings of unconsolidated affiliates(78) (142)
Distributions from unconsolidated affiliates125
 170
Other non-cash(12) (24)
Net change in operating assets and liabilities, net of effects of acquisitions27
 (187)
Net cash provided by operating activities3,377
 4,020
INVESTING ACTIVITIES:   
Cash proceeds from sale of noncontrolling interest in subsidiary—
 93
Cash paid for all other acquisitions, net of cash received—
 (7)
Capital expenditures, excluding allowance for equity funds used during construction(2,892) (2,818)
Contributions in aid of construction costs47
 41
Contributions to unconsolidated affiliates(16) (254)
Distributions from unconsolidated affiliates in excess of cumulative earnings97
 21
Proceeds from the sale of other assets6
 22
Other(5) (40)
Net cash used in investing activities(2,763) (2,942)
FINANCING ACTIVITIES:   
Proceeds from borrowings16,975
 16,463
Repayments of debt(16,717) (14,705)
Cash received from related company676
 180
Preferred units issued for cash1,580
 780
Capital contributions from noncontrolling interests148
 206
Predecessor capital contributions from noncontrolling interests30
 —
Distributions to partners(2,697) (3,157)
Distributions to noncontrolling interests(680) (731)
Predecessor distributions to noncontrolling interests(25) —
Debt issuance costs(50) (87)
Other10
 (1)
Net cash used in financing activities(750) (1,052)
Increase (decrease) in cash and cash equivalents(136) 26
Cash and cash equivalents, beginning of period288
 418
Cash and cash equivalents, end of period$152
 $444
*As adjusted. See Note 1.

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts are in millions)
(unaudited)
1.
ORGANIZATION AND BASIS OF PRESENTATION
Organization
The consolidated financial statements presented herein include Energy Transfer Operating, L.P. and its subsidiaries (the “Partnership,” “we,” “us,” “our”“Partnership,” “we,” “us,” “our” or “ETO”“ETO”).
Energy Transfer Operating, L.P. is a consolidated subsidiary of Energy Transfer LP. In December 2019, ET completed the acquisition of SemGroup. During the first quarterand second quarters of 2020, ET contributed certainSemGroup and its former SemGroup subsidiaries to ETO through sale and contribution transactions. The contribution transactions were accounted for as reorganizations of entities under common control; therefore, the contributed entities’entities’ assets and liabilities were not adjusted as of the contribution date. The Partnership’sPartnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation beginning December 5, 2019 for SemGroup assets contributed (the date ET acquired SemGroup). Predecessor equity included in the consolidated financial statements represents the equity of contributed entities prior to the contribution transactions.
Our consolidated financial statements reflect the following reportable segments:
••intrastate transportation and storage;storage;
••interstate transportation and storage;storage;
••midstream;midstream;
••NGL and refined products transportation and services;services;
••crude oil transportation and services;services;
••investment in Sunoco LP;
••investment in USAC; and
••all other.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 of Energy Transfer Operating, L.P. for the year ended December 31, 2019,, included in the Partnership’sPartnership’s Annual Report on Form 10-K filed with the SEC on February 21, 2020.2020. In the opinion of the Partnership’sPartnership’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 consolidated financial statements of the Partnership presented herein include the results of operations of our controlled subsidiaries, including Sunoco LP and USAC.
Certain prior period amounts have also been reclassified to conform to the current period presentation. These reclassifications had no impact on net income or total equity.
Change in Accounting Policy
Effective January 1, 2020, the Partnership elected to change its accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. Under the revised accounting policy, certain amounts of crude oil that are not available for sale have been reclassified from inventory to non-current assets. These crude oil barrels, which are owned by the Partnership’sPartnership’s crude oil acquisition and marketing business, include pipeline linefill and tank bottoms and are not considered to be available for sale because the volumes must be maintained in order to continue normal operation of the related pipelines or tanks and because there is no expectation of liquidation or sale of these volumes in the near term.
Under the previous accounting policy, all crude oil barrels were recorded as inventory under the weighted-average cost method. Under the revised accounting policy, barrels related to pipeline linefill and tank bottoms are accounted for as long-lived assets and reflected as non-current assets on the consolidated balance sheet. These crude oil barrels will be tested for impairment


78
Table of Contents

consistent with the Partnership’sPartnership’s existing accounting policy for impairments of long-lived assets. The Partnership’sPartnership’s management believes that the change in accounting policy is preferable as it more closely aligns the accounting policies across the consolidated entity, given that similar assets in the Partnership’sPartnership’s natural gas, NGLs and refined products businesses are accounted for as non-current assets. In addition, management believes that reflecting these crude oil barrels as non-current assets better represents the economic results of the Partnership’sPartnership’s crude oil acquisition and marketing business by reducing volatility resulting from market price adjustments to crude oil barrels that are not expected to be sold or liquidated in the near term.
The impactimpacts of this accounting policy change on the Partnership’sPartnership’s net income for threethe six months ended March 31,June 30, 2020 was approximately$265 million. $265 million. As a result of this change in accounting policy, the Partnership’sPartnership’s consolidated balance sheets for prior periods have been retrospectively adjusted as follows:
December 31, 2019
 
December 31, 2018
December 31, 2019 December 31, 2018
As Originally Reported*
 
Effect of Change
 
As Adjusted
 
As Originally Reported
 
Effect of Change
 
As Adjusted
As Originally Reported* Effect of Change As Adjusted As Originally Reported Effect of Change As Adjusted
Inventories
$
1,935

 
$
(403
)
 
$
1,532

 
$
1,677

 
$
(305
)
 
$
1,372

$1,935
 $(403) $1,532
 $1,677
 $(305) $1,372
Total current assets
7,747

 
(403
)
 
7,344

 
6,820

 
(305
)
 
6,515

7,889
 (403) 7,486
 6,820
 (305) 6,515
Other non-current assets, net
1,051

 
496

 
1,547

 
1,006

 
472

 
1,478

1,076
 496
 1,572
 1,006
 472
 1,478
Total assets
102,712

 
93

 
102,805

 
88,442

 
167

 
88,609

102,203
 93
 102,296
 88,442
 167
 88,609
Total partners' capital
27,289

 
93

 
27,382

 
28,718

 
167

 
28,885

Total partners’ capital27,289
 93
 27,382
 28,718
 167
 28,885
* Amounts reflect the retrospective consolidation of the SemGroup entities discussed above.


89
Table of Contents

In addition, the Partnership’sPartnership’s consolidated statements of operations, comprehensive income and cash flows for prior periods have been retrospectively adjusted as follows:
Year Ended December 31,
 
Three Months Ended March 31,
Year Ended December 31, Three Months Ended June 30, Six Months Ended June 30,
2019
 
2018
 
2019
2019 2018 2019 2019
As originally reported:
 
 
 
 
 
       
Consolidated Statements of Operations and Comprehensive Income
 
 
 
 
 
       
Cost of products sold
$
39,603

 
$
41,658

 
$
9,415

$39,603
 $41,658
 $10,302
 $19,717
Operating income
7,285

 
5,402

 
1,928

7,285
 5,402
 1,827
 3,755
Income from continuing operations before income tax expense (benefit)
5,386

 
4,044

 
1,407

Income from continuing operations before income tax expense5,386
 4,044
 1,316
 2,723
Net income
5,186

 
3,774

 
1,281

5,186
 3,774
 1,281
 2,562
Comprehensive income
5,210

 
3,731

 
1,289

5,210
 3,731
 1,282
 2,571
Comprehensive income attributable to partners
4,108

 
2,982

 
1,020

4,108
 2,982
 1,003
 2,023
 
 
 
 
 
       
Consolidated Statements of Cash Flows
 
 
 
 
 
       
Net income
5,186

 
3,774

 
1,281

5,186
 3,774
 1,281
 2,562
Net change in operating assets and liabilities
(479
)
 
117

 
(399
)
(479) 117
 151
 (248)
 
 
 
 
 
       
Effect of change:
 
 
 
 
 
       
Consolidated Statements of Operations and Comprehensive Income
 
 
 
 
 
       
Cost of products sold
74

 
(55
)
 
62

74
 (55) (1) 61
Operating income
(74
)
 
55

 
(62
)
(74) 55
 1
 (61)
Income from continuing operations before income tax expense (benefit)
(74
)
 
55

 
(62
)
Income from continuing operations before income tax expense(74) 55
 1
 (61)
Net income
(74
)
 
55

 
(62
)
(74) 55
 1
 (61)
Comprehensive income
(74
)
 
55

 
(62
)
(74) 55
 1
 (61)
Comprehensive income attributable to partners
(74
)
 
55

 
(62
)
(74) 55
 1
 (61)
 
 
 
 
 
       
Consolidated Statements of Cash Flows
 
 
 
 
 
       
Net income
(74
)
 
55

 
(62
)
(74) 55
 1
 (61)
Net change in operating assets and liabilities
74

 
(55
)
 
62

74
 (55) (1) 61
 
 
 
 
 
       
As adjusted:
 
 
 
 
 
       
Consolidated Statements of Operations and Comprehensive Income
 
 
 
 
 
       
Cost of products sold
39,677

 
41,603

 
9,477

39,677
 41,603
 10,301
 19,778
Operating income
7,211

 
5,457

 
1,866

7,211
 5,457
 1,828
 3,694
Income from continuing operations before income tax expense (benefit)
5,312

 
4,099

 
1,345

Income from continuing operations before income tax expense5,312
 4,099
 1,317
 2,662
Net income
5,112

 
3,829

 
1,219

5,112
 3,829
 1,282
 2,501
Comprehensive income
5,136

 
3,786

 
1,227

5,136
 3,786
 1,283
 2,510
Comprehensive income attributable to partners
4,034

 
3,037

 
958

4,034
 3,037
 1,004
 1,962
 
 
 
 
 
       
Consolidated Statements of Cash Flows
 
 
 
 
 
       
Net income
5,112

 
3,829

 
1,219

5,112
 3,829
 1,282
 2,501
Net change in operating assets and liabilities
(405
)
 
62

 
(337
)
(405) 62
 150
 (187)

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


10
Table of Contents

these estimates are based on management’smanagement’s available knowledge of current and expected future events, actual results could be different from those estimates.


9
Table of Contents

Recent Accounting Pronouncements
Effective January 1, 2020, the Partnership adopted Accounting Standards Update (“ASU”(“ASU”) 2016-13 "Financial“Financial Instruments - Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments."” ASU 2016-13 requires an entity to utilize a new impairment model known as the current expected credit loss ("CECL"(“CECL”) model to estimate its lifetime "expected“expected credit loss"loss” and record an allowance that, when deducted from the amortized cost basis of the financial asset, presents the net amount expected to be collected on the financial asset. The CECL model is expected to result in more timely recognition of credit losses. The impact of adoption was immaterial to the Partnership. However, due in large part to the global economic impacts of COVID-19, the Partnership and its subsidiaries recorded an aggregate$16 $16 millionof current expected credit losses for the threesix months ended March 31,June 30, 2020.
Goodwill
During the first quarter of 2020, due to the impacts of the COVID-19 pandemic, the decline in commodity prices and the decreases in the Partnership’sPartnership’s market capitalization, we determined that interim impairment testing should be performed on certain reporting units. We performed the interim impairment tests consistent with our approach for annual impairment testing, including using similar models, inputs and assumptions. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of$483 $483 million related to our Arklatex and South Texas operations within the midstream segment, a goodwill impairment of$183 $183 million related to our Lake Charles LNG regasification operations within the interstate transportation and storage segment due to a contractual reductioncontractually scheduled reductions in payments for the remainder of the contract term, and a goodwill impairment of$40 $40 millionrelated to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline.In addition, USAC recognized a goodwill impairment of$619 $619 millionduring the three months ended March 31, 2020, which is included in the Partnership'sPartnership’s consolidated results of operations.No other impairments of the Partnership’sPartnership’s goodwill were identified.
In connection with aforementioned impairments, the Partnership determined the fair value of our reporting units using the income approach. The income approach is based on the present value of future cash flows, which are derived from our long-term financial forecasts, and requires significant assumptions including, among others, revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Cash flow projections are derived from one-year budgeted amounts and three-year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur.
Of the$3.81 $3.87 billionof goodwill on the Partnership’sPartnership’s consolidated balance sheet as of March 31,June 30, 2020, approximately$1.2 $1.2 billionis recorded in reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test.Management believes that all of the$1.2 $1.2 billionis at significant risk of impairment, if commodity prices and/or overall market demand remains low. In addition, as of March 31, 2020, the Partnership's goodwill balance includes approximately$230 millionof goodwill related to the SemGroup assets that were contributed from ET, as discussed above; these goodwill balances are subject to change as the purchase price allocation has not been finalized. Future goodwill impairment could be impacted by the finalization of the SemGroup purchase accounting.
Changes in the carrying amounts of goodwill were as follows:
Intrastate
Transportation
and Storage
 
Interstate
Transportation and Storage
 
Midstream
 
NGL and Refined Products Transportation and Services
 
Crude Oil Transportation and Services
 
Investment in Sunoco LP
 
Investment in USAC
 
All Other
 
Total
Intrastate
Transportation
and Storage		 Interstate
Transportation and Storage		 Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services Investment in Sunoco LP Investment in USAC All Other Total
Balance, December 31, 2019
$
10

 
$
226

 
$
483

 
$
693

 
$
1,397

 
$
1,555

 
$
619

 
$
149

 
$
5,132

$10
 $226
 $483
 $693
 $1,397
 $1,555
 $619
 $184
 $5,167
Impaired
—

 
(183
)
 
(483
)
 
—

 
—

 
—

 
(619
)
 
(40
)
 
(1,325
)
—
 (183) (483) —
 —
 —
 (619) (40) (1,325)
Other—
 —
 —
 —
 —
 —
 —
 (7) (7)
Balance, March 31, 2020
$
10

 
$
43

 
$
—

 
$
693

 
$
1,397

 
$
1,555

 
$
—

 
$
109

 
$
3,807

10
 43
 —
 693
 1,397
 1,555
 —
 137
 3,835
Other—
 —
 —
 —
 —
 —
 —
 33
 33
Balance, June 30, 2020$10
 $43
 $—
 $693
 $1,397
 $1,555
 $—
 $170
 $3,868



1011
Table of Contents

2.
ACQUISITIONS AND RELATED TRANSACTIONS
ET Contribution of SemGroup Assets to ETO
As discussed in Note 1, certain former SemGroup subsidiaries were transferred from ET to ETO during the three months ended March 31,first and second quarter of 2020. The following table represents the preliminary fair value, as of December 5, 2019, of the SemGroup assets and liabilities transferred from ET to ETO:
At December 5, 2019
At December 5, 2019
Total current assets
$
548

$794
Property, plant and equipment
2,544

3,891
Other non-current assets
574

617
Goodwill
230

295
Intangible assets
280

460
Total assets
4,176

6,057
 
 
Total current liabilities
480

629
Long-term debt, less current maturities (1)
812

2,576
Other non-current liabilities
109

197
SemCAMS Preferred shares241
Total liabilities
1,401

3,643
 
 
Noncontrolling interest
335

822
 
 
Partners’ capital
2,440

Total liabilities and partners’ capital
$
4,176

Partners’ capital1,592
Total liabilities and partners’ capital$6,057

(1) Long-term debt at December 5, 2019 includes SemGroup senior notes with an aggregate principal amount of $1.375 billion and SemGroup subsidiary debt of $593$593 million,, all of which was redeemed in December 2019, subsequent to the closing of ET’sET’s acquisition of SemGroup, using proceeds from an intercompany promissory note from ETO.
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. The Partnership’sPartnership’s consolidated balance sheets did not include any material amounts of restricted cash as of March 31,June 30, 2020 or December 31, 2019.2019.
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.


1112
Table of Contents

The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities is comprised as follows:
Three Months Ended
March 31,
Six Months Ended
June 30,
2020
 
2019
2020 2019
Accounts receivable
$
1,653

 
$
(302
)
$2,084
 $(340)
Accounts receivable from related companies
(12
)
 
(28
)
118
 7
Inventories
281

 
135

(180) 28
Other current assets
75

 
91

150
 37
Other non-current assets, net
(94
)
 
(34
)
(159) (43)
Accounts payable
(1,705
)
 
323

(2,108) 201
Accounts payable to related companies
(73
)
 
(69
)
12
 (109)
Accrued and other current liabilities
(185
)
 
(409
)
(122) (21)
Other non-current liabilities
13

 
(31
)
42
 (87)
Derivative assets and liabilities, net
160

 
(13
)
190
 140
Net change in operating assets and liabilities, net of effects of acquisitions
$
113

 
$
(337
)
$27
 $(187)

Non-cash activities are as follows:

Three Months Ended
March 31,
Six Months Ended
June 30,

2020
 
2019
2020 2019
NON-CASH INVESTING AND FINANCING ACTIVITIES:
 
 
 
   
Accrued capital expenditures
$
992

 
$
630

$742
 $714
Accrued distributions to partners
1,100

 
—

Lease assets obtained in exchange for new lease liabilities
17

 
8

125
 15

4.
INVENTORIES
As further discussed in Note 1, the Partnership elected to change its accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. As a result of this change in accounting policy, the Partnership’sPartnership’s inventory balance for the prior period has been retrospectively adjusted.
Inventories consisted of the following:
March 31, 2020
 
December 31, 2019
June 30,
2020		 December 31,
2019
Natural gas, NGLs and refined products
$
463

 
$
833

$774
 $833
Crude oil
105

 
251

367
 251
Spare parts and other
456

 
448

452
 448
Total inventories
$
1,024

 
$
1,532

$1,593
 $1,532

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.
Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in, first-out (“LIFO”) method.  As of June 30, 2020 and December 31, 2019, the carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of $372 million and $229 million, respectively, and the inventory carrying value equaled or exceeded its replacement cost.  For the three and six months ended June 30, 2020 and 2019, the Partnership’s consolidated income statements did not include any material amounts of income from the liquidation of LIFO fuel inventory.


1213
Table of Contents

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, 2020 was $43.52 billion and $49.93 billion, respectively. As of December 31, 2019, the aggregate fair value and carrying amount of our consolidated debt obligations was $54.30 billion and $50.57 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 and interest rate derivatives 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”“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. During the threesix months endedMarch 31, June 30, 2020,, 0 transfers were made between any levels within the fair value hierarchy.


1314
Table of Contents

The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of March 31,June 30, 2020 and December 31, 2019 based on inputs used to derive their fair values:
 
 
Fair Value Measurements at
March 31, 2020
  Fair Value Measurements at
June 30, 2020
Fair Value Total
 
Level 1
 
Level 2
Fair Value Total Level 1 Level 2
Assets:
 
 
 
 
 
     
Commodity derivatives:
 
 
 
 
 
     
Natural Gas:
 
 
 
 
 
     
Basis Swaps IFERC/NYMEX
$
108

 
$
108

 
$
—

$112
 $112
 $—
Swing Swaps IFERC
2

 
—

 
2

2
 —
 2
Fixed Swaps/Futures
31

 
31

 
—

93
 93
 —
Forward Physical Contracts
6

 
—

 
6

7
 —
 7
Power:
 
 
 
 
 
     
Forwards
15

 
—

 
15

21
 —
 21
Futures
5

 
5

 
—

3
 3
 —
Options – Puts
2

 
2

 
—

Options – Calls
1

 
1

 
—

NGLs – Forwards/Swaps
527

 
527

 
—

Crude – Forwards/Swaps
3

 
3

 
—

Options – Puts1
 1
 —
Options – Calls1
 1
 —
NGLs – Forwards/Swaps208
 208
 —
Refined Products – Futures4
 4
 —
Crude – Forwards/Swaps3
 3
 —
Total commodity derivatives
700

 
677

 
23

455
 425
 30
Other non-current assets
26

 
17

 
9

29
 19
 10
Total assets
$
726

 
$
694

 
$
32

$484
 $444
 $40
Liabilities:
 
 
 
 
 
     
Interest rate derivatives
$
(573
)
 
$
—

 
$
(573
)
$(577) $—
 $(577)
Commodity derivatives:
 
 
 
 
 
     
Natural Gas:
 
 
 
 
 
     
Basis Swaps IFERC/NYMEX
(85
)
 
(85
)
 
—

(83) (83) —
Swing Swaps IFERC
(2
)
 
(1
)
 
(1
)
(5) —
 (5)
Fixed Swaps/Futures
(33
)
 
(33
)
 
—

(117) (117) —
Forward Physical Contracts
(1
)
 
—

 
(1
)
(1) —
 (1)
Power:
 
 
 
 
 
     
Forwards
(9
)
 
—

 
(9
)
(17) —
 (17)
Futures
(5
)
 
(5
)
 
—

(3) (3) —
NGLs – Forwards/Swaps
(489
)
 
(489
)
 
—

Refined Products – Futures
(7
)
 
(7
)
 
—

NGLs – Forwards/Swaps(218) (218) —
Refined Products – Futures(21) (21) —
Crude – Forwards/Swaps(1) (1) —
Total commodity derivatives
(631
)
 
(620
)
 
(11
)
(466) (443) (23)
Total liabilities
$
(1,204
)
 
$
(620
)
 
$
(584
)
$(1,043) $(443) $(600)


1415
Table of Contents

 
 
Fair Value Measurements at
December 31, 2019
  Fair Value Measurements at
December 31, 2019
Fair Value Total
 
Level 1
 
Level 2
Fair Value Total Level 1 Level 2
Assets:
 
 
 
 
 
     
Commodity derivatives:
 
 
 
 
 
     
Natural Gas:
 
 
 
 
 
     
Basis Swaps IFERC/NYMEX
$
17

 
$
17

 
$
—

$17
 $17
 $—
Swing Swaps IFERC
1

 
—

 
1

1
 —
 1
Fixed Swaps/Futures
65

 
65

 
—

65
 65
 —
Forward Physical Contracts
3

 
—

 
3

3
 —
 3
Power:


 
 
 
 


    
Forwards
11

 
—

 
11

11
 —
 11
Futures
4

 
4

 
—

4
 4
 —
Options – Puts
1

 
1

 
—

Options – Calls
1

 
1

 
—

NGLs – Forwards/Swaps
260

 
260

 
—

Refined Products – Futures
8

 
8

 
—

Crude – Forwards/Swaps
13

 
13

 
—

Options – Puts1
 1
 —
Options – Calls1
 1
 —
NGLs – Forwards/Swaps260
 260
 —
Refined Products – Futures8
 8
 —
Crude – Forwards/Swaps13
 13
 —
Total commodity derivatives
384

 
369

 
15

384
 369
 15
Other non-current assets
31

 
20

 
11

31
 20
 11
Total assets
$
415

 
$
389

 
$
26

$415
 $389
 $26
Liabilities:
 
 
 
 
 
     
Interest rate derivatives
$
(399
)
 
$
—

 
$
(399
)
$(399) $—
 $(399)
Commodity derivatives:
 
 
 
 
 
     
Natural Gas:
 
 
 
 
 
     
Basis Swaps IFERC/NYMEX
(49
)
 
(49
)
 
—

(49) (49) —
Swing Swaps IFERC
(1
)
 
—

 
(1
)
(1) —
 (1)
Fixed Swaps/Futures
(43
)
 
(43
)
 
—

(43) (43) —
Power:


 
 
 
 


    
Forwards
(5
)
 
—

 
(5
)
(5) —
 (5)
Futures
(3
)
 
(3
)
 
—

(3) (3) —
NGLs – Forwards/Swaps
(278
)
 
(278
)
 
—

Refined Products – Futures
(10
)
 
(10
)
 
—

NGLs – Forwards/Swaps(278) (278) —
Refined Products – Futures(10) (10) —
Total commodity derivatives
(389
)
 
(383
)
 
(6
)
(389) (383) (6)
Total liabilities
$
(788
)
 
$
(383
)
 
$
(405
)
$(788) $(383) $(405)

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 June 30, 2020 was $52.92 billion and $51.21 billion, respectively. As of December 31, 2019, the aggregate fair value and carrying amount of our consolidated debt obligations was $54.66 billion and $50.93 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
6.
DEBT OBLIGATIONS
Notes and Debentures
ETO January 2020 Senior Notes Offering and Redemption
On January 22, 2020, ETO completed a registered offering (the “January“January 2020 Senior Notes Offering”Offering”) of$1.00 $1.00 billion aggregate principal amount of ETO’s 2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of the Partnership’s


16
2.900%Senior Notes due 2025,$1.50 billionaggregate principal amountTable of the Partnership’sContents

Partnership’s 3.750%Senior Notes due 2030 and$2.00 $2.00 billionaggregate principal amount of the Partnership’sETO’s 5.000%Senior Notes due 2050 (collectively, the “Notes”“Notes”). The Notes are fully and unconditionally guaranteed by the Partnership’sETO’s wholly-owned subsidiary, Sunoco Logistics Operations, on a senior unsecured basis.
Using proceeds from the January 2020 Senior Notes Offering, ETO redeemed its$400 $400 millionaggregate principal amount of5.75%Senior Notes due September 1, 2020, its$1.05 $1.05 billionaggregate principal amount of4.15%Senior Notes due October


15
Table of Contents

1, 2020, its$1.14 $1.14 billionaggregate principal amount of7.50%Senior Notes due October 15, 2020, its$250 $250 millionaggregate principal amount of5.50%Senior Notes due February 15, 2020, ET’s$52ET’s $52 millionaggregate principal amount of7.50%Senior Notes due October 15, 2020 and Transwestern’s$175Transwestern’s $175 millionaggregate principal amount of5.36%Senior Notes due December 9, 2020.
HFOTCO Long-Term Debt
In connection with the contribution transactions discussed in Note 2, HFOTCO became a wholly-owned subsidiary of ETO.ETO in February 2020. As ofMarch 31, June 30, 2020,, HFOTCO had$225 $225 millionoutstanding of tax exempt notes due 2050 (the "IKE Bonds"“Ike Bonds”). The IKEIke Bonds are fully and unconditionally guaranteed by the Partnership, on a senior unsecured basis. The indentures under which the IKEIke Bonds were issued are subject to customary representations and warranties and affirmative and negative covenants, the majority of which are substantially similar to those found in ETO’sETO’s revolving credit facility, as further discussed below.
Credit Facilities and Commercial Paper
ETO Term Loan
ETO’sETO’s term loan credit agreement provides for a $2$2 billion three-year term loan credit facility (the “ETO“ETO Term Loan”Loan”). Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreementETO Term Loan is unsecured and is guaranteed by ourETO’s subsidiary, Sunoco Logistics Operations.
As ofMarch 31, June 30, 2020,, the ETO Term Loan had$2 $2 billionoutstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as ofMarch 31, June 30, 2020was1.92% 1.18%.
ETO Five-Year Credit Facility
ETO’sETO’s revolving credit facility (the “ETO“ETO Five-Year Credit Facility”Facility”) allows for unsecured borrowings up to$5.00 $5.00 billionand matures on December 1, 2023. The ETO Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to$6.00 $6.00 billionunder certain conditions.
As ofMarch 31, June 30, 2020,, the ETO Five-Year Credit Facility had$1.96 $3.01 billion of outstanding borrowings, $113 million$1.11 billion of which was commercial paper. The amount available for future borrowings was$2.97 $1.90 billion,after taking into account letters of credit of$72 million. $86 million. The weighted average interest rate on the total amount outstanding as ofMarch 31, June 30, 2020was2.24% 1.34%.
ETO 364-Day Facility
ETO’sETO’s 364-day revolving credit facility (the “ETO“ETO 364-Day Facility”Facility”) allows for unsecured borrowings up to$1.00 $1.00 billionand matures on November 27, 2020.As ofMarch 31, June 30, 2020,, the ETO 364-Day Facility had0outstanding borrowings.
Sunoco LP Credit Facility
Sunoco LP maintains a$1.50 $1.50 billionrevolving credit facility (the “Sunoco“Sunoco LP Credit Facility”Facility”), which matures in July 2023. As ofMarch 31, June 30, 2020,, the Sunoco LP Credit Facility had$265 $158 millionof outstanding borrowings and$8 $8 millionin standby letters of credit. As ofMarch 31, June 30, 2020,, Sunoco LP had$1.23 $1.33 billion of availability under the Sunoco LP Credit Facility. The weighted average interest rate on the total amount outstanding as ofMarch 31, June 30, 2020 was 2.63%2.19%.
USAC Credit Facility
USAC maintains a$1.60 $1.60 billionrevolving credit facility (the “USAC“USAC Credit Facility”Facility”), with a further potential increase of$400 $400 million,, which matures in April 2023. As of March 31,June 30, 2020,, the USAC Credit Facility had$459 $448 millionof outstanding borrowings and0outstanding letters of credit. As ofMarch 31, June 30, 2020,, USAC had$1.14 $1.15 billionof borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of$186 $151 millionunder the USAC Credit Facility. The weighted average interest rate on the total amount outstanding as of June 30, 2020 was 2.77%.


17
Table of Contents

SemCAMS Credit Facilities
SemCAMS is party to a credit agreement providing for a C$350 million (US$257 million at the March 31,June 30, 2020 was 3.67%exchange rate) senior secured term loan facility, a C$525 million (US$385 million at the June 30, 2020exchange rate) senior secured revolving credit facility, and a C$300 million (US$220 million at theJune 30, 2020exchange rate) senior secured construction loan facility (the “KAPS Facility”). The term loan facility and the revolving credit facility mature on February 25, 2024. The KAPS Facility matures on June 13, 2024. SemCAMS may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250 million (US$183 million at the June 30, 2020exchange rate), subject to receiving commitments for such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders.As of June 30, 2020, the SemCAMS senior secured term loan facility and senior secured revolving credit facility had $251 million and $92 million, respectively, of outstanding borrowings. As of June 30, 2020, the KAPS Facility had0outstanding borrowings.
Compliance with Our Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as ofMarch 31, 2020. June 30, 2020.


16
Table of Contents

7.
REDEEMABLE NONCONTROLLING INTERESTS
Certain redeemable noncontrolling interests in the Partnership’sPartnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheets. Redeemable noncontrolling interests as of March 31,June 30, 2020 included a balance of $477$477 million related to the USAC Preferred Units described below and a balance of $15$15 million related to noncontrolling interest holders in one of the Partnership’sPartnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership. In addition, redeemable noncontrolling interests includes a balance of $258 million in SemCAMS preferred shares.
USAC Preferred Units
As of March 31,June 30, 2020,, USAC had 500,000 USAC Preferred Units issued and outstanding, whichoutstanding. The holders of these units are entitled to receive cumulative quarterly distributions equal to $24.375$24.375 per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed. Certain portions of the USAC Preferred Units will be convertible into USAC common units at the election of the holders beginning in 2021. To the extent the holders of the USAC Preferred Units have not elected to convert their preferred units by April 2, 2023, USAC will have the option to redeem all or any portion of the USAC Preferred Units for cash. In addition, at any time on or after the tenth anniversary of the issue date,April 2, 2028, the holders of the USAC Preferred Units will have the right to require USAC to redeem all or any portion of the USAC Preferred Units, and the Partnership may elect to pay up to 50% of such redemption amount in USAC common units.
SemCAMS Redeemable Preferred Stock
As of June 30, 2020, SemCAMS had 329,830 shares of cumulative preferred stock issued and outstanding. The preferred stock is redeemable at SemCAMS’s option subsequent to January 3, 2021 at a redemption price of C$1,100 (US$807 at the June 30, 2020 exchange rate) per share. The preferred stock is redeemable by the holder contingent upon a change of control or liquidation of SemCAMS. The preferred stock is convertible to SemCAMS common shares in the event of an initial public offering by SemCAMS. Dividends on the preferred stock may be paid in-kind through June 30, 2021.
8.
EQUITY
All of our common units are owned by ET.
Preferred Units
As of March 31,June 30, 2020 and December 31, 2019,, our outstanding preferred units included 950,000 Series A Preferred Units, 550,000 Series B Preferred Units, 18,000,000 Series C Preferred Units, 17,800,000 Series D Preferred Units and 32,000,000 Series E Preferred Units. As of March 31,June 30, 2020,, our outstanding preferred units also included 500,000 Series F Preferred Units and 1,100,000 Series G Preferred Units.


18
Table of Contents

The following table summarizes changes in the amounts of our Series A, Series B, Series C, Series D, Series E, Series F and Series G preferred units for the threesix months ended March 31,2020:June 30, 2020:
Preferred Unitholders
 
 
Preferred Unitholders  
Series A
 
Series B
 
Series C
 
Series D
 
Series E
 
Series F
 
Series G
 
Total
Series A Series B Series C Series D Series E Series F Series G Total
Balance, December 31, 2019
$
958

 
$
556

 
$
440

 
$
434

 
$
786

 
$
—

 
$
—

 
$
3,174

$958
 $556
 $440
 $434
 $786
 $—
 $—
 $3,174
Distributions to partners
(30
)
 
(18
)
 
(8
)
 
(9
)
 
(15
)
 
—

 
—

 
(80
)
(30) (18) (8) (9) (15) —
 —
 (80)
Units issued for cash
—

 
—

 
—

 
—

 
—

 
494

 
1,086

 
1,580

—
 —
 —
 —
 —
 494
 1,086
 1,580
Other, net
—

 
—

 
—

 
—

 
—

 
(1
)
 
(2
)
 
(3
)
—
 —
 —
 —
 —
 (1) (2) (3)
Net income
15

 
9

 
8

 
9

 
15

 
6

 
15

 
77

15
 9
 8
 9
 15
 6
 15
 77
Balance, March 31, 2020
$
943

 
$
547

 
$
440

 
$
434

 
$
786

 
$
499

 
$
1,099

 
$
4,748

943
 547
 440
 434
 786
 499
 1,099
 4,748
Distributions to partners—
 —
 (8) (8) (15) (11) (25) (67)
Other, net—
 —
 —
 —
 —
 (1) —
 (1)
Net income15
 9
 8
 8
 15
 9
 20
 84
Balance, June 30, 2020$958
 $556
 $440
 $434
 $786
 $496
 $1,094
 $4,764
The following table summarizes changes in the amounts of our Series A, Series B, Series C, Series D and Series DE preferred units for the threesix months endedMarch 31, 2019: June 30, 2019:
Preferred Unitholders
 
 
Preferred Unitholders  
Series A
 
Series B
 
Series C
 
Series D
 
Total
Series A Series B Series C Series D Series E Total
Balance, December 31, 2018
$
958

 
$
556

 
$
440

 
$
434

 
$
2,388

$958
 $556
 $440
 $434
 $—
 $2,388
Distributions to partners
(30
)
 
(18
)
 
(8
)
 
(8
)
 
(64
)
(30) (18) (8) (8) —
 (64)
Net income
15

 
9

 
8

 
8

 
40

15
 9
 8
 8
 —
 40
Balance, March 31, 2019
$
943

 
$
547

 
$
440

 
$
434

 
$
2,364

943
 547
 440
 434
 —
 2,364
Distributions to partners—
 —
 (9) (9) —
 (18)
Units issued for cash—
 —
 —
 —
 780
 780
Other, net—
 —
 —
 —
 (1) (1)
Net income15
 9
 9
 9
 11
 53
Balance, June 30, 2019$958
 $556
 $440
 $434
 $790
 $3,178

Series F Preferred Units
On January 22, 2020, the Partnership issued500,000of itsSeries F Preferred Units representing limited partner interest in the Partnership, at a price to the public of$1,000 $1,000 per unit. Distributions on the Series F Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of


17
Table of Contents

each year, commencing on May 15, 2020 to, but excluding, May 15, 2025, at a rate equal to6.750%per annum of the$1,000 $1,000 liquidation preference. On and after May 15, 2025, the distribution rate on the Series F Preferred Units will equal a percentage of the$1,000 $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of5.134%per annum. The Series F Preferred Units are redeemable at ETO’sETO’s option on or after May 15, 2025 at a redemption price of$1,000  $1,000 per Series F Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Series G Preferred Units
On January 22, 2020, the Partnership issued1,100,000of itsSeries G Preferred Units representing limited partner interest in the Partnership, at a price to the public of$1,000 $1,000 per unit. Distributions on the Series G Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2030, at a rate equal to7.125%per annum of the$1,000 $1,000 liquidation preference. On and after May 15, 2030, the distribution rate on the Series G Preferred Units will equal a percentage of the$1,000 $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of5.306%per annum. The Series G Preferred Units are redeemable at ETO’sETO’s option on or after May 15, 2030 at a redemption price of$1,000  $1,000 per Series G


19
Table of Contents

Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Subsidiary Equity Transactions
Sunoco LP Equity Distribution Program
For the threesix months endedMarch 31, June 30, 2020,, Sunoco LP issued 0 additional units under its at-the-market equity distribution program. As of March 31,June 30, 2020,, $295 $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement.
USAC Class B Conversion
On July 30, 2019, the 6,397,965USAC Class B units held by the Partnership converted into6,397,965common units representing limited partner interests in USAC. These common units will participate in any future distributions declared by USAC.
USAC Distribution Reinvestment Program
During the threesix months endedMarch 31, June 30, 2020,, distributions of $0.3$0.9 million were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately 18,88396,592 USAC common units.
Cash Distributions
Distributions on ETO’sETO’s preferred units declared and/or paid by the Partnership subsequent toDecember 31, 2019were as follows:
Period Ended
 
Record Date
 
Payment Date
 
Series A (1)
 
Series B (1)
 
Series C
 
Series D
 
Series E
 
Series F (2)
 
Series G (2)
 Record Date Payment Date 
Series A (1)
 
Series B (1)
 Series C Series D Series E 
Series F (2)
 
Series G (2)
December 31, 2019
 
February 3, 2020
 
February 18, 2020
 
$
31.25

 
$
33.125

 
$
0.4609

 
$
0.4766

 
0.4750

 
$
—

 
$
—

 February 3, 2020 February 18, 2020 $31.25
 $33.125
 $0.4609
 $0.4766
 0.4750
 $—
 $—
March 31, 2020
 
May 1, 2020
 
May 15, 2020
 
—

 
—

 
0.4609

 
0.4766

 
0.4750

 
21.19

 
22.36

 May 1, 2020 May 15, 2020 —
 —
 0.4609
 0.4766
 0.4750
 21.19
 22.36
June 30, 2020 August 3, 2020 August 17, 2020 31.25
 33.125
 0.4609
 0.4766
 0.4750
 —
 —

(1)       Series A Preferred Unit and Series B Preferred Unit distributions are paid on a semi-annual basis.
(2) 
Series F Preferred Unit and Series G Preferred Unit distributions related to the period ended March 31, 2020 represent a prorated initial distribution. Distributions are paid on a semi-annual basis.  
Sunoco LP Cash Distributions
Distributions declared and/or paid by Sunoco LP subsequent to its common unitholders subsequent to December 31, 2019were as follows:
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
 Record Date Payment Date Rate
December 31, 2019
 
February 7, 2020
 
February 19, 2020
 
$
0.8255

 February 7, 2020 February 19, 2020 $0.8255
March 31, 2020
 
May 7, 2020
 
May 19, 2020
 
0.8255

 May 7, 2020 May 19, 2020 0.8255
June 30, 2020 August 7, 2020 August 19, 2020 0.8255



18
Table of Contents

USAC Cash Distributions
Distributions declared and/or paid by USAC to its common unitholders subsequent toDecember 31, 2019were as follows:
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
 Record Date Payment Date Rate
December 31, 2019
 
January 27, 2020
 
February 7, 2020
 
$
0.5250

 January 27, 2020 February 7, 2020 $0.5250
March 31, 2020
 
April 27, 2020
 
May 8, 2020
 
0.5250

 April 27, 2020 May 8, 2020 0.5250
June 30, 2020 July 31, 2020 August 10, 2020 0.5250



20
Table of Contents

Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
March 31, 2020
 
December 31, 2019
June 30,
2020		 December 31,
2019
Available-for-sale securities
$
4

 
$
13

$13
 $13
Foreign currency translation adjustment
(5
)
 
(5
)
(32) (5)
Actuarial loss related to pensions and other postretirement benefits
(19
)
 
(25
)
(14) (25)
Investments in unconsolidated affiliates, net
(17
)
 
(1
)
(17) (1)
Subtotal(50) (18)
Amounts attributable to noncontrolling interest29
 —
Total AOCI, net of tax
$
(37
)
 
$
(18
)
$(21) $(18)

9.
INCOME TAXES
The Partnership’sPartnership’s effective tax rate differs from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level.
10.
REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
FERC Proceedings
By Order issued January 16, 2019, the FERC initiated a review of Panhandle’sPanhandle’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by the Order dated October 1, 2019.  A hearing in the combined proceedings is scheduled for August 2020, with an initial decision expected in early 2021.
Commitments
In the normal course of business, ETO purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETO believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.
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’affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
We have certain non-cancelable rights-of-way (“ROW”(“ROW”) commitments, which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The table below reflects ROW expense included in operating expenses in the accompanying consolidated statements of operations:
 
Three Months Ended
March 31,
 
2020
 
2019
ROW expense
$
9

 
$
6

 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2020 2019 2020 2019
ROW expense$10
 $6
 $19
 $12



19
Table of Contents

PES Refinery Fire and Bankruptcy
We ownpreviously owned an approximately 7.4% indirect non-operating interest in PES, which ownsowned a former refinery in Philadelphia. In addition, the Partnership providespreviously provided logistics services to PES under commercial contracts and Sunoco LP has historicallypreviously purchased refined products from PES. In June 2019, an explosion and fire occurred at the refinery complex.
On July 21, 2019, PES Holdings, LLC and seven of its subsidiaries (collectively, the "Debtors"“Debtors”) filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware seeking relief under the provisions of Chapter 11 of the United


21
Table of Contents

States Bankruptcy Code, as a result of the explosion and fire at the Philadelphia refinery complex. The Debtors have also defaulted on a $75$75 million note payable to a subsidiary of the Partnership. TheIn June 2020, the Partnership has notreceived $12 million from PES on the note payable and recorded a valuation allowance related toreserve for the remaining $63 million note receivable as of March 31, 2020, because management is not yet able to determine the collectability of the note in bankruptcy.balance.
In addition, the Partnership’sPartnership’s subsidiaries retained certain environmental remediation liabilities when the refinery was sold to PES. As of March 31,June 30, 2020, the Partnership has funded these environmental remediation liabilities through its wholly-owned captive insurance company, based upon actuarially determined estimates for such costs, and these liabilities are included in the total environmental liabilities discussed below under “Environmental“Environmental Remediation.” In the event that PES property is sold in connection with the bankruptcy proceeding, it” It may be necessary for the Partnership to record additional environmental remediation liabilities in the future depending upon the proposed use of such property by the buyer of the property;buyer; however, management is not currently able to estimate such additional liabilities.
PES has rejected certain of the Partnership’sPartnership’s commercial contracts pursuant to Section 365 of the Bankruptcy Code; however, the impact of the bankruptcy on the Partnership’sPartnership’s commercial contracts and related revenue loss (temporary or permanent) is unknown at this time. In addition, Sunoco LP has been successful at acquiring alternative supplies to replace fuel volume lost from PES and does not anticipate any material impact to its business going forward.
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.
Dakota Access Pipeline
On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”(“SRST”) filed a lawsuit in the United States District Court for the District of Columbia challenging permits issued by the United States Army Corps of Engineers (“USACE”(“USACE”) permitting Dakota Access, LLC (“(“Dakota Access”Access”) to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE allowing the pipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”(“CRST”) intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”(“OST”) and the Yankton Sioux Tribe (“YST”(“YST”) were consolidated with this action and several individual tribal members intervened (collectively with SRST and CRST, the “Tribes”“Tribes”). Plaintiffs and Defendants filed cross motions for summary judgment. On March 25, 2020, the Court remanded the case back to the USACE for preparation of an Environment Impact Statement. On July 6, 2020, the Court vacated the easement and ordered Dakota Access to be shut down and emptied of oil by August 5, 2020. Dakota Access and USACE have filed notices of appeal with the United States Court of Appeals for the District of Columbia (“Court of Appeals”) with respect to the Court’s ruling related to the preparation of an Environmental Impact Statement and also filed motions for a stay of the Court’s July 6, 2020 Order. On July 14, 2020, the Court of Appeals administratively stayed the Court’s July 6 Order and ordered further briefing with respect to the motion to stay. On August 5, 2020, the Court of Appeals granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil. The Court has requested briefing on whether to suspend operationof Appeals also denied a stay of the pipeline duringMarch 25 Order and the timeremaining portion of the July 6 Order vacating the easement. As a result, no court order stops Dakota Access from continuing to operate the Pipeline. The August 5 Order contemplates that the USACE conducts any additional environmental analysis. Briefing will make a determination under its regulations and procedures whether vacating the easement requires oil to stop flowing. The Order also contemplates further proceedings in the District Court, and it expedites the appeal with briefing to conclude on May 27,by September 30, 2020.
Energy Transfer cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.project, but expects after the law and complete record are fully considered, the issues in this litigation will be resolved in a manner that will allow the pipeline to continue to operate.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’soperator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“LLC’s (“Lone Star”Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’sStar’s South Terminal and damage to Lone Star’sStar’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’sStar’s storage wells, however,


2022
Table of Contents

however, Lone Star is still quantifying the extent of its incurred and ongoing damages and has obtained, and will continue to seek, reimbursement for these losses.
MTBE Litigation
ETC Sunoco Holdings LLC and Sunoco (R&M)&M), LLC (collectively, “Sunoco”“Sunoco”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’attorneys’ fees.
As ofMarch 31, June 30, 2020,, Sunoco is a defendant in5cases, including one case each initiated by the States of Maryland and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants ETO, ETP Holdco Corporation, and Sunoco Partners Marketing && Terminals L.P. (“SPMT”(“SPMT”).
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. 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 such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’sPartnership’s consolidated financial position.
Regency Merger Litigation
On June 10, 2015, Adrian Dieckman (“Dieckman”(“Dieckman”), a purported Regency unitholder, filed a class action complaint related to the Regency-ETO merger (the “Regency Merger”“Regency Merger”) in the Court of Chancery of the State of Delaware (the “Regency“Regency Merger Litigation”Litigation”), on behalf of Regency’sRegency’s common unitholders against Regency GP LP, Regency GP LLC, ET, ETO, ETP GP, and the members of Regency’sRegency’s board of directors.
The Regency Merger Litigation alleges that the Regency Merger breached the Regency partnership agreement. On March 29, 2016, the Delaware Court of Chancery granted the defendants’defendants’ motion to dismiss the lawsuit in its entirety. Plaintiff appealed, and the Delaware Supreme Court reversed the judgment of the Court of Chancery. Plaintiff then filed an Amended Verified Class Action Complaint, which defendants moved to dismiss. The Court of Chancery granted in part and denied in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP LP and Regency GP LLC (the “Regency Defendants”“Regency Defendants”). The Court of Chancery later granted Plaintiff’sPlaintiff’s unopposed motion for class certification. Trial was held on December 10-16, 2019, and a post-trial hearing was held on May 6, 2020.
The Regency Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it.
Rover
On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“(“Ohio EPA”EPA”) filed suit against Rover and other defendants (collectively, the Defendants”) seeking to recover civil penalties allegedly owed and certain injunctive relief related to permit compliance. The Defendantsdefendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court, which Defendantsthe defendants opposed in briefs filed in February 2020. On April 22, 2020, the Ohio Supreme Court granted the Ohio EPA’sEPA’s request for review. The briefing schedule forBriefing is underway and will conclude at the Ohio Supreme Court’s review has not yet been set.end of August 2020.
Bayou Bridge
On January 11, 2018, environmental groups and a trade association filed suit against the USACE in the United States District Court for the Middle District of Louisiana. Plaintiffs allege that the USACE’sUSACE’s issuance of permits authorizing the construction of the Bayou Bridge Pipeline through the Atchafalaya Basin (“Basin”(“Basin”) violated the National Environmental Policy Act, the Clean Water Act, and the Rivers and Harbors Act. They asked the district court to vacate these permits and to enjoin construction of the project through the Basin until the USACE corrects alleged deficiencies in its decision-making process. ETO, through its subsidiary Bayou Bridge Pipeline, LLC (“(“Bayou Bridge”Bridge”), intervened on January 26, 2018.


2123
Table of Contents

In February 2018, the District Court initially granted Plaintiffs’ motion for a preliminary injunction, but the Fifth Circuit Court of Appeals subsequently vacated that decision. The Fifth Circuit’s ruling allowed construction to continue and be completed during the pendency of the case. Plaintiffs filed a second motion for preliminary injunction in January 2019, which was denied. Plaintiffs and Defendants filed cross motions for summary judgment. On March 25, 2020, the Court granted summary judgment in favor of the USACE. Plaintiffs have until May 26, 2020 to file a notice of appeal.did not appeal by the deadline, and the case has concluded.
Revolution
On September 10, 2018, a pipeline release and fire (the “Incident”“Incident”) occurred on the Revolution pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no injuries. On February 8, 2019, the Pennsylvania Department of Environmental Protection (“PADEP”(“PADEP”) issued a Permit Hold on any requests for approvals/permits or permit amendments for any project in Pennsylvania pursuant to the state’sstate’s water laws. The Partnership filed an appeal of the Permit Hold with the Pennsylvania Environmental Hearing Board. On January 3, 2020, the Partnership entered into a Consent Order and Agreement with the DepartmentPADEP in which, among other things, the Permit Hold was lifted, the Partnership agreed to pay a$28.6 $28.6 millioncivil penalty and fund a$2 $2 millioncommunity environmental project, and all related appeals were withdrawn.
The Pennsylvania Office of Attorney General has commenced an investigation regarding the Incident, and the United States Attorney for the Western District of Pennsylvania has issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time.
Chester County, Pennsylvania Investigation
In December 2018, the former Chester County District Attorney (“DA”(“DA”) sent a letter to the Partnership stating that his office was investigating the Partnership and related entities for “potential crimes”“potential crimes” related to the Mariner East pipelines.
Subsequently, the matter was submitted to an Investigating Grand Jury in Chester County, Pennsylvania, which has issued subpoenas seeking documents and testimony. On September 24, 2019, the former DA sent a Notice of Intent to the Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership responded to the Notice of Intent within the proscribed time period. To date, the Partnership is not aware of any further action with regard to this Notice.
In December 2019, the former DA announced charges against a current employee related to the provision of security services. The Partnership has secured independent counsel forOn June 25, 2020, a preliminary hearing was held on the employee. Whilecharges against the Partnership will continue to cooperate withemployee, and the investigation, it intends to vigorously defend itself.judge dismissed all charges.
Delaware County, Pennsylvania Investigation
On March 11, 2019, the Delaware County District Attorney’sAttorney’s Office (“DA”(“DA”) announced that the DA and the Pennsylvania Attorney General’sGeneral’s Office, at the request of the DA, are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. The Partnership has not been appraised ofOn March 16, 2020, the specific conduct under investigation.Pennsylvania Attorney General Office served a Statewide Investigating Grand Jury subpoena for documents relating to inadvertent returns and water supplies related to the Mariner East pipelines. While the Partnership will cooperate with the investigation,subpoena, it intends to vigorously defend itself.
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 ofMarch 31, June 30, 2020andDecember 31, 2019,, accruals of approximately$94 $92 millionand$98 $98 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.
In addition, other legal proceedings exist that are considered reasonably possible to result in unfavorable outcomes.   For those where possible losses can be estimated, the range of possible losses related to these contingent obligations is estimated to be up to$80 million; $80 million; however,noaccruals have been recorded as ofMarch 31, June 30, 2020 or December 31, 2019.2019.


2224
Table of Contents

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. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. 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, natural resource damages, 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 theour 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.
In February 2017, we received letters from the DOJ on behalf of EPA and Louisiana Department of Environmental Quality (“LDEQ”(“LDEQ”) notifying SPLP and Mid-Valley Pipeline Company (“Mid-Valley”(“Mid-Valley”) that enforcement actions were being pursued for three separate crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”(“Colmesneil”) which allegedly occurred in February 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) which allegedly occurred in October 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma which allegedly occurred in January 2015. In January 2019, a Consent Decree approved by all parties as well as an accompanying Complaint was filed in the United States District Court for the Western District of Louisiana seeking public comment and final court approval to resolve all penalties with the DOJ and LDEQ for the three releases. Subsequently, the court approved the Consent Decree and the penalty payment of $5.4$5.4 millionwas satisfied. The Consent Decree requires certain injunctive relief to be completed on the Longview-to-Mayersville pipeline within three years but the injunctive relief is not expected to have any material impact on operations. In addition to resolution of the civil penalty and injunctive relief, we continue to discuss natural resource damages with the Louisiana trustees related to the Caddo Parish, Louisiana release.
In October 2018, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”(“PHMSA”) issued a notice of proposed safety order (the “Notice”“Notice”) to SPMT, a wholly-owned subsidiary of ETO. The Notice alleged that conditions exist on certain pipeline facilities owned and operated by SPMT in Nederland, Texas that pose a pipeline integrity risk to public safety, property or the environment. The Notice also made preliminary findings of fact and proposed corrective measures. SPMT responded to the Notice by submitting a timely written response on November 2, 2018, attended an informal consultation held on January 30, 2019 and entered into a consent agreement with PHMSA resolving the issues in the Notice as of March 2019. SPMT is currently awaiting response from PHMSA regarding the approval status of the submitted Remedial Work Plan.
On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to$1 $1 millionrelated to a May 2018 rupture near Edmond, Oklahoma.   The release occurred on the Noble to Douglas 8”8” pipeline in an area of external corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediately to the release and remediated the surrounding environment and pipeline in cooperation with the OCC.  The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the pipeline causing the failure.   SPLP is negotiating a settlement agreement with the OCC for a lesser penalty. The OCC has accepted our counter offer in conjunction with a proposed consent order. The Consent Order will be presented to the OCC at a final hearing, the date of which is to be determined.


2325
Table of Contents

Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
•
•
certainCertain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of polychlorinated biphenyls (“PCBs”(“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could be contractually responsible for contamination caused by other parties.
Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
•
•
certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
•
legacyLegacy sites related to Sunoco that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites.
•
•
Sunoco 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”(“PRP”). As ofMarch 31, June 30, 2020,, Sunoco had been named as a PRP at approximately29 30 identified or potentially identifiable “Superfund”“Superfund” sites under federal and/or comparable state law. Sunoco is usually one of a number of companies identified as a PRP at a site. Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’sSunoco’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, 2020
 
December 31, 2019
June 30,
2020		 December 31,
2019
Current
$
42

 
$
46

$43
 $46
Non-current
271

 
274

261
 274
Total environmental liabilities
$
313

 
$
320

$304
 $320

We have 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 thethree months ended March 31,June 30, 2020and2019,, the Partnership recorded$8 $7 millionand$6 $9 million,, respectively, of expenditures related to environmental cleanup programs. During the six months ended June 30, 2020 and 2019, the Partnership recorded $15 million and $15 million, respectively, of expenditures related to environmental cleanup programs.
Our pipeline operations are subject to regulation by the United States Department of Transportation under PHMSA, pursuant to which PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, 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“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.


2426
Table of Contents

Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Safety and Health Administration’sAdministration’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 past costs for OSHA required activities, including general 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.
REVENUE
Disaggregation of Revenue
The Partnership’sPartnership’s consolidated financial statements reflect eight reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes. Note 14 depicts the disaggregation of revenue by segment.
Contract Balances with Customers
The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability.
The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services.
The Partnership recognizes a contract liability if the customer'scustomer’s payment of consideration precedes the Partnership’sPartnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed fee for a right to use our assets, but allowsallow customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.
The following table summarizes the consolidated activity of our contract liabilities:
Contract Liabilities
Contract Liabilities
Balance, December 31, 2019
$
375

$377
Additions
178

413
Revenue recognized
(205
)
(405)
Balance, March 31, 2020
$
348

Balance, June 30, 2020$385
 
 
Balance, December 31, 2018
$
394

$394
Additions
148

300
Revenue recognized
(162
)
(315)
Balance, March 31, 2019
$
380

Balance, June 30, 2019$379

The balances of receivables from contracts with customers listed in the table below include both current trade receivables and long-term receivables, net of allowance for doubtful accounts.expected credit losses. The allowance for receivablesexpected credit losses represents Sunoco LP’sLP's best estimate of the probable losses associated with potential customer defaults. Sunoco LP determinesestimates the allowanceexpected credit losses based on historical write-off experience by industry and on a specific identification basis.current expectations of future credit losses.


2527
Table of Contents

The balances of Sunoco LP’sLP’s contract assets as of March 31,June 30, 2020 and December 31, 2019 were as follows:
March 31, 2020
 
December 31, 2019
June 30,
2020		 December 31,
2019
Contract asset balances:
 
 
 
   
Contract asset
$
128

 
$
117

Contract assets$128
 $117
Accounts receivable from contracts with customers
140

 
366

263
 366

Costs to Obtain or Fulfill a Contract
Sunoco LP recognizes an asset from the costs incurred to obtain a contract (e.g., sales commissions) only if it expects to recover those costs. On the other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that will be used in satisfying performance obligations in the future, and are expected to be recovered. These capitalized costs are recorded as a part of other current assets and other non-current assets and are amortized on a systematic basis consistent with the pattern of transfer of the goods or services to which such costs relate. The amount of amortization expense that Sunoco LP recognized for thethree months endedMarch 31, June 30, 2020 and 2019 was $5$5 million and $4$4 million,, respectively. The amount of amortization expense that Sunoco LP recognized for the six months ended June 30, 2020 and 2019 was $10 million and $8 million, respectively. Sunoco LP has also made a policy election of expensing the costs to obtain a contract, as and when they are incurred, in cases where the expected amortization period is one year or less.
12.
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 in 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 utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. 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. 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’ssegment’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


28
Table of Contents

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.


26
Table of Contents

The following table details our outstanding commodity-related derivatives:
March 31, 2020
 
December 31, 2019
June 30, 2020 December 31, 2019
Notional Volume
 
Maturity
 
Notional Volume
 
Maturity
Notional Volume Maturity Notional Volume Maturity
Mark-to-Market Derivatives
 
 
 
 
    
(Trading)
 
 
 
 
    
Natural Gas (BBtu):
 
 
 
 
    
Basis Swaps IFERC/NYMEX (1)
(19,673
)
 
2020-2024
 
(35,208
)
 
2020-2024
(20,433) 2020-2024 (35,208) 2020-2024
Fixed Swaps/Futures
1,688

 
2020-2021
 
1,483

 
2020
373
 2020-2021 1,483
 2020
Power (Megawatt):
 
 
 
 
    
Forwards
2,125,200

 
2020-2029
 
3,213,450

 
2020-2029
1,338,776
 2020-2029 3,213,450
 2020-2029
Futures
329,896

 
2020-2021
 
(353,527
)
 
2020
204,090
 2020-2021 (353,527) 2020
Options – Puts
621,860

 
2020
 
51,615

 
2020
Options – Calls
4,035,972

 
2020-2021
 
(2,704,330
)
 
2020-2021
Options – Puts(340,743) 2020 51,615
 2020
Options – Calls(1,268,532) 2020-2021 (2,704,330) 2020-2021
(Non-Trading)
 
 
 
 
    
Natural Gas (BBtu):
 
 
 
 
    
Basis Swaps IFERC/NYMEX
(15,860
)
 
2020-2022
 
(18,923
)
 
2020-2022
(27,713) 2020-2022 (18,923) 2020-2022
Swing Swaps IFERC
31,505

 
2020-2021
 
(9,265
)
 
2020
(35,590) 2020-2021 (9,265) 2020
Fixed Swaps/Futures
(1,425
)
 
2020-2022
 
(3,085
)
 
2020-2021
(10,708) 2020-2022 (3,085) 2020-2021
Forward Physical Contracts
(36,691
)
 
2020-2021
 
(13,364
)
 
2020-2021
(23,980) 2020-2021 (13,364) 2020-2021
NGLs (MBbls) – Forwards/Swaps
(2,235
)
 
2020-2022
 
(1,300
)
 
2020-2021
Refined Products (MBbls) – Futures
(1,779
)
 
2020-2022
 
(2,473
)
 
2020-2021
Crude (MBbls) – Forwards/Swaps
5,260

 
2020
 
4,465

 
2020
NGLs (MBbls) – Forwards/Swaps(8,830) 2020 (1,300) 2020-2021
Refined Products (MBbls) – Futures(3,370) 2020-2022 (2,473) 2020-2021
Crude (MBbls) – Forwards/Swaps3,393
 2020 4,465
 2020
Corn (thousand bushels)
(140
)
 
2020
 
(1,210
)
 
2020
—
 — (1,210) 2020
Fair Value Hedging Derivatives
 
 
 
 
    
(Non-Trading)
 
 
 
 
    
Natural Gas (BBtu):
 
 
 
 
    
Basis Swaps IFERC/NYMEX
(32,695
)
 
2020-2021
 
(31,780
)
 
2020
(43,235) 2020-2021 (31,780) 2020
Fixed Swaps/Futures
(32,695
)
 
2020-2021
 
(31,780
)
 
2020
(43,235) 2020-2021 (31,780) 2020
Hedged Item – Inventory
32,695

 
2020-2021
 
31,780

 
2020
Hedged Item – Inventory43,235
 2020-2021 31,780
 2020

(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.


2729
Table of Contents

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
 
Type(1)
 Notional Amount Outstanding
March 31, 2020
 
December 31, 2019
June 30,
2020		 December 31,
2019
July 2020(2)(3)
 
Forward-starting to pay a fixed rate of 3.52% and receive a floating rate
 
$
—

 
$
400

 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate $—
 $400
July 2021(2)
 
Forward-starting to pay a fixed rate of 3.55% and receive a floating rate
 
400

 
400

 Forward-starting to pay a fixed rate of 3.55% and receive a floating rate 400
 400
July 2022(2)
 
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
 
400

 
400

 Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 400
 400

(1) 
Floating rates are based on 3-month LIBOR.  
(2) 
Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.  
(3) 
The July 2020 interest rate swaps were terminated in January 2020.
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’sPartnership’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’sPartnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, 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 with 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.


2830
Table of Contents

Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
 
Fair Value of Derivative Instruments
 Fair Value of Derivative Instruments
 
Asset Derivatives
 
Liability Derivatives
 Asset Derivatives Liability Derivatives
 
March 31, 2020
 
December 31, 2019
 
March 31, 2020
 
December 31, 2019
 June 30,
2020		 December 31,
2019		 June 30,
2020		 December 31,
2019
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
 
        
Commodity derivatives (margin deposits)
 
$
11

 
$
24

 
$
(12
)
 
$
—

 $18
 $24
 $(22) $—
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
 
        
Commodity derivatives (margin deposits)
 
615

 
319

 
(561
)
 
(350
)
 370
 319
 (367) (350)
Commodity derivatives
 
74

 
41

 
(58
)
 
(39
)
 67
 41
 (77) (39)
Interest rate derivatives
 
—

 
—

 
(573
)
 
(399
)
 —
 —
 (577) (399)
 
689

 
360

 
(1,192
)
 
(788
)
 437
 360
 (1,021) (788)
Total derivatives
 
$
700

 
$
384

 
$
(1,204
)
 
$
(788
)
 $455
 $384
 $(1,043) $(788)

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
 Asset Derivatives Liability Derivatives
 
Balance Sheet Location
 
March 31, 2020
 
December 31, 2019
 
March 31, 2020
 
December 31, 2019
 Balance Sheet Location June 30,
2020		 December 31,
2019		 June 30,
2020		 December 31,
2019
Derivatives without offsetting agreements
 
Derivative liabilities
 
$
—

 
$
—

 
$
(573
)
 
$
(399
)
 Derivative liabilities $—
 $—
 $(577) $(399)
Derivatives in offsetting agreements:
Derivatives in offsetting agreements:
 
 
 
 
 
 
 
 
Derivatives in offsetting agreements:        
OTC contracts
 
Derivative assets (liabilities)
 
74

 
41

 
(58
)
 
(39
)
 Derivative assets (liabilities) 67
 41
 (77) (39)
Broker cleared derivative contracts
 
Other current assets (liabilities)
 
626

 
343

 
(573
)
 
(350
)
 Other current assets (liabilities) 388
 343
 (389) (350)
Total gross derivatives
Total gross derivatives
 
700

 
384

 
(1,204
)
 
(788
)
Total gross derivatives 455
 384
 (1,043) (788)
Offsetting agreements:
Offsetting agreements:
 
 
 
 
 
 
 
 
Offsetting agreements:        
Counterparty netting
 
Derivative assets (liabilities)
 
(49
)
 
(18
)
 
49

 
18

 Derivative assets (liabilities) (53) (18) 53
 18
Counterparty netting
 
Other current assets (liabilities)
 
(551
)
 
(318
)
 
551

 
318

 Other current assets (liabilities) (349) (318) 349
 318
Total net derivatives
Total net derivatives
 
$
100

 
$
48

 
$
(604
)
 
$
(452
)
Total net derivatives $53
 $48
 $(641) $(452)

We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or non-current depending on the anticipated settlement date.


2931
Table of Contents

The following tables summarizetable summarizes the location and amounts recognized in incomeour consolidated statements of operations with respect to our derivative financial instruments:
Location of Gain (Loss) Recognized in Income on Derivatives
 
Amount of Gain (Loss) Recognized in Income on Derivatives
Location Amount of Gain (Loss) on Derivatives
 
Three Months Ended
March 31,
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 
2020
 
2019
 2020 2019 2020 2019
Derivatives not designated as hedging instruments:
 
 
 
 
        
Commodity derivatives – Trading
Cost of products sold
 
$
5

 
$
5

Commodity derivatives – Non-trading
Cost of products sold
 
112

 
(12
)
Commodity derivatives – TradingCost of products sold $(5) $(20) $11
 $(14)
Commodity derivatives – Non-tradingCost of products sold (96) (29) 97
 (41)
Interest rate derivatives
Losses on interest rate derivatives
 
(329
)
 
(74
)
Losses on interest rate derivatives (3) (122) (332) (196)
Total
 
$
(212
)
 
$
(81
)
 $(104) $(171) $(224) $(251)

13.
RELATED PARTY TRANSACTIONS
ET-ETO Promissory Note
As of March 31,June 30, 2020 and December 31, 2019,, ETO’s ETO’s promissory note receivable from ET had an outstanding balance of $3.23$3.0 billion and $3.71$3.7 billion,, respectively, and ETO’sETO’s long-term intercompany payable to ET had an outstanding balance of $120$135 million and $104$104 million,, respectively. The outstanding promissory note receivable and intercompany payable are reflected on a net basis in the Partnership’sPartnership’s consolidated balance sheets.
Interest income attributable to promissory notes from ET included in other income, net in our consolidated statements of operations for the three months endedMarch 31, June 30, 2020 and 2019 was $44$38 million and $21$67 million. respectively. Interest income attributable to promissory notes from ET included in other income, net in our consolidated statements of operations for the six months ended June 30, 2020 and 2019 was $82 million. and $88 million, respectively.
ETO-SemGroup Long-Term Notes
In December 2019, in connection with the SemGroup acquisition, ETO and SemGroup entered into an intercompany promissory note for an aggregate amount up to $2.5 billion that accrues interest at 5.20% per annum. The ETO-SemGroup promissory note matures on December 31, 2029. As of March 31, 2020 and December 31, 2019, the ETO-SemGroup promissory note had an outstanding balance of $2.19 billion and $2.32 billion, respectively.
The Partnership also has related party transactions with several of its unconsolidated affiliates. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets.
The following table summarizes the revenues from related companies on our consolidated statements of operations:
 
Three Months Ended
March 31,
 
2020
 
2019
Revenues from related companies
$
133

 
$
109

 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2020 2019 2020 2019
Revenues from related companies$142
 $136
 $275
 $245



3032
Table of Contents

The following table summarizes the accounts receivable from and accounts payable to related companies on our consolidated balance sheets:
March 31, 2020
 
December 31, 2019
June 30,
2020		 December 31,
2019
Accounts receivable from related companies:
 
 
 
   
ET
$
7

 
$
8

$—
 $8
FGT
20

 
50

13
 50
Phillips 66
11

 
36

9
 36
Traverse
54

 
42

62
 42
Other
46

 
39

55
 31
Total accounts receivable from related companies
$
138

 
$
175

$139
 $167
 
 
 
   
Accounts payable to related companies:
 
 
 
   
ET
$
1,029

 
$
1,085

$21
 $—
Other
8

 
27

15
 31
Total accounts payable to related companies
$
1,037

 
$
1,112

$36
 $31

14.
REPORTABLE SEGMENTS
Our financial statements currently reflect the following reportable segments, which conduct their business primarily in the United States:
••intrastate transportation and storage;storage;
••interstate transportation and storage;storage;
••midstream;midstream;
••NGL and refined products transportation and services;services;
••crude oil transportation and services;services;
••investment in Sunoco LP;LP;
••investment in USAC;USAC; and
••all other.other.
Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.
Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our crude oil transportation and services segment are primarily reflected in crude sales. Revenues from our investment in Sunoco LP segment are primarily reflected in refined product sales. Revenues from our investment in USAC segment are primarily reflected in gathering, transportation and other fees. Revenues from our all other segment are primarily reflected in natural gas sales.sales and gathering, transportation and other fees.
We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership 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, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Inventory adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at last-in, first-out (“LIFO”). These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.


33
Table of Contents

Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted


31
Table of Contents

EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.  The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.


34
Table of Contents

The following tables present financial information by segment:
Three Months Ended
March 31,
Three Months Ended
June 30,		 Six Months Ended
June 30,
2020
 
2019*
2020 2019 2020 2019
Revenues:
 
 
 
       
Intrastate transportation and storage:
 
 
 
       
Revenues from external customers
$
536

 
$
769

$465
 $671
 $1,001
 $1,440
Intersegment revenues
57

 
87

51
 94
 108
 181
593

 
856

516
 765
 1,109
 1,621
Interstate transportation and storage:
 
 
 
       
Revenues from external customers
459

 
492

440
 487
 899
 979
Intersegment revenues
5

 
6

5
 6
 10
 12
464

 
498

445
 493
 909
 991
Midstream:
 
 
 
       
Revenues from external customers
501

 
663

391
 337
 892
 1,000
Intersegment revenues
669

 
1,055

627
 861
 1,296
 1,916
1,170

 
1,718

1,018
 1,198
 2,188
 2,916
NGL and refined products transportation and services:
 
 
 
       
Revenues from external customers
2,118

 
2,713

1,666
 2,356
 3,784
 5,069
Intersegment revenues
597

 
318

453
 256
 1,050
 574
2,715

 
3,031

2,119
 2,612
 4,834
 5,643
Crude oil transportation and services:
 
 
 
       
Revenues from external customers
4,213

 
4,167

1,811
 5,012
 6,024
 9,179
Intersegment revenues
—

 
19

28
 34
 28
 53
4,213

 
4,186

1,839
 5,046
 6,052
 9,232
Investment in Sunoco LP:
 
 
 
       
Revenues from external customers
3,260

 
3,692

2,043
 4,474
 5,303
 8,166
Intersegment revenues
12

 
—

37
 1
 49
 1
3,272

 
3,692

2,080
 4,475
 5,352
 8,167
Investment in USAC:
 
 
 
       
Revenues from external customers
176

 
167

166
 169
 342
 336
Intersegment revenues
3

 
4

3
 5
 6
 9
179

 
171

169
 174
 348
 345
All other:
 
 
 
       
Revenues from external customers
305

 
458

356
 371
 720
 829
Intersegment revenues
149

 
39

136
 20
 285
 59
454

 
497

492
 391
 1,005
 888
Eliminations
(1,492
)
 
(1,528
)
(1,340) (1,277) (2,832) (2,805)
Total revenues
$
11,568

 
$
13,121

$7,338
 $13,877
 $18,965
 $26,998

*As adjusted. See Note 1.


3235
Table of Contents

Three Months Ended
March 31,
Three Months Ended
June 30,		 Six Months Ended
June 30,
2020
 
2019*
2020 2019* 2020 2019*
Segment Adjusted EBITDA:
 
 
 
       
Intrastate transportation and storage
$
240

 
$
252

$187
 $290
 $427
 $542
Interstate transportation and storage
404

 
456

403
 460
 807
 916
Midstream
383

 
382

367
 412
 750
 794
NGL and refined products transportation and services
663

 
612

674
 644
 1,337
 1,256
Crude oil transportation and services
591

 
744

519
 752
 1,110
 1,496
Investment in Sunoco LP
209

 
153

182
 152
 391
 305
Investment in USAC
106

 
101

105
 105
 211
 206
All other
19

 
33

4
 13
 46
 46
Total
2,615

 
2,733

2,441
 2,828
 5,079
 5,561
Depreciation, depletion and amortization
(851
)
 
(771
)
(934) (781) (1,799) (1,552)
Interest expense, net of interest capitalized
(595
)
 
(527
)
(578) (578) (1,178) (1,105)
Impairment losses
(1,325
)
 
(50
)
(4) —
 (1,329) (50)
Losses on interest rate derivatives
(329
)
 
(74
)
(3) (122) (332) (196)
Non-cash compensation expense
(18
)
 
(29
)
(41) (29) (63) (58)
Unrealized gains on commodity risk management activities
51

 
49

Unrealized gains (losses) on commodity risk management activities(48) (23) 3
 26
Losses on extinguishments of debt
(59
)
 
(2
)
—
 —
 (59) (2)
Inventory valuation adjustments
(227
)
 
93

Inventory valuation adjustments (Sunoco LP)90
 4
 (137) 97
Adjusted EBITDA related to unconsolidated affiliates
(154
)
 
(146
)
(157) (163) (311) (309)
Equity in earnings (losses) of unconsolidated affiliates
(7
)
 
65

Equity in earnings of unconsolidated affiliates85
 77
 78
 142
Other, net
45

 
4

(34) 104
 (20) 108
Income (loss) before income tax expense
(854
)
 
1,345

817
 1,317

(68)
2,662
Income tax expense
(53
)
 
(126
)
(98) (35) (127) (161)
Net income (loss)
$
(907
)
 
$
1,219

$719
 $1,282
 $(195) $2,501

 June 30,
2020		 December 31, 2019*
Segment assets:   
Intrastate transportation and storage$6,972
 $6,648
Interstate transportation and storage17,413
 18,111
Midstream19,132
 20,332
NGL and refined products transportation and services21,803
 19,145
Crude oil transportation and services21,481
 22,933
Investment in Sunoco LP4,985
 5,438
Investment in USAC3,058
 3,730
All other3,640
 5,959
Total segment assets$98,484
 $102,296

 
March 31, 2020
 
December 31, 2019*
Segment assets:
 
 
 
Intrastate transportation and storage
$
6,851

 
$
6,648

Interstate transportation and storage
17,263

 
18,111

Midstream
18,969

 
20,332

NGL and refined products transportation and services
17,082

 
19,145

Crude oil transportation and services
24,832

 
22,933

Investment in Sunoco LP
4,895

 
5,438

Investment in USAC
3,103

 
3,730

All other
5,918

 
6,468

Total segment assets
$
98,913

 
$
102,805

*As adjusted. See Note 1.


3336
Table of Contents

ITEM 2. MANAGEMENT’SMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Tabular dollar and unit amounts are in millions)
The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q; and (ii) the consolidated financial statements and management’smanagement’s discussion and analysis of financial condition and results of operations included in the Partnership’sPartnership’s Annual Report on Form 10-K for the year ended December 31, 2019 filed with the SEC on February 21, 2020. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Part“Part I –– Item 1A. Risk Factors”Factors” of our Annual Report on Form 10-K for the year ended December 31, 2019 filed with the SEC on February 21, 2020, and “Part “Part II - Item 1A. Risk Factors”Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 filed with the SEC on May 11, 2020 and “Part II - Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q. Additional information on forward-looking statements is discussed below in “Forward-Looking“Forward-Looking Statements.””
References to “we,” “us,” “our,”“we,” “us,” “our,” the “Partnership”“Partnership” and “ETO”“ETO” shall mean Energy Transfer Operating, L.P. and its subsidiaries.
RECENT DEVELOPMENTS
COVID-19
In the first quarter of 2020, the COVID-19 pandemic prompted several states and municipalities in which we operate to take extraordinary and wide-ranging actions to contain and combat the outbreak and spread of the virus, including mandates for many individuals to substantially restrict daily activities and for many businesses to curtail or cease normal operations. To the extent COVID-19 continues or worsens, governments may impose additional similar restrictions. As a provider of critical energy infrastructure, our business has been designated as a “critical"critical infrastructure sector”sector" and our employees as “essential"essential critical infrastructure workers”workers" pursuant to the Department of Homeland Security Guidance on Essential Critical Infrastructure Workforce(s). To date, our field operations have continued largely uninterrupted, and remote work and other COVID-19 related conditions have not significantly impacted our ability to maintain operations or caused us to incur significant additional expenses; however, we are unable to predict the magnitude or duration of current and potential future COVID-19 mitigation measures. As an essential business providing critical energy infrastructure, the safety of our employees and the continued operation of our assets are our top priorities and we will continue to operate in accordance with federal and state health guidelines and safety protocols. We have implemented several new policies and provided employee training to help maintain the health and safety of our workforce.
ET Contribution of SemGroup Assets to ETO
On December 5, 2019, ET completed the acquisition of SemGroup. During the first quarterand second quarters of 2020, ET contributed certain SemGroup assets to ETO through sale and contribution transactions. The Partnership and SemGroup are under common control by ET subsequent to ET’sET’s acquisition of SemGroup; therefore, these transactions were accounted for as reorganizations of entities under common control. Accordingly, beginning with the quarter ending March 31, 2020, the Partnership’sPartnership’s consolidated financial statements have been retrospectively adjusted to reflect the consolidation of the contributed SemGroup businesses beginning December 5, 2019 (the date ET acquired SemGroup).
ETO Series F and Series G Preferred Units Issuance
On January 22, 2020, ETO issued 500,000 of its Series F Preferred Units at a price of $1,000$1,000 per unit and 1,100,000 of its Series G Preferred Units at a price of $1,000$1,000 per unit. The net proceeds were used to repay amounts outstanding under ETO’sETO's revolving credit facility and for general partnership purposes.
ETO January 2020 Senior Notes Offering and Redemption
On January 22, 2020, ETO completed a registered offering (the “January“January 2020 Senior Notes Offering”Offering”) of$1.00 $1.00 billion aggregate principal amount of ETO’s 2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of the Partnership’s2.900%Senior Notes due 2025,$1.50 billionaggregate principal amount of the Partnership’sPartnership’s 3.750%Senior Notes due 2030 and$2.00 $2.00 billionaggregate principal amount of the Partnership’sETO’s 5.000%Senior Notes due 2050 (collectively, the “Notes”“Notes”). The Notes are fully and unconditionally guaranteed by the Partnership’sETO’s wholly-owned subsidiary, Sunoco Logistics Operations, on a senior unsecured basis.
Using proceeds from the January 2020 Senior Notes Offering, ETO redeemed its$400 $400 millionaggregate principal amount of5.75%Senior Notes due September 1, 2020, its$1.05 $1.05 billionaggregate principal amount of4.15%Senior Notes due October 1, 2020, its$1.14 $1.14 billionaggregate principal amount of7.50%Senior Notes due October 15, 2020, its$250 $250 millionaggregate principal amount of5.50%Senior Notes due February 15, 2020, ET’s$52ET’s $52 millionaggregate principal amount of7.50%Senior Notes due October 15, 2020 and Transwestern’s$175Transwestern’s $175 millionaggregate principal amount of5.36%Senior Notes due December 9, 2020.


3437
Table of Contents

Lake Charles LNG
On March 30, 2020, Shell Royal Dutch Plc announced that it would not proceed with a proposed equity interest in the Lake Charles LNG liquefaction project due to adverse market factors affecting Shell's business and its desire to preserve cash in light of the current environment. We intend to continue to develop the project, possibly in conjunction with one or more equity partners, and we plan to evaluate a variety of alternatives to advance the project, including the possibility of reducing the size of the project from three trains (16.45 million tonnes per annum of LNG capacity) to two trains (11.0 million tonnes per annum). The project is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets. In light of the existing brownfield infrastructure and the advanced state of the development of the project, we plan to continue to pursue the project on a disciplined, cost effective basis, and ultimately we will determine whether to make a final investment decision to proceed with the project based on market conditions, capital expenditure considerations and our success in securing equity participation by third parties as well as long-term LNG offtake commitments on satisfactory terms.
Regulatory Update
Interstate Natural Gas Transportation Regulation
Rate Regulation
Effective January 2018, the 2017 Tax and Jobs Act (the “Tax Act”"Tax Act") changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“("Revised Policy Statement”Statement") stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost of service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover”"double recover" its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’investors' income tax costs. In light of the rehearing order, the impacts of the FERC’sFERC's policy on the treatment of income taxes may have on the rates ETO can charge for the FERC regulated transportation services are unknown at this time.
The FERC also issued a Notice of Inquiry (“(“2017 Tax Law NOI”NOI”) on March 15, 2018, requesting comments on the effect of the Tax Act on FERC jurisdictional rates. The 2017 Tax Law NOI states that of particular interest to the FERC is whether, and if so how, the FERC should address changes relating to accumulated deferred income taxes and bonus depreciation. Comments in response to the 2017 Tax Law NOI were due on or before May 21, 2018.
In March 2019, following the decision of the D.C. Circuit in Emera Maine v. Federal Energy Regulatory Commission, the FERC issued a Notice of Inquiry regarding its policy for determining return on equity (“ROE”("ROE"). The FERC specifically sought information and stakeholder views to help the FERC explore whether, and if so how, it should modify its policies concerning the determination of ROE to be used in designing jurisdictional rates charged by public utilities. The FERC also expressly sought comment on whether any changes to its policies concerning public utility ROEs should be applied to interstate natural gas and oil pipelines. Initial comments were due in June 2019, and reply comments were due in July 2019. The FERC has not taken any further action with respect to the Notice of Inquiry as of this time, and therefore we cannot predict what effect, if any, such development could have on our cost-of-service rates in the future.
By order issued January 16, 2019, the FERC initiated a review of Panhandle’sPanhandle’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing.  Panhandle filed a cost and revenue study on April 1, 2019. Panhandle filed a NGA Section 4 rate case on August 30, 2019.
Even without action on the 2017 Tax Law NOI or as contemplated in the Final Rule, the FERC or our shippers may challenge the cost of service rates we charge. The FERC’sFERC’s establishment of a just and reasonable rate is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’sFERC’s determination of just and reasonable cost of service rates. Although changes in these two tax related components may decrease, other components in the cost of service rate calculation may increase and result in a newly calculated cost of service rate that is the same as or greater than the prior cost of service rate. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost of service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger Pipeline, LLC, MEP and FEP,


3538
Table of Contents

have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. We do not expect market-based rates, negotiated rates or discounted rates that are not tied to the cost of service rates to be affected by the Revised Policy Statement or any final regulations that may result from the March 15, 2018 proposals. The revenues we receive from natural gas transportation services we provide pursuant to cost of service based rates may decrease in the future as a result of the ultimate outcome of the NOI, the Final Rule, and the Revised Policy Statement, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost of service rates, if any, will depend on a detailed review of all of ETO’sETO’s cost of service components and the outcomes of any challenges to our rates by the FERC or our shippers.
Pipeline Certification
The FERC issued a Notice of Inquiry on April 19, 2018 (“(“Pipeline Certification NOI”NOI”), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in response to the Pipeline Certification NOI were due on or before July 25, 2018. We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.
Interstate Common Carrier Regulation
The FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index, or PPI. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’sFERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 1.23 percent. Many existing pipelines utilize the FERC liquids index to change transportation rates annually every July 1. With respect to liquids and refined products pipelines subject to FERC jurisdiction, the Revised Policy Statement requires the pipeline to reflect the impacts to its cost of service from the Revised Policy Statement and the Tax Act on Page 700 of FERC Form No. 6. This information will be used by the FERC in its next five year review of the liquids pipeline index to generate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and the Tax Act in the determination of indexed rates prospectively, effective July 1, 2021. The FERC’sFERC’s establishment of a just and reasonable rate, including the determination of the appropriate liquids pipeline index, is based on many components, and tax related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’sFERC’s determination of the appropriate pipeline index. Accordingly, depending on the FERC’sFERC’s application of its indexing rate methodology for the next five year term of index rates, the Revised Policy Statement and tax effects related to the Tax Act may impact our revenues associated with any transportation services we may provide pursuant to cost of service based rates in the future, including indexed rates.
Trends and Outlook
Recent crude oil market disruptions involving foreign oil-producing nations and the COVID-19 pandemic may have a negative impact onnegatively impacted our earnings and cash flows from operations.operations and may continue to do so. Reduced demand for natural gas, NGLs, refined products and/or crude oil caused by the COVID-19 pandemic and a continuation of low WTI crude oil prices caused by the actions of foreign oil-producing nations may result in the shut-in of production from U.S. oil and gas wells, which in turn may result in decreased volumes transported on our pipeline systems and decreased overall utilization of our midstream services.
With respect to commodity prices, natural gas prices have remained comparatively low in recent months as associated gas from shale oil resources has provided additional supply to the market. Meanwhile, crude oil prices have seensaw a sharp declines as a result of actions by foreign oil-producing nations and a decrease in global demand as result of the COVID-19 pandemic but have subsequently risen and stabilized. We cannot predict the future impacts, or the duration of such impacts, from the COVID-19 pandemic. Global oil and natural gas demand growth is likely to remain flat or decline in the near term and will likely result in lower U.S. production levels.
The outlook for commodity prices is mixed and could have a varying impact on our business. Reduced demand and increased supply of crude oil has resulted in an increase in worldwide crude oil storage inventories, which is expected to keep crude oil prices suppressed for the foreseeable future. With respect to natural gas markets, a relatively more moderate decrease in demand, coupled with anticipated decreases in gas production associated with wells drilled to produce crude oil, have counterbalanced softness in pricing. The overall outlook for our midstream services will depend, in part, on the timing and extent of recovery in the commodity markets.


3639
Table of Contents

While we anticipate that current and projected commodity prices and the related impact to activity levels in both the upstream and midstream sectors will impact our business, we cannot predict the ultimate magnitude of that impact and expect it to be varied across our operations, depending on the region, customer, type of service, contract term and other factors.
As a result of the current commodity price environment, a small number of counterparties to our commercial contracts have made force majeure claims in an effort to terminate or modify existing agreements with us, and in the future we expect more counterparties to do the same. To the extent our counterparties are successful in those claims, we may not receive the full payments or other benefits of those contracts during the pendency of the force majeure event. While the vast majority of our counterparties are investment grade rated companies, some of our counterparties may be forced to file for bankruptcy protection, in which case our existing contracts with those counterparties may be rejected by the bankruptcy court. In this case, we expect that we would attempt to negotiate replacement contracts with those counterparties and, depending on the availability of alternatives to our services, these contracts may have terms that are less favorable to us than the contracts rejected in bankruptcy court.
Ultimately, the extent to which our business will be impacted by recent market developments depends on the factors described above as well as future developments beyond our control, which are highly uncertain and cannot be predicted. In response to these market events and uncertainties, we have cut our already reduced 2020 growth capital spending budget by $400a total of $600 million and reduced planned operating expenses by $200 million to $250 million; and we are prepared to cut spending further should the need arise.approximately $400 million. While current market volatility makes the near-term unpredictable, we believe that overall the long-term demand for our services will continue given the essential nature of the midstream natural gas, NGLs, refined products and crude oil business, although we cannot predict any possible changes in such demand with reasonable certainty.
We currently have ample liquidity to fund our business and we do not anticipate any liquidity concerns in the immediate future (see “Liquidity“Liquidity and Capital Resources”Resources” below). In addition, while the trading price of ET common units declined significantly during the first quarterhalf of 2020, thereby making equity capital market transactions less attractive in the near term, we continue to have access to the debt capital markets on generally favorable terms. In the event we seek additional equity or debt capital, our blended cost of capital for equity and debt is expected to be modestly higher in the near term; however, we will continue to evaluate growth projects and acquisitions as such opportunities may be identified in the future in light of this higher cost of capital.
Results of Operations
We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership 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, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Inventory adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at last-in, first-out (“LIFO”). These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.
Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.  The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.
Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section titled “Segment“Segment Operating Results.”” Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’sPartnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures.
As discussed in Note 1 of the Partnership’sPartnership’s consolidated financial statements included in “Item“Item 1. Financial Statements,”” during the first quarter of 2020, the Partnership elected to change its inventory accounting policy related to certain barrels of crude oil that were previously accountingaccounted for as inventory. These changes have been applied retrospectively to all prior periods, and the prior period amounts reflected below have been adjusted from those amounts previously reported.


3740
Table of Contents

Consolidated Results
Three Months Ended
March 31,
 
 
Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2020
 
2019*
 
Change
2020 2019* Change 2020 2019* Change
Segment Adjusted EBITDA:
 
 
 
 
 
          

Intrastate transportation and storage
$
240

 
$
252

 
$
(12
)
$187
 $290
 $(103) $427
 $542
 $(115)
Interstate transportation and storage
404

 
456

 
(52
)
403
 460
 (57) 807
 916
 (109)
Midstream
383

 
382

 
1

367
 412
 (45) 750
 794
 (44)
NGL and refined products transportation and services
663

 
612

 
51

674
 644
 30
 1,337
 1,256
 81
Crude oil transportation and services
591

 
744

 
(153
)
519
 752
 (233) 1,110
 1,496
 (386)
Investment in Sunoco LP
209

 
153

 
56

182
 152
 30
 391
 305
 86
Investment in USAC
106

 
101

 
5

105
 105
 —
 211
 206
 5
All other
19

 
33

 
(14
)
4
 13
 (9) 46
 46
 —
Adjusted EBITDA (consolidated)
2,615

 
2,733

 
(118
)
2,441
 2,828
 (387) 5,079
 5,561
 (482)
Depreciation, depletion and amortization
(851
)
 
(771
)
 
(80
)
(934) (781) (153) (1,799) (1,552) (247)
Interest expense, net of interest capitalized
(595
)
 
(527
)
 
(68
)
(578) (578) —
 (1,178) (1,105) (73)
Impairment losses
(1,325
)
 
(50
)
 
(1,275
)
(4) —
 (4) (1,329) (50) (1,279)
Losses on interest rate derivatives
(329
)
 
(74
)
 
(255
)
(3) (122) 119
 (332) (196) (136)
Non-cash compensation expense
(18
)
 
(29
)
 
11

(41) (29) (12) (63) (58) (5)
Unrealized gains on commodity risk management activities
51

 
49

 
2

Unrealized gains (losses) on commodity risk management activities(48) (23) (25) 3
 26
 (23)
Losses on extinguishments of debt
(59
)
 
(2
)
 
(57
)
—
 —
 —
 (59) (2) (57)
Inventory valuation adjustments
(227
)
 
93

 
(320
)
Inventory valuation adjustments (Sunoco LP)90
 4
 86
 (137) 97
 (234)
Adjusted EBITDA related to unconsolidated affiliates
(154
)
 
(146
)
 
(8
)
(157) (163) 6
 (311) (309) (2)
Equity in earnings (losses) of unconsolidated affiliates
(7
)
 
65

 
(72
)
Equity in earnings of unconsolidated affiliates85
 77
 8
 78
 142
 (64)
Other, net
45

 
4

 
41

(34) 104
 (138) (20) 108
 (128)
Income (loss) before income tax expense
(854
)
 
1,345


(2,199
)
817
 1,317

(500)
(68) 2,662
 (2,730)
Income tax expense
(53
)
 
(126
)
 
73

(98) (35) (63) (127) (161) 34
Net income (loss)
$
(907
)

$
1,219

 
$
(2,126
)
$719

$1,282
 $(563) $(195) $2,501
 $(2,696)
*As adjusted.
Adjusted EBITDA (consolidated). For the three and six months ended March 31,June 30, 2020 compared to the same period last year, Adjusted EBITDA decreased $118 million14% and 9%, or 4%. The decrease wasrespectively, primarily due to a net impactthe impacts of $240 million from crude oil, NGLlower volumes and refined products inventory valuation adjustments ($213 millionmarket prices among several of negative adjustments in the current period compared to $27 million of favorable adjustments in the prior period). This decrease wasour core operating segments; these decreases were partially offset by a net increaseincreases of approximately $113 $150 million and $290 million, respectively, in Adjusted EBITDA from recent acquisitions and assets placed in service.
Additional discussion of these and other factors affecting Adjusted EBITDA is included in the analysis of Segment Adjusted EBITDA in the “Segment“Segment Operating Results”Results” section below.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three and six months endedMarch 31, June 30, 2020compared to the same periodperiods last year due to the acquisition of SemGroup on December 5, 2019, as well as incremental depreciation related to assets recently placed in service.


41
Table of Contents

Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased for the threesix months endedMarch 31, June 30, 2020 compared to the same periodperiods last year primarily due to the following:
•
•
an increase of $62$67 millionrecognized by the Partnership primarily attributable to the higher consolidated debt balancebalances following the March 2019 ET-ETO notes exchange and the December 2019 SemGroup acquisition, and related debt refinancing, the impact of which was partially offset by lower borrowing costs fromon both recently refinanced debt and floating rate debt;debt and higher capitalized interest;


38
Table of Contents

•
•
an increase of $4$3 millionfor USAC for the six months ended June 30, 2020 compared to the six months ended June 30, 2019 was primarily attributable to a full quartersix months of interest expense incurred in the current period on its senior notes 2027 issued in March 2019, which were used to reduce borrowings under itsthe credit agreement, partially offset by the reduced borrowings and lower weighted average interest rates under the credit agreement; and
•
an increase of $3 million for Sunoco LP for the six months ended June 30, 2020 compared to the same period last year primarily related to an increase in Sunoco LP’s total long-term debt.
an increase of $2 million for Sunoco LP primarily related to an increase in Sunoco LP’s total long-term debt.
Impairment Losses. During the three months ended March 31, 2020, the Partnership performed an interim impairment test on certain reporting units within midstream, interstate, crude, NGL and all other operations. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of $483 million related to our Arklatex and South Texas operations within the midstream segment, a goodwill impairment of $183 million related to our Lake Charles LNG regasification operations with the interstate transportation and storage segment, and a goodwill impairment of $40 millionrelated to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million, during the three months ended March 31, 2020, which is included in the Partnership'sPartnership’s consolidated results of operations. During the three months ended March 31, 2019, USAC recorded a $3 million impairment of compression equipment as a result of its evaluations of the future deployment of USAC’sUSAC’s idle fleet under then-current market conditions. USAC recorded a $4 million impairment of compression equipment during the three months ended June 30, 2020 as a result of its evaluations of the future deployment of its idle fleet under current market conditions.
Gains (Losses)Losses on Interest Rate Derivatives. Losses on interest rate derivatives during the three and six months endedMarch 31, June 30, 2020resulted from decreases in forward interest rates, which caused our forward-starting swaps to decrease in value.
Unrealized Gains (Losses) on Commodity Risk Management Activities. See additional information on the unrealized gains (losses) on commodity risk management activities included in “Segment“Segment Operating Results”Results” below.
Losses on Extinguishments of Debt. During the three and six months ended March 31,June 30, 2020, amounts were related to ETO senior notes redemption in January 2020.
Inventory Valuation Adjustments. Inventory valuation adjustments were recorded for the inventory associated with Sunoco LP due to changes in fuel prices between periods.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental“Supplemental Information on Unconsolidated Affiliates”Affiliates” and “Segment“Segment Operating Results”Results” below.
Other, net. Other, net primarily includes the interest income related to the ET-ETO Promissory Notes, as well as amortization of regulatory assets and other income and expense amounts.
Income Tax (Expense) BenefitExpense. For thethree months endedMarch 31, June 30, 2020 compared to the same period in the prior year, income tax expense increased due to higher earnings at our corporate subsidiaries in the current period. For the six months ended June 30, 2020 compared to the same period in the prior year, income tax expense decreased due to the recognition of a taxable gain on the sale of assets at our corporate subsidiaries in the prior period.


3942
Table of Contents

Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
Three Months Ended
March 31,
 
 
Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2020
 
2019
 
Change
2020 2019 Change 2020 2019 Change
Equity in earnings (losses) of unconsolidated affiliates:
 
 
 
 
 
           
Citrus
$
35

 
$
32

 
$
3

$42
 $39
 $3
 $77
 $71
 $6
FEP
(70
)
 
14

 
(84
)
18
 14
 4
 (52) 28
 (80)
MEP
—

 
7

 
(7
)
(2) 7
 (9) (2) 14
 (16)
White Cliffs
8

 
—

 
8

9
 —
 9
 17
 —
 17
Other
20

 
12

 
8

18
 17
 1
 38
 29
 9
Total equity in earnings (losses) of unconsolidated affiliates
$
(7
)
 
$
65

 
$
(72
)
$85
 $77
 $8
 $78
 $142
 $(64)
 
 
 
 
 
           
Adjusted EBITDA related to unconsolidated affiliates(1):
 
 
 
 
 
           
Citrus
$
79

 
$
81

 
$
(2
)
$89
 $87
 $2
 $168
 $168
 $—
FEP
19

 
19

 
—

19
 18
 1
 38
 37
 1
MEP
8

 
19

 
(11
)
7
 20
 (13) 15
 39
 (24)
White Cliffs
14

 
—

 
14

13
 —
 13
 27
 —
 27
Other
34

 
27

 
7

29
 38
 (9) 63
 65
 (2)
Total Adjusted EBITDA related to unconsolidated affiliates
$
154

 
$
146

 
$
8

$157
 $163
 $(6) $311
 $309
 $2
 
 
 
 
 
           
Distributions received from unconsolidated affiliates:
 
 
 
 
 
           
Citrus
$
49

 
$
35

 
$
14

$58
 $39
 $19
 $107
 $74
 $33
FEP
18

 
17

 
1

17
 16
 1
 35
 33
 2
MEP
11

 
11

 
—

7
 15
 (8) 18
 26
 (8)
White Cliffs
13

 
—

 
13

10
 —
 10
 23
 —
 23
Other
19

 
16

 
3

20
 42
 (22) 39
 58
 (19)
Total distributions received from unconsolidated affiliates
$
110

 
$
79

 
$
31

$112
 $112
 $—
 $222
 $191
 $31
(1) 
These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.  
Segment Operating Results
We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.
The tables below identify the components of Segment Adjusted EBITDA, which is calculated as follows:
•
•
Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
•
•
Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.


43
Table of Contents

•
•
Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.


40
Table of Contents

•
•
Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. 
In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.
In addition, for certain segments, the sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.
Intrastate Transportation and Storage
Three Months Ended
March 31,
 
 
Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2020
 
2019
 
Change
2020 2019 Change 2020 2019 Change
Natural gas transported (BBtu/d)
13,135

 
11,982

 
1,153

12,921
 12,115
 806
 13,028
 12,049
 979
Withdrawals from storage natural gas inventory (BBtu)
6,975

 
—

 
6,975

(1,910) —
 (1,910) 5,065
 —
 5,065
Revenues
$
593

 
$
856

 
$
(263
)
$516
 $765
 $(249) $1,109
 $1,621
 $(512)
Cost of products sold
303

 
572

 
(269
)
248
 400
 (152) 551
 972
 (421)
Segment margin
290

 
284

 
6

268
 365
 (97) 558
 649
 (91)
Unrealized (gains) losses on commodity risk management activities
(6
)
 
10

 
(16
)
Unrealized gains on commodity risk management activities(33) (26) (7) (39) (16) (23)
Operating expenses, excluding non-cash compensation expense
(41
)
 
(42
)
 
1

(48) (47) (1) (89) (89) —
Selling, general and administrative expenses, excluding non-cash compensation expense
(9
)
 
(6
)
 
(3
)
(6) (7) 1
 (15) (13) (2)
Adjusted EBITDA related to unconsolidated affiliates
6

 
6

 
—

6
 5
 1
 12
 11
 1
Segment Adjusted EBITDA
$
240

 
$
252

 
$
(12
)
$187
 $290
 $(103) $427
 $542
 $(115)
Volumes. For the three and six months endedMarch 31, June 30, 2020 compared to the same periodperiods last year, transported volumes increased primarily due to increased utilization of our Texas pipelines.


44
Table of Contents

Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:
 
Three Months Ended
March 31,
 
 
 
2020
 
2019
 
Change
Transportation fees
$
161

 
$
154

 
$
7

Natural gas sales and other (excluding unrealized gains and losses)
88

 
120

 
(32
)
Retained fuel revenues (excluding unrealized gains and losses)
9

 
11

 
(2
)
Storage margin (excluding unrealized gains and losses)
26

 
9

 
17

Unrealized gains (losses) on commodity risk management activities
6

 
(10
)
 
16

Total segment margin
$
290

 
$
284

 
$
6



41
Table of Contents

 Three Months Ended
June 30,		   Six Months Ended
June 30,		  
 2020 2019 Change 2020 2019 Change
Transportation fees$148
 $148
 $—
 $309
 $302
 $7
Natural gas sales and other (excluding unrealized gains and losses)68
 173
 (105) 156
 293
 (137)
Retained fuel revenues (excluding unrealized gains and losses)10
 12
 (2) 19
 23
 (4)
Storage margin (excluding unrealized gains and losses)9
 6
 3
 35
 15
 20
Unrealized gains on commodity risk management activities33
 26
 7
 39
 16
 23
Total segment margin$268
 $365
 $(97) $558
 $649
 $(91)
Segment Adjusted EBITDA. For the three months endedMarch 31, June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation segment decreased due to the net effectsimpacts of the following:
•
•
a decrease of $32$105 million in realized natural gas sales and other primarily due to lower realized gains from pipeline optimization activity; and
•
an increase of $1 million in operating expenses primarily due to higher maintenance project costs and higher cost of fuel consumption; partially offset by
an increase of $3 million in realized storage margin primarily due to higher storage optimization and fees.
Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation segment decreased due to the net impacts of the following:
•
a decrease of $137 million in realized natural gas sales and other primarily due to lower realized gains from pipeline optimization activity;
•
•
a decrease of $4 million in retention revenueretained fuel revenues primarily due to lower natural gas prices; and
•
•
an increase of$3 $2 millionin selling, general and administrative expenses primarily due to higher allocated corporate costs; partially offset by
•
•
an increase of$17 $20 millionin realized storage margin primarily due to higher storage optimization;
•
•
an increase of$7 $7 million in transportation fees primarily due to volume ramp-ups on the Red Bluff Express pipeline and new contracts; and
•
an increase of $1 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to higher fee revenue on the Trans-Pecos and Comanche Trail pipelines.


45

a decrease of $1 million in operating expenses primarily related to lower cost of fuel consumption resulting from lower natural gas prices.
Interstate Transportation and Storage
Three Months Ended
March 31,
 
 
Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2020
 
2019
 
Change
2020 2019 Change 2020 2019 Change
Natural gas transported (BBtu/d)
10,630

 
11,532

 
(902
)
10,152
 10,825
 (673) 10,440
 11,177
 (737)
Natural gas sold (BBtu/d)
15

 
19

 
(4
)
17
 17
 —
 16
 18
 (2)
Revenues
$
464

 
$
498

 
$
(34
)
$445
 $493
 $(48) $909
 $991
 $(82)
Operating expenses, excluding non-cash compensation, amortization and accretion expenses
(143
)
 
(146
)
 
3

(139) (138) (1) (282) (284) 2
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
(21
)
 
(14
)
 
(7
)
(16) (18) 2
 (37) (32) (5)
Adjusted EBITDA related to unconsolidated affiliates
106

 
119

 
(13
)
115
 125
 (10) 221
 244
 (23)
Other
(2
)
 
(1
)
 
(1
)
(2) (2) —
 (4) (3) (1)
Segment Adjusted EBITDA
$
404

 
$
456

 
$
(52
)
$403
 $460
 $(57) $807
 $916
 $(109)
Volumes. For the three and six months ended March 31,June 30, 2020 compared to the same periods last year, transported volumes decreased 0.7 Bcf/d primarily due to shut-ins of crude production resulting in lower utilization of contracted capacity on our Panhandleassociated gas and Trunkline pipelines.a decrease in demand for LNG export.
Segment Adjusted EBITDA. For the three months endedMarch 31, June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following:
•
•
a decrease of $34$43 million in revenuesreservation fees primarily due to a decrease of $18 million from additional revenue recognized in 2019 associated with a shipper bankruptcy, a decrease of $16 million decrease resulting from a contractual rate adjustmentlower rates on commitments at our Lake Charles LNG facilityeffective January 2020 and a $20decrease of $12 million decrease primarily due to less capacity sold on our Panhandle and Trunkline systems as well as lower rates and volumes as a resulton the sale of less favorable market conditionsuncommitted capacity on our Rover Panhandle,pipeline. These decreases were partially offset by increased margin from our Transwestern and Trunkline pipelines;system due to increased demand in firm transportation;
•
•
an increasea decrease of$7 $4 millionin selling, general and administrative expenses primarilyinterruptible transportation due to higher overhead costs;lower rates and lower short-term customer demand on our Sea Robin and Transwestern systems; and
•
•
a decrease of$13 $10 millionin Adjusted EBITDA related to unconsolidated affiliates primarily due to an $11lower earnings of $12 millionnet decrease from our Midcontinent Express Pipeline joint venture as a result of less capacity sold and lower rates received following the expiration of certain contracts, andpartially offset by a $2 million increase from Citrus primarily due to higher margins and lower operating expenses.net decrease from our Citrus joint venture resulting from higher allocated expenses; partially offset by
Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following:
•
•
a decrease of$3 $73 millionin operating expensesreservation fees primarily due to a decrease of $18 million from additional revenue recognized in 2019 associated with a shipper bankruptcy, a decrease of $30 million due to less capacity sold at lower ad valorem taxes.rates on our Panhandle and Trunkline system as well as lower rates on the sale of uncommitted capacity on our Rover pipeline, and a decrease of $32 million due to a contractual rate adjustment on commitments at our Lake Charles LNG facility. These decreases were partially offset by increased revenues from our Transwestern system due to increased demand in firm transportation;
a decrease of $8 million in operational gas sales, interruptible transportation, parking and storage revenue due to unfavorable market conditions;
an increase of $5 million in selling, general and administrative expenses primarily due to higher allocated overhead costs and an increase in reserves for insurance claims; and
a decrease of $23 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower earnings from our Midcontinent Express Pipeline joint venture as a result of less capacity sold and lower rates received following the expiration of certain contracts; partially offset by


4246
Table of Contents

a decrease of $2 million in operating expenses primarily due to lower employee costs resulting from cost-cutting initiatives of $10 million and an $8 million decrease in ad valorem taxes, partially offset by bad debt expense of $10 million and a $5 million change in lower of cost or market adjustments.
Midstream
Three Months Ended
March 31,
 
 
Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2020
 
2019
 
Change
2020 2019 Change 2020 2019 Change
Gathered volumes (BBtu/d)
13,346

 
12,718

 
628

12,964
 13,148
 (184) 13,155
 12,934
 221
NGLs produced (MBbls/d)
610

 
563

 
47

602
 565
 37
 606
 564
 42
Equity NGLs (MBbls/d)
36

 
35

 
1

37
 30
 7
 37
 33
 4
Revenues
$
1,170

 
$
1,718

 
$
(548
)
$1,018
 $1,198
 $(180) $2,188
 $2,916
 $(728)
Cost of products sold
575

 
1,141

 
(566
)
473
 584
 (111) 1,048
 1,725
 (677)
Segment margin
595

 
577

 
18

545
 614
 (69) 1,140
 1,191
 (51)
Operating expenses, excluding non-cash compensation expense
(193
)
 
(183
)
 
(10
)
(166) (189) 23
 (359) (372) 13
Selling, general and administrative expenses, excluding non-cash compensation expense
(26
)
 
(19
)
 
(7
)
(20) (23) 3
 (46) (42) (4)
Adjusted EBITDA related to unconsolidated affiliates
7

 
6

 
1

7
 9
 (2) 14
 15
 (1)
Other
—

 
1

 
(1
)
1
 1
 —
 1
 2
 (1)
Segment Adjusted EBITDA
$
383

 
$
382

 
$
1

$367
 $412
 $(45) $750
 $794
 $(44)
Volumes. Gathered volumes increaseddecreased during thethree months endedMarch 31, June 30, 2020 compared to the same period last year primarily due to increasesdecreases in the South Texas and North Texas regions, partially offset by the impact of the SemGroup acquisition in the Mid-Continent/Panhandle Ark-La-Tex, Permian, South Texas and Northeast regions.region. NGL production increased due to the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and increased ethane recovery in the Permian, South Texas and North Texas regions.
Gathered volumes increased during the six months ended June 30, 2020 compared to the same period last year primarily due to the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and volume increases in the Permian and Mid-Continent/PanhandleNortheast region, partially offset by ethane rejectiondecreases in the South Texas region. NGL production increased due to the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and increased ethane recovery in the Permian, South Texas and North Texas regions.
Segment Margin. The table below presents the components of our midstream segment margin. For the prior period included in the table below, the amounts previously reported for fee-based and non-fee-based margin have been adjusted to reflect reclassification of certain contractual minimum fees in order to conform to the current period classification:
Three Months Ended
March 31,
 
 
Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2020
 
2019
 
Change
2020 2019 Change 2020 2019 Change
Gathering and processing fee-based revenues
$
530

 
$
502

 
$
28

$503
 $530
 $(27) $1,033
 $1,034
 $(1)
Non-fee-based contracts and processing
65

 
75

 
(10
)
42
 84
 (42) 107
 157
 (50)
Total segment margin
$
595

 
$
577

 
$
18

$545
 $614
 $(69) $1,140
 $1,191
 $(51)
Segment Adjusted EBITDA. For the three months endedMarch 31, June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increaseddecreased due to the net impacts of the following:
•
an increase of$28 millionin fee-based margin due to volume growth in the Permian, Mid-Continent/Panhandle and Northeast regions; and
•
an increase of $13 million in non fee-based margin due to increased throughput volume in the Permian region; partially offset by
•
•
a decrease of$22$39 millionin non fee-based margin due to lower NGL prices of $17 million and lower natural gas prices of $5 million;prices;
•
•
an increasea decrease of$10 $3 millionin operating expensesnon-fee based margin due to an increase of $6 milliondecreased throughput volume in maintenance project coststhe South Texas region; and $4 million in employee costs; and
•
•
an increasea decrease of $27 million in fee-based margin due to volume declines in the South Texas and North Texas regions; partially offset by


47
Table of Contents

a decrease of $23 million in operating expenses due to decreases of $11 million in outside services, $8 million in employee costs and $3 million in materials; and
•
a decrease of $73 million in selling, general and administrative expenses due to an increasea decrease in allocated overhead costs allocated to the segment.costs.


Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:
43
Tablea decrease of Contents$61 million in non-fee-based margin due to lower NGL prices of $56 million and lower gas prices of $5 million;

•
an increase of $4 million in selling, general and administrative expenses due to an increase of $3 million in capitalized overhead costs and an increase of $1 million in insurance; partially offset by
•
an increase of $11 million in non-fee-based margin due to increased throughput volume in the Mid-Continent/Panhandle region as a result of the SemGroup acquisition; and
•
a decrease of $13 million in operating expenses due to decreases of $11 million in outside services, $4 million in employee costs and $3 million in materials, partially offset by an increase of $7 million in maintenance project costs.
NGL and Refined Products Transportation and Services
Three Months Ended
March 31,
 
 
Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2020
 
2019
 
Change
2020 2019 Change 2020 2019 Change
NGL transportation volumes (MBbls/d)
1,398

 
1,178

 
220

1,401
 1,305
 96
 1,400
 1,237
 163
Refined products transportation volumes (MBbls/d)
533

 
617

 
(84
)
377
 628
 (251) 460
 623
 (163)
NGL and refined products terminal volumes (MBbls/d)
847

 
777

 
70

748
 885
 (137) 798
 831
 (33)
NGL fractionation volumes (MBbls/d)
804

 
678

 
126

836
 701
 135
 820
 690
 130
Revenues
$
2,715

 
$
3,031

 
$
(316
)
$2,119
 $2,612
 $(493) $4,834
 $5,643
 $(809)
Cost of products sold
1,836

 
2,326

 
(490
)
1,368
 1,848
 (480) 3,204
 4,174
 (970)
Segment margin
879

 
705

 
174

751
 764
 (13) 1,630
 1,469
 161
Unrealized (gains) losses on commodity risk management activities
(55
)
 
57

 
(112
)
Unrealized losses on commodity risk management activities78
 39
 39
 23
 96
 (73)
Operating expenses, excluding non-cash compensation expense
(159
)
 
(149
)
 
(10
)
(154) (155) 1
 (313) (304) (9)
Selling, general and administrative expenses, excluding non-cash compensation expense
(25
)
 
(19
)
 
(6
)
(19) (26) 7
 (44) (45) 1
Adjusted EBITDA related to unconsolidated affiliates
23

 
18

 
5

18
 21
 (3) 41
 39
 2
Other—
 1
 (1) —
 1
 (1)
Segment Adjusted EBITDA
$
663

 
$
612

 
$
51

$674
 $644
 $30
 $1,337
 $1,256
 $81
Volumes. For the three and six months endedMarch 31, June 30, 2020 compared to the same periodperiods last year, NGL transportation volumes increased due to higher throughput volumes on our Mariner East pipeline system. In addition, throughput barrels on our Texas NGL pipeline system increased due to higher receipt of liquids production from both wholly-owned and third-party gas plants primarily in the Permian and North Texas regions. In addition, NGL transportation volumes increased on our Mariner East pipeline system.
Refined products transportation volumes decreased for the three and six months endedMarch 31, June 30, 2020 compared to the same periodperiods last year due to the closure of a third-party refinery during the third quarter of 2019, and various turnarounds performed at third party refineries, which negatively impacted supply to our refined products transportation system.system, and less domestic demand for jet fuel and other refined products. These decreases in volumes wereare partially offset by the initiation of service on our JC Nolan diesel fuel pipeline in the third quarter of 2019.
NGL and refined products terminal volumes increaseddecreased for the three and six months endedMarch 31, June 30, 2020 compared to the same periodperiods last year primarily due to higher volumes from our Mariner East system, the initiation of service on our JC Nolan diesel fuel pipeline in the third quarter of 2019, additional cargoes shipped out of our Nederland terminal, and the initiation of natural gasoline exports in July of 2019. These increases were partially offset by the closure of a third-party refinery during the third quarter of 2019, and various turnarounds performed at third-party refineries. Forless domestic demand for jet fuel and other refined products. These decreases were partially offset by higher volumes from our Mariner East system,


48
Table of Contents

and the three months ended March 31, 2019, NGLinitiation of service on our JC Nolan diesel fuel pipeline and refined products terminal volumes have been adjusted from amounts previously reported to be consistent withnatural gasoline export project, both of which commenced service in the current period presentation; specifically, those volumes were adjusted to exclude terminal volumes for which fees are attributable to storage capacity rather than terminal throughput.third quarter of 2019.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased 19%20% for both the three and six months endedMarch 31, June 30, 2020 compared to the same periodperiods last year primarily due to the commissioning of our sixth and seventh fractionators in February 2019 and February 2020, respectively.


44
Table of Contents

Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:
Three Months Ended
March 31,
 
 
Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2020
 
2019
 
Change
2020 2019 Change 2020 2019 Change
Transportation margin
$
476

 
$
363

 
$
113

$449
 $422
 $27
 $925
 $785
 $140
Fractionators and refinery services margin
179

 
168

 
11

173
 154
 19
 352
 320
 32
Terminal services margin
151

 
135

 
16

129
 166
 (37) 280
 303
 (23)
Storage margin
63

 
56

 
7

55
 53
 2
 118
 109
 9
Marketing margin
(45
)
 
40

 
(85
)
23
 8
 15
 (22) 48
 (70)
Unrealized gains (losses) on commodity risk management activities
55

 
(57
)
 
112

Unrealized losses on commodity risk management activities(78) (39) (39) (23) (96) 73
Total segment margin
$
879

 
$
705

 
$
174

$751
 $764
 $(13) $1,630
 $1,469
 $161
Segment Adjusted EBITDA. For the three months endedMarch 31, June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:
•
•
an increase of$113 $27 millionin transportation margin primarily due to a $74 $28 million increase from higher throughput volumes on our Mariner East pipeline system, a $35an $11 million increase from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $7 $6 million increase due to the initiation of service on our JC Nolan diesel fuel pipeline in the third quarter of 2019, and a $5 $4 million increase due to higher throughput volumes from the BarnettSoutheast Texas region. These increases were partially offset by a $6an $8 million decrease due to a reclassification between our transportation and fractionators margins, a $7 million decrease due to less domestic demand for jet fuel and other refined products, a $5 million decrease resulting from the closure of a third-party refinery during the third quarter of 2019;2019, and a $2 million decrease due to lower third-party volumes on our Mariner West pipeline;
•
•
an increase of$16 $15 million in terminal servicesmarketing margin primarily due to an $18a $50 million increase due to higher optimization gains from higher throughput onthe sale of NGL component products at our Mariner East systemMont Belvieu facility and a $10 million increase due to write-downs of NGL inventory in the second quarter of 2019. These increases were partially offset by a $2 million decreaselower gains from our butane blending business during the second quarter of 2020 due to the closure of a third-party refinery;unfavorable market conditions; and
•
•
an increase of$11 $19 million in fractionators and refinery services margin primarily due to a $15 million increase resulting from the commissioning of our seventh fractionator in February 2020 and higher NGL volumes from the Permian and Barnett regions feeding our Mont Belvieu fractionation facility, and an increase of $8 million due to a reclassification between our transportation and fractionators margins. These increases were partially offset by a $4 million decrease due to the expiration of a third-party blending contract during the second quarter of 2020; partially offset by
•
a decrease of $37 million in terminal services margin primarily due to a $25 million decrease resulting from the expiration of a third party contract at our Nederland export facility in the second quarter of 2020, a $9 million decrease due to lower third-party and intercompany volumes feeding our Marcus Hook Industrial Complex, a $6 million decrease due to less domestic demand for jet fuel and other refined products, and a $4 million decrease due to the closure of a third-party refinery. These decreases were partially offset by a $6 million increase due to higher throughput on our Mariner East system.


49
Table of Contents

Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:
•
an increase of $140 million in transportation margin primarily due to a $103 million increase from higher throughput volumes on our Mariner East pipeline system, a $46 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $14 million increase due to the initiation of service on our JC Nolan diesel fuel pipeline in the third quarter of 2019, a $9 million increase due to higher throughput volumes from the Barnett region, and a $6 million increase due to higher throughput from the Southeast Texas region. These increases were partially offset by an $11 million decrease resulting from the closure of a third-party refinery during the third quarter of 2019, a $10 million decrease due to less domestic demand for jet fuel and other refined products, an $8 million decrease due to a reclassification between our transportation and fractionators margins, a $5 million decrease due to lower volumes from the Eagle Ford region, and a $3 million decrease due to lower third-party volumes on our Mariner West pipeline;
•
an increase of $32 million in fractionators and refinery services margin primarily due to a $25 million increase resulting from the commissioning of our sixth and seventh fractionators in February 2019 and February 2020, respectively, and higher NGL volumes from the Permian regionand Barnett regions feeding our Mont Belvieu fractionation facility;facility, an $8 million increase due to a reclassification between our transportation and fractionators margins, and a $3 million increase in truck and rail volumes feeding our refinery services facility. These increases were partially offset by a $6 million decrease due to the expiration of a third-party blending contract during the second quarter of 2020; and
•
•
an increase of$7 $9 millionin storage margin primarily due to a$3 $6 millionincrease in fees generated from exported volumes and a$3 $3 millionincrease from higher throughput; partially offset by
•
•
a decrease of$85 $70 millionin marketing margin primarily due to a $50$54 million decrease due to lower gains from inventory valuation adjustmentsour butane and gasoline blending business due to unfavorable market conditions, a$34 $35 milliondecrease from capacity lease fees incurred by our marketing affiliate on our Mariner East pipeline system;system and a $12 million decrease due to fewer export and rack sales. These decreases were partially offset by higher optimization gains from the sale of NGL component products at our Mont Belvieu facility;
•
•
an increasea decrease of$10 $23 millionin operating expensesterminal services margin primarily due to increases totaling$16a $25 million decrease resulting from the expiration of a third-party contract at our Nederland export facility in the second quarter of 2020, a $16 million decrease due to lower third-party and intercompany volumes feeding our Marcus Hook Industrial Complex, a $10 million decrease due to a closure of a third-party refinery, and an $8 million decrease due to less domestic demand for costs associated with operating additional assets as well as an increase in throughput volumes,jet fuel and other refined products. These decreases were partially offset by a$6 $33 milliondecrease increase due to higher throughput on our Mariner East system and a $3 million increase resulting from initiation of service of our natural gasoline export in power costs;the third quarter of 2019; and
•
an increase of$6 million in selling, general and administrative expenses primarily due to a$6 millionincrease in overhead costs allocated to the segment.
an increase of $9 million in operating expenses primarily due to increases totaling $15 million for costs associated with operating additional assets as well as an increase in throughput volumes, partially offset by a $5 million reduction to lower power costs.


4550
Table of Contents

Crude Oil Transportation and Services
Three Months Ended
March 31,
 
 
Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2020
 
2019
 
Change
2020 2019 Change 2020 2019 Change
Crude transportation volumes (MBbls/d)
4,454

 
4,048

 
406

3,590
 4,266
 (676) 4,021
 4,158
 (137)
Crude terminals volumes (MBbls/d)
2,996

 
2,560

 
436

2,716
 2,846
 (130) 2,851
 2,704
 147
Revenues
$
4,213

 
$
4,186

 
$
27

$1,839
 $5,046
 $(3,207) $6,052
 $9,232
 $(3,180)
Cost of products sold
3,458

 
3,162

 
296

1,175
 4,136
 (2,961) 4,633
 7,298
 (2,665)
Segment margin
755

 
1,024

 
(269
)
664
 910
 (246) 1,419
 1,934
 (515)
Unrealized (gains) losses on commodity risk management activities
10

 
(109
)
 
119

—
 11
 (11) 10
 (98) 108
Operating expenses, excluding non-cash compensation expense
(158
)
 
(150
)
 
(8
)
(131) (150) 19
 (289) (300) 11
Selling, general and administrative expenses, excluding non-cash compensation expense
(28
)
 
(20
)
 
(8
)
(26) (20) (6) (54) (40) (14)
Adjusted EBITDA related to unconsolidated affiliates
12

 
(2
)
 
14

11
 1
 10
 23
 (1) 24
Other
—

 
1

 
(1
)
1
 —
 1
 1
 1
 —
Segment Adjusted EBITDA
$
591

 
$
744

 
$
(153
)
$519
 $752
 $(233) $1,110
 $1,496
 $(386)
Volumes. For the three months ended March 31,June 30, 2020 compared to the same periodsperiod last year, crude transportation and terminal volumes benefited from an increase in barrels throughwere lower due to decreased demand on our existing Texas pipelines,pipeline system and our Bakken pipeline, the initiation of service on phase 2 of our Bayou Bridge pipelinedriven by lower production in the second quarter of 2019,these regions as well as the acquisition of pipelinelower refinery utilization, partly offset by contributions from assets during the fourth quarter ofacquired in 2019.
For the threesix months ended March 31, 2019, certain volumes have been reclassified fromJune 30, 2020 compared to the same period last year, crude transportation volumes were lower due to crude terminaldecreased demand on our Texas pipeline system and our Bakken pipeline, driven by lower production in these regions and lower refinery utilization. Terminal volumes were higher due to be consistent with the current period presentation.contributions from assets acquired in 2019.
Segment Adjusted EBITDA. For the three months endedMarch 31, June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreased due to the net impacts of the following:
•
•
a decrease of$150 $257 millionin segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a$206 $62 milliondecrease (excluding a net change of $119 $11 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business that was primarilydue to well shut-ins resulting in unfulfilled producer supply commitments, as well as unfavorable pricing conditions impacting our Permian to Gulf Coast and Bakken to Gulf Coast trading operations, a $123 million decrease from inventory valuation adjustments (a loss of $154 million for the current period compared to a gain of $36 million for the prior period) and a $58 million decrease on our Texas crude pipeline system due to lower utilization due in part to well shut-ins, as well as lower average tariff rates realized, partially offset by a $73 $117 million increase in margin from terminal operations primarilydecrease due to assets acquired in 2019, a $20 million increase due to higherlower volumes on our Bakken Pipeline resulting from well shut-ins, a $10 million decrease in marine throughput at our crude terminals, and an $18a $7 million increasedecrease due to higherlower volumes on our Bayou Bridge Pipeline;Pipeline, partially offset by an increase of $74 million related to assets acquired in 2019; and
an increase of $6 million in selling, general and administrative expenses primarily due to a $3 million increase in legal expenses, and a $2 million increase in insurance expenses, partially offset by a $1 million decrease in allocated overhead costs; offset by
•
a decrease of $19 million in operating expenses primarily due to lower volume-driven pipeline expenses, partially offset by increased costs related to assets acquired in 2019; and
•
an increase of$8 millionin operating expenses primarily due to costs related to assets acquired in 2019, partly offset by lower crude trucking expenses; and
•
an increase of$8 millionin selling, general and administrative expenses primarily due to a $3 million increase in allocated overhead, a $4 million increase in costs related to assets acquired in 2019, and a $1 million increase in legal expenses; partially offset by
•
•
an increase of $14$10 million in Adjusted EBITDA related to unconsolidated affiliates due to assets acquired in 2019 and improved jet fuels sales by our joint ventures.2019.
Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreased due to the net impacts of the following:
a decrease of $407 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $268 million decrease (excluding a net change of $108 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business due primarily to unfavorable pricing conditions, as well as unfulfilled producer supply commitments due to well shut-ins, impacting our Permian to Gulf Coast


4651
Table of Contents

and Bakken to Gulf Coast trading operations, a $194 million decrease from our Texas crude pipeline system due to lower utilization due in part to well shut-ins, as well as lower average tariff rates realized, a $97 million decrease due to lower volumes on our Bakken Pipeline resulting from well shut-ins, and an $8 million decrease in marine throughput at our crude terminals, offset by a $162 million increase related to assets acquired in 2019 and an $11 million increase due to higher volumes on our Bayou Bridge Pipeline; and
•
an increase of $14 million in selling, general and administrative expenses primarily due to a $4 million increase in legal expenses, a $4 million increase related to assets acquired in 2019, a $2 million increase in insurance expenses, and a $2 million increase in allocated overhead costs; partially offset by
•
a decrease of $11 million in operating expenses primarily due to lower volume-driven pipeline expenses, partially offset by increased costs related to assets acquired in 2019; and
•
an increase of $24 million in Adjusted EBITDA related to unconsolidated affiliates due to assets acquired in 2019.
Investment in Sunoco LP
Three Months Ended
March 31,
 
 
Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2020
 
2019
 
Change
2020 2019 Change 2020 2019 Change
Revenues
$
3,272

 
$
3,692

 
$
(420
)
$2,080
 $4,475
 $(2,395) $5,352
 $8,167
 $(2,815)
Cost of products sold
3,164

 
3,322

 
(158
)
1,722
 4,206
 (2,484) 4,886
 7,528
 (2,642)
Segment margin
108

 
370

 
(262
)
358
 269
 89
 466
 639
 (173)
Unrealized (gains) losses on commodity risk management activities
6

 
(6
)
 
12

—
 3
 (3) 6
 (3) 9
Operating expenses, excluding non-cash compensation expense
(109
)
 
(98
)
 
(11
)
(72) (89) 17
 (181) (187) 6
Selling, general and administrative expenses, excluding non-cash compensation expense
(30
)
 
(24
)
 
(6
)
(22) (31) 9
 (52) (55) 3
Adjusted EBITDA related to unconsolidated affiliates
2

 
—

 
2

3
 —
 3
 5
 —
 5
Inventory valuation adjustments
227

 
(93
)
 
320

(90) (4) (86) 137
 (97) 234
Other
5

 
4

 
1

5
 4
 1
 10
 8
 2
Segment Adjusted EBITDA
$
209

 
$
153

 
$
56

$182
 $152
 $30
 $391
 $305
 $86
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the three months endedMarch 31, June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impacts of the following:
•
•
an increase of$70 $16 million in motor fuel sales as a result of an increase in gross profit onper gallon sold, partially offset by a decrease in gallons sold;
a decrease of $26 million in operating expenses and selling, general and administrative expenses, excluding non-cash compensation expense, primarily attributable to lower employee costs, maintenance, advertising, credit card fees and utilities; and
an increase of $3 million in Adjusted EBITDA related to unconsolidated affiliates which was attributable to the JC Nolan joint venture entered into in 2019; partially offset by
a decrease of $15 million in non-motor fuel sales gross margin as a result of reduced credit card transactions related to the COVID-19 pandemic.
Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impacts of the following:
•
an increase of $84 million in motor fuel sales primarily due toas a 32.6%result of a 39.6% increase in gross profit per gallon sold and the receipt of a $13 million make-up payment under athe fuel supply agreement;agreement with 7-Eleven, Inc.; partially offset by a 2.2%14.6% decrease in gallons sold;


52
Table of Contents

•
•
an increase in non-motor fuel sales gross profita decrease of $2 million; and
•
an increase in unconsolidated affiliate adjusted EBITDA of $2 million; partially offset by
•
an increase of $17$9 million in operating expenses and selling, general and administrative expenses, excluding non-cash compensation expense, primarily attributable to lower employee costs, maintenance, advertising, credit card fees and utilities. This decrease is primarily offset by a $16 million charge for current expected credit losses ofon Sunoco LP’sLP’s accounts receivable in connection with the financial impact from COVID-19.COVID-19; and
•
an increase in unconsolidated affiliate Adjusted EBITDA of $5 million, which was attributable to the JC Nolan joint venture entered into in 2019; partially offset by
•
a decrease of $13 million in non motor fuel sales primarily due to reduced credit card transactions related to the COVID-19 pandemic.
Investment in USAC
Three Months Ended
March 31,
 
 
Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2020
 
2019
 
Change
2020 2019 Change 2020 2019 Change
Revenues
$
179

 
$
171

 
$
8

$169
 $174
 $(5) $348
 $345
 $3
Cost of products sold
24

 
22

 
2

18
 24
 (6) 42
 46
 (4)
Segment margin
155

 
149

 
6

151
 150
 1
 306
 299
 7
Operating expenses, excluding non-cash compensation expense
(35
)
 
(35
)
 
—

(30) (32) 2
 (65) (67) 2
Selling, general and administrative expenses, excluding non-cash compensation expense
(14
)
 
(13
)
 
(1
)
(16) (13) (3) (30) (26) (4)
Segment Adjusted EBITDA
$
106

 
$
101

 
$
5

$105
 $105
 $—
 $211
 $206
 $5
The Investment in USAC segment reflects the consolidated results of USAC.
Segment Adjusted EBITDA. For the three months ended June 30, 2020, Segment Adjusted EBITDA related to our investment in USAC segment was consistent with the same period last year primarily due to the offsetting impacts of the following:
•
an increase of $3 million in selling, general and administrative expenses primarily due to an increase in the provision for expected credit losses; offset by
•
a decrease of $2 million in operating expenses, as well as an increase of $1 million in segment margin primarily due to a decrease in cost of products sold offset by a decrease in revenues as a result of a decrease in average revenue generating horsepower.
Segment Adjusted EBITDA. March 31,For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impacts of the following:
•
•
an increase of $6$7 million in segment margin primarily due to an increase revenues as a result of thean increase in average revenue generating horsepower;fleet horsepower and a decrease in cost of products sold; partially offset by
•
•
an increase of$1 $4 millionin selling, general and administrative expenses primarily due to an increase in the provision for expected credit losses.


4753
Table of Contents

All Other
Three Months Ended
March 31,
 
 
Three Months Ended
June 30,		   Six Months Ended
June 30,		  
2020
 
2019
 
Change
2020 2019 Change 2020 2019 Change
Revenues
$
454

 
$
497

 
$
(43
)
$492
 $391
 $101
 $1,005
 $888
 $117
Cost of products sold
415

 
455

 
(40
)
377
 343
 34
 792
 798
 (6)
Segment margin
39

 
42

 
(3
)
115
 48
 67
 213
 90
 123
Unrealized gains on commodity risk management activities
(5
)
 
(1
)
 
(4
)
Unrealized (gains) losses on commodity risk management activities2
 (4) 6
 (3) (5) 2
Operating expenses, excluding non-cash compensation expense
(8
)
 
(7
)
 
(1
)
(27) (6) (21) (65) (13) (52)
Selling, general and administrative expenses, excluding non-cash compensation expense
(26
)
 
(13
)
 
(13
)
(19) (20) 1
 (51) (33) (18)
Adjusted EBITDA related to unconsolidated affiliates
—

 
(1
)
 
1

—
 2
 (2) —
 1
 (1)
Other and eliminations
19

 
13

 
6

(67) (7) (60) (48) 6
 (54)
Segment Adjusted EBITDA
$
19

 
$
33

 
$
(14
)
$4
 $13
 $(9) $46
 $46
 $—
Amounts reflected in our all other segment primarily include:
•
our natural gas marketing operations;
our wholly-owned natural gas compression operations;
our investment in coal handling facilities; and
our Canadian operations, which were acquired in the SemGroup acquisition in December 2019 and include natural gas gathering and processing assets.
our natural gas marketing operations;
•
our wholly-owned natural gas compression operations;
•
a noncontrolling interest in PES. Prior to PES’s reorganization in August 2018, ETO’s 33% interest in PES was reflected as an unconsolidated affiliate; subsequent to the August 2018 reorganization, ETO holds an approximately 7.4% interest in PES and no longer reflects PES as an affiliate; and
•
our investment in coal handling facilities.
Segment Adjusted EBITDA. For the three months endedMarch 31, June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impacts of the following:
•
•
a decrease of $2$7 milliondue to lower sales of residue gas;
•
•a decrease of $11 million due to lower revenues from our compression equipment business;
a decrease of $7 million due to power trading activities;
a decrease of $5 million due to lower demand and operator production at our natural resources business;
•
a decrease of $4 million due to storage gains; and
•
a decrease of $3 million from increased power costs at our compression services business; partially offset by
•
an increase of $25 million from the acquisition of SemCAMS; and
•
an increase of $6 million in settled derivatives.
Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment was comparable due to the net impacts of the following:
•
a decrease of $9 million from power trading activities;
•
a decrease of $9 million due to lower sales of residue gas;
•
a decrease of $6 million due to lower gas prices and increased power costs at our compression services business;
•
•
a decrease of $4$4 milliondue to lower revenues from our compression equipment business;storage, park and loan operations;
•
•
a decrease of $10$18 million due to changes in eliminations of intersegment amounts, the net impacts of which are reflected in the all other segment; lower revenue from our compression equipment business;
•
•
a decrease of $3$20 milliondue to higher expenses in our compression business resulting from lower cost recoveriesmerger and higher allocated costs;acquisition expense;
•
•
a decrease of $2$8 milliondue to power trading activities;lower demand and operator production at our natural resources business; and


54
Table of Contents

•
a decrease of $5 million due to the elimination of Sunoco LP’s interest in our JC Nolan joint venture; partially offset by
•
•
a decreasean increase of $51 million from the acquisition of SemCAMS;$16 milliondue to higher merger and acquisition expense in the current period; partially offset by
•
•
an increase of $16$17 millionfrom settlement payments received from our ownership of PES; and
•
•
an increase of $8 million in settled derivatives.$5 milliondue to storage gains.


55
Table of Contents

LIQUIDITY AND CAPITAL RESOURCES
Overview
Our ability to satisfy obligations and pay distributions to unitholders will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’smanagement’s control.


48
Table of Contents

We currently expect capital expenditures in 2020 to be within the following ranges (excluding capital expenditures related to our investments in Sunoco LP and USAC):
Growth
 
Maintenance
Growth Maintenance
Low
 
High
 
Low
 
High
Low High Low High
Intrastate transportation and storage
$
10

 
$
20

 
$
40

 
$
45

$10
 $20
 $40
 $45
Interstate transportation and storage (1)
75

 
100

 
125

 
130

75
 100
 115
 120
Midstream
400

 
425

 
105

 
110

450
 475
 105
 110
NGL and refined products transportation and services
2,550

 
2,700

 
85

 
95

2,425
 2,525
 95
 105
Crude oil transportation and services (1)
275

 
300

 
140

 
150

275
 300
 130
 140
All other (including eliminations)
50

 
75

 
55

 
60

75
 100
 55
 60
Total capital expenditures
$
3,360

 
$
3,620

 
$
550

 
$
590

$3,310
 $3,520
 $540
 $580
(1) 
Includes capital expenditures related to our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.
The assets used in our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time we experience increases in pipe costs due to a number of factors, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control; however, we have included these factors in our anticipated growth capital expenditures for each year.
We generally fund maintenance capital expenditures and distributions with cash flows from operating activities. We generally fund growth capital expenditures with borrowings under credit facilities, long-term debt, the issuance of additional preferred units or a combination thereof.
Sunoco LP
Sunoco LP currently expects to spend approximately$30 $30 millionon growth capital and$75 $75 millionon maintenance capital for the full year2020. 2020.
USAC
USAC currently plans to spend approximately$30 $30 millionin on maintenance capital expenditures during 2020, including parts consumed from inventory.
Without giving effect to any equipment USAC may acquire pursuant to any future acquisitions, it currently has budgeted between$80 $80 million and $90$90 millionin expansion capital expenditures during 2020. As ofMarch 31, June 30, 2020,, USAC has binding commitments to purchase$34 $18 millionof additional compression units and serialized parts, all of which USAC expects to be delivered throughout 2020.
Cash Flows
Our cash flows may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price for our and our subsidiaries’subsidiaries’ products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions and other factors.
Operating Activities
Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results“Results of Operations”Operations” above), excluding the impacts of non-cash items and net changes in operating assets and liabilities (net of effects


56
Table of Contents

of acquisitions). Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisition of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities


49
Table of Contents

between periods result from factors such as the changes in the value of price risk management assets and liabilities, the timing of accounts receivable collection, the timing of payments on accounts payable, the timing of purchase and sales of inventories and the timing of advances and deposits received from customers.
ThreeSix months ended March 31,June 30, 2020 compared to threesix months ended March 31,2019.June 30, 2019. Cash provided by operating activities during 2020 was $1.83$3.38 billion compared to $1.85$4.02 billion for 2019,, and net loss was $907$195 million for 2020 and net income was $1.22$2.50 billion for 2019.2019. The difference between net loss and net cash provided by operating activities for the threesix months ended March 31,June 30, 2020 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions) of $113$27 million and other non-cash items totaling $2.56 billion.$3.42 billion.
The non-cash activity in 2020 and 2019 consisted primarily of depreciation, depletion and amortization of $851 million$1.80 billion and $771 million,$1.55 billion, respectively, non-cash compensation expense of $18$63 million and $29$58 million,, respectively, inventory valuation adjustments of $227$137 million and $93$97 million,, respectively, and deferred incomes taxes of $66$126 million and $98$140 million,, respectively. Non-cash activity also included losses on extinguishments of debt in 2020 and 2019 of $59$59 million and $2$2 million,, respectively, and impairment losses of $1.33$1.33 billion and $50$50 million in 2020 and 2019,, respectively.
Unconsolidated affiliate activity in 2020 and 2019 consisted of equity in losses of $7 million and equity in earnings of $65$78 million, and $142 million, respectively, and cash distributions received of $58$125 million and $66$170 million,, respectively.
Cash paid for interest, net of interest capitalized, was $533 million$1.05 billion and $581 million$1.02 billion for the threesix months ended March 31,June 30, 2020 and 2019,, respectively. Interest capitalized was $38$106 million and $43$94 million for the threesix months ended March 31,June 30, 2020 and 2019,, respectively.
Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash contributions to our joint ventures, and cash proceeds from sales or contributions of assets or businesses. In addition, distributions from equity investees are included in cash flows from investing activities if the distributions are deemed to be a return of the Partnership’sPartnership’s investment. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.
ThreeSix months ended March 31,June 30, 2020 compared to threesix months ended March 31,2019.June 30, 2019. Cash used in investing activities during 2020 was $1.56$2.76 billion compared to $1.10$2.94 billion in 2019.2019. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2020 were $1.60$2.85 billion compared to $1.14$2.78 billion for 2019.2019. Additional detail related to our capital expenditures is provided in the table below. During 2019,, we received $93$93 million of cash proceeds from the sale of a noncontrolling interest in a subsidiary and paid $5$7 million in cash for all other acquisitions.


57
Table of Contents

The following is a summary of capital expenditures (including only our proportionate share of the Bakken, Rover and Bayou Bridge pipeline projects and net of contributions in aid of construction costs) on an accrual basis for thethree six months ended March 31,2020:June 30, 2020:
Capital Expenditures Recorded During Period
Capital Expenditures Recorded During Period
Growth
 
Maintenance
 
Total
Growth Maintenance Total
Intrastate transportation and storage
$
2

 
$
24

 
$
26

$2
 $34
 $36
Interstate transportation and storage
8

 
7

 
15

22
 34
 56
Midstream
128

 
23

 
151

243
 55
 298
NGL and refined products transportation and services
774

 
16

 
790

1,340
 39
 1,379
Crude oil transportation and services
83

 
12

 
95

115
 37
 152
Investment in Sunoco LP
36

 
5

 
41

50
 9
 59
Investment in USAC
47

 
9

 
56

69
 13
 82
All other (including eliminations)
16

 
6

 
22

56
 18
 74
Total capital expenditures
$
1,094

 
$
102

 
$
1,196

$1,897
 $239
 $2,136
Financing Activities
Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures.


50
Table of Contents

ThreeSix months ended March 31,June 30, 2020 compared to threesix months ended March 31,2019.June 30, 2019. Cash used in financing activities during 2020 was $345$750 million compared to $650 million$1.05 billion for 2019.2019. During 2020,, we received net proceeds of $1.58$1.58 billion from the issuance of preferred units. During 2020,, we had a net decreaseincrease in our debt level of $70$934 million compared to a net increase of $1.17$1.94 billion for 2019.2019. In 2020 and 2019,, we paid debt issuance costs of $51$50 million and $84$87 million,, respectively.
In 2020 and 2019,, we paid distributions of $1.53$2.70 billion and $1.51$3.16 billion,, respectively, to our partners. In 2020 and 2019,, we paid distributions of $340$680 million and $361$731 million,, respectively, to noncontrolling interests. In addition, we received capital contributions of $66$148 million in cash from noncontrolling interests in 2020 compared to $140$206 million in cash from noncontrolling interests in 2019.2019.


58
Table of Contents

Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
March 31, 2020
 
December 31, 2019
June 30,
2020		 December 31,
2019
ETO Senior Notes
$
37,782

 
$
36,118

$37,783
 $36,118
Transwestern Senior Notes
400

 
575

400
 575
Panhandle Senior Notes
235

 
235

235
 235
Bakken Senior Notes
2,500

 
2,500

2,500
 2,500
Sunoco LP Senior Notes and lease-related obligations
2,932

 
2,935

2,929
 2,935
USAC Senior Notes
1,475

 
1,475

1,475
 1,475
Credit facilities and commercial paper:
 
 
 
   
ETO $2.00 billion Term Loan facility due October 2022
2,000

 
2,000

2,000
 2,000
ETO $5.00 billion Revolving Credit Facility due December 2023 (1)
1,955

 
4,214

3,010
 4,214
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023
265

 
162

158
 162
USAC $1.60 billion Revolving Credit Facility due April 2023
459

 
403

448
 403
HFOTCO Tax Exempt Notes due 2050
225

 
225

225
 225
SemCAMS Revolver due February 202492
 92
SemCAMS Revolver Term Loan A due February 2024251
 269
Other long-term debt
8

 
2

11
 2
Net unamortized premiums, discounts, and fair value adjustments
(10
)
 
4

(11) 4
Deferred debt issuance costs
(301
)
 
(276
)
(293) (279)
Total debt
49,925

 
50,572

51,213
 50,930
Less: current maturities of long-term debt
16

 
12

34
 25
Long-term debt, less current maturities
$
49,909

 
$
50,560

$51,179
 $50,905
(1) 
Includes $113 million$1.11 billion and $1.64$1.64 billion of commercial paper outstanding at March 31,June 30, 2020 and December 31, 2019,, respectively.
Recent Transactions
ETO January 2020 Senior Notes Offering and Redemption
On January 22, 2020, ETO completed a registered offering (the “January“January 2020 Senior Notes Offering”Offering”) of $1.00 billion aggregate principal amount of the Partnership’sPartnership’s 2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of the Partnership’sPartnership’s 3.750% Senior Notes due 2030 and $2.00 billion aggregate principal amount of the Partnership’sPartnership’s 5.000% Senior Notes due 2050 (collectively, the “Notes”“Notes”). The Notes are fully and unconditionally guaranteed by the Partnership’sPartnership’s wholly-owned subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis.
Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of 5.75% Senior Notes due September 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET’sET's $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’sTranswestern's $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.


51
Table of Contents

Credit Facilities and Commercial Paper
ETO Term Loan
ETO’sETO’s term loan credit agreement provides for a $2$2 billion three-year term loan credit facility (the “ETO“ETO Term Loan”Loan”). Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreementETO Term Loan is unsecured and is guaranteed by ourETO’s subsidiary, Sunoco Logistics Operations.
As ofMarch 31, June 30, 2020,, the ETO Term Loan had$2 $2 billionoutstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as of June 30, 2020 was 1.18%.


59
Table of ContentsMarch 31, 2020was1.92%.

ETO Five-Year Credit Facility
ETO’sETO’s revolving credit facility (the “ETO“ETO Five-Year Credit Facility”Facility”) allows for unsecured borrowings up to$5.00 $5.00 billionand matures on December 1, 2023. The ETO Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to$6.00 $6.00 billionunder certain conditions.
As ofMarch 31, June 30, 2020,, the ETO Five-Year Credit Facility had$1.96 $3.01 billion of outstanding borrowings, $113 million$1.11 billion of which was commercial paper. The amount available for future borrowings was$2.97 $1.90 billion,after taking into account letters of credit of$72 million. $86 million. The weighted average interest rate on the total amount outstanding as ofMarch 31, June 30, 2020was2.24% 1.34%.
ETO 364-Day Facility
ETO’sETO’s 364-day revolving credit facility (the “ETO“ETO 364-Day Facility”Facility”) allows for unsecured borrowings up to$1.00 $1.00 billionand matures on November 27, 2020.As ofMarch 31, June 30, 2020,, the ETO 364-Day Facility hadnooutstanding borrowings.
Sunoco LP Credit Facility
Sunoco LP maintains a$1.50 $1.50 billionrevolving credit facility (the “Sunoco“Sunoco LP Credit Facility”Facility”), which matures in July 2023. As ofMarch 31, June 30, 2020,, the Sunoco LP Credit Facility had$265 $158 millionof outstanding borrowings and$8 $8 millionin standby letters of credit. As ofMarch 31, June 30, 2020,Sunoco LP had$1.23 $1.33 billion of availability under the Sunoco LP Credit Facility. The weighted average interest rate on the total amount outstanding as ofMarch 31, June 30, 2020 was 2.63%2.19%.
USAC Credit Facility
USAC maintains a$1.60 $1.60 billionrevolving credit facility (the “USAC“USAC Credit Facility”Facility”), with a further potential increase of$400 $400 million,, which matures in April 2023. As of March 31,June 30, 2020,, the USAC Credit Facility had$459 $448 millionof outstanding borrowings andnooutstanding letters of credit. As ofMarch 31, June 30, 2020,, USAC had$1.14 $1.15 billionof borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of$186 $151 millionunder the USAC Credit Facility. The weighted average interest rate on the total amount outstanding as of June 30, 2020 was 2.77%.
SemCAMS Credit Facilities
SemCAMS is party to a credit agreement providing for a C$350 million (US$257 million at the March 31,June 30, 2020 was 3.67%exchange rate) senior secured term loan facility, a C$525 million (US$385 million at the June 30, 2020exchange rate) senior secured revolving credit facility, and a C$300 million (US$220 million at theJune 30, 2020exchange rate) senior secured construction loan facility (the “KAPS Facility”). The term loan facility and the revolving credit facility mature on February 25, 2024. The KAPS Facility matures on June 13, 2024. SemCAMS may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250 million (US$183 million at the June 30, 2020exchange rate), subject to receiving commitments for such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders.As of June 30, 2020, the SemCAMS senior secured term loan facility and senior secured revolving credit facility had $251 million and $92 million, respectively, of outstanding borrowings. As of June 30, 2020, the KAPS Facility hadnooutstanding borrowings.
Covenants Related to Our Credit Agreements
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as ofMarch 31, 2020. June 30, 2020.
Parent and Subsidiary Guarantee of Senior Notes
Sunoco Logistics Operations is the issuer of multiple series of senior notes that are guaranteed by ETO. Supplemental indentures were previously issued on all of the outstanding ETO senior notes to provide the guaranty by Sunoco Logistics Operations. These guarantees are full and unconditional on a senior unsecured basis. No other consolidated subsidiaries of the Partnership guarantee the senior notes. Neither Sunoco Logistics Operations nor ETO have material independent assets or operations, other than their investments in and receivables from affiliates which are not subject to these guarantees.
Certain of ETO’sETO's and Sunoco Logistics Operations’Operations' subsidiaries are less than wholly-owned. Consequently, such subsidiaries have noncontrolling interest holders whose rights and obligations are generally similar to ours, except in cases where redeemable and/or preferred noncontrolling interests exist. Additional information and balances related to noncontrolling interests are available in the consolidated financial statements and notes thereto included in “Item"Item 1. Financial Statements”Statements" in this quarterly report on Form 10-Q and in “Item"Item 8. Financial Statements and Supplementary Data”Data" included in our annual report on Form 10-K.
In addition, because none of ETO’sETO’s or Sunoco Logistics Operations’Operations’ other subsidiaries guarantee the senior notes, the senior notes are structurally subordinated to the claims of all creditors, including unsecured indebtedness, trade creditors and tort claimants,


60
Table of Contents

of those subsidiaries. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the


52
Table of Contents

business of any of our subsidiaries (except for Sunoco Logistics Operations), creditors of such subsidiaries would generally have the right to be paid in full before any distribution is made to us or the holders of the senior notes. As of March 31,June 30, 2020, our subsidiaries (other than Sunoco Logistics Operations) had an aggregate of $8.6$8.8 billion of indebtedness outstanding.
CASH DISTRIBUTIONS
Distributions on ETO’sETO’s preferred units declared and/or paid by the Partnership subsequent toDecember 31, 2019were as follows:
Period Ended
 
Record Date
 
Payment Date
 
Series A (1)
 
Series B (1)
 
Series C
 
Series D
 
Series E
 
Series F (2)
 
Series G (2)
 Record Date Payment Date 
Series A (1)
 
Series B (1)
 Series C Series D Series E 
Series F (2)
 
Series G (2)
December 31, 2019
 
February 3, 2020
 
February 18, 2020
 
$
31.25

 
$
33.125

 
$
0.4609

 
$
0.4766

 
$
0.4750

 
$
—

 
$
—

 February 3, 2020 February 18, 2020 $31.25
 $33.125
 $0.4609
 $0.4766
 $0.4750
 $—
 $—
March 31, 2020
 
May 1, 2020
 
May 15, 2020
 
—

 
—

 
0.4609

 
0.4766

 
0.4750

 
21.19

 
22.36

 May 1, 2020 May 15, 2020 —
 —
 0.4609
 0.4766
 0.4750
 21.19
 22.36
June 30, 2020 August 3, 2020 August 17, 2020 31.25
 33.125
 0.4609
 0.4766
 0.4750
 —
 —
(1) 
Series A Preferred Unit and Series B Preferred Unit distributions are paid on a semi-annual basis.
(2) 
Series F Preferred Unit and Series G Preferred Unit distributions related to the period ended March 31, 2020 represent a prorated initial distribution. Distributions are paid on a semi-annual basis.  
Sunoco LP Cash Distributions
Distributions declared and/or paid by Sunoco LP subsequent to its common unitholders subsequent to December 31, 2019were as follows:
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
 Record Date Payment Date Rate
December 31, 2019
 
February 7, 2020
 
February 19, 2020
 
$
0.8255

 February 7, 2020 February 19, 2020 $0.8255
March 31, 2020
 
May 7, 2020
 
May 19, 2020
 
0.8255

 May 7, 2020 May 19, 2020 0.8255
June 30, 2020 August 7, 2020 August 19, 2020 0.8255
USAC Cash Distributions
Distributions declared and/or paid by USAC to its common unitholders subsequent toDecember 31, 2019were as follows:
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
 Record Date Payment Date Rate
December 31, 2019
 
January 27, 2020
 
February 7, 2020
 
$
0.5250

 January 27, 2020 February 7, 2020 $0.5250
March 31, 2020
 
April 27, 2020
 
May 8, 2020
 
0.5250

 April 27, 2020 May 8, 2020 0.5250
June 30, 2020 July 31, 2020 August 10, 2020 0.5250
ESTIMATES AND CRITICAL ACCOUNTING POLICIES
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. We describe our significant accounting policies in Note 2 to our consolidated financial statements in the Partnership’sPartnership’s Annual Report on Form 10-K filed with the SEC on February 21, 2020.2020. See Note 1 in “Item“Item 1. Financial Statements”Statements” for information regarding recent changes to the Partnership’sPartnership’s critical accounting policies related to inventory.
RECENT ACCOUNTING PRONOUNCEMENTS
Currently, there are no accounting pronouncements that have been issued, but not yet adopted, that are expected to have a material impact on the Partnership’sPartnership’s financial position or results of operations.


61
Table of Contents

FORWARD-LOOKING STATEMENTS
This quarterly report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will”“anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are


53
Table of Contents

based are reasonable, neither we nor our General Partner can give assurances that such expectations 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, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:
•
•
changes in the long-term supply of and demand for natural gas, NGLs, refined products and/or crude oil, including as a result of uncertainty regarding the length of time it will take for the United States and the rest of the world to slow the spread of the COVID-19 virus to the point where applicable authorities are comfortable easing current restrictions on various commercial and economic activities; such restrictions are designed to protect public health but also have the effect of reducing demand for natural gas, NGLs, refined products and crude oil;
•
•
the severity and duration of world health events, including the recent COVID-19 pandemic, related economic repercussions, actions taken by governmental authorities and other third parties in response to the pandemic and the resulting severe disruption in the oil and gas industry and negative impact on demand for natural gas, NGLs, refined products and crude oil, which may negatively impact our business;
•
•
changes in general economic conditions and changes in economic conditions of the crude oil and natural gas industries specifically, including the current significant surplus in the supply of oil and actions by foreign oil-producing nations with respect to oil production levels and announcements of potential changes in such levels, including the ability of those countries to agree on and comply with supply limitation;
•
•
uncertainty regarding the timing, pace and extent of an economic recovery in the United States and elsewhere, which in turn will likely affect demand for natural gas, NGLs, refined products and crude oil and therefore the demand for midstream services we provide and the commercial opportunities available to us;
•
•
the deterioration of the financial condition of our customers and the potential renegotiation or termination of customer contracts as a result of such deterioration;
•
•
operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;
•
•
actions taken by federal, state or local governments to require producers of natural gas, NGL, refined products and crude oil to proration or cut their production levels as a way to address any excess market supply situations;
•
•
the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;
•
•
the actual amount of cash distributions by our subsidiaries to us;
•
•
the volumes transported on our subsidiaries’subsidiaries’ pipelines and gathering systems;
•
•
the level of throughput in our subsidiaries’subsidiaries’ processing and treating facilities;
•
•
the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services;
•
•
the prices and market demand for, and the relationship between, natural gas and NGLs;
•
•
energy prices generally;
•
•
the prices of natural gas and NGLs compared to the price of alternative and competing fuels;
•
•
the general level of petroleum product demand and the availability and price of NGL supplies;
•
•
the level of domestic natural gas, NGL, refined products and crude oil production;
•
•
the availability of imported natural gas, NGLs, refined products and crude oil;


62
Table of Contents

•
•
actions taken by foreign oil and gas producing nations;
•
•
the political and economic stability of petroleum producing nations;
•
•
the effect of weather conditions on demand for natural gas, NGLs, refined products and crude oil;
•
•
availability of local, intrastate and interstate transportation systems;
•
•
the continued ability to find and contract for new sources of natural gas supply;
•
•
availability and marketing of competitive fuels;


54
Table of Contents

•
•
the impact of energy conservation efforts;
•
•
energy efficiencies and technological trends;
•
•
governmental regulation and taxation;
•
•
changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’subsidiaries’ interstate and intrastate pipelines;
•
•
hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;
•
•
competition from other midstream companies and interstate pipeline companies;
•
•
loss of key personnel;
•
•
loss of key natural gas producers or the providers of fractionation services;
•
•
reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities;
•
•
the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments;
•
•
the nonpayment or nonperformance by our subsidiaries’subsidiaries’ customers;
•
•
regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our subsidiaries’subsidiaries' internal growth projects, such as our subsidiaries’subsidiaries' construction of additional pipeline systems;
•
•
risks associated with the construction of new pipelines and treating and processing facilities or additions to our subsidiaries’subsidiaries' existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;
•
•
the availability and cost of capital and our subsidiaries’subsidiaries' ability to access certain capital sources;
•
•
a deterioration of the credit and capital markets;
•
•
risks associated with the assets and operations of entities in which our subsidiaries own less than a controlling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence;
•
•
the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;
•
•
changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and
•
•
the costs and effects of legal and administrative proceedings.
Many of the foregoing risks and uncertainties are, and will be, heightened by the COVID-19 pandemic and any further worsening of the global business and economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this Quarterly Report on Form 10-Q or our Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under ““Part I - Item 1A. Risk Factors”Factors” in our Annual Report on Form 10-K and “Partfor the year ended December 31, 2019, “Part II - Item 1A. Risk Factors”Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 and “Part II - Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q. Any forward-looking statement made by us in this Quarterly Report on Form 10-Q is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.


63
Table of Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II - Item 7A7A. included in the Partnership’sPartnership’s Annual Report on Form 10-K for the year ended December 31, 2019 filed with the SEC on February 21, 2020,, in addition to the accompanying notes and management’smanagement’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed for the year ended December 31, 2019.2019. Since December 31, 2019, there have been no material changes to our primary market risk exposures or how those exposures are managed.


55
Table of Contents

Commodity Price Risk
The table below summarizes our commodity-related financial derivative instruments and fair values, including derivatives related to our consolidated subsidiaries, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity. Dollar amounts are presented in millions.
March 31, 2020
 
December 31, 2019
June 30, 2020 December 31, 2019
Notional Volume
 
Fair Value Asset (Liability)
 
Effect of Hypothetical 10% Change
 
Notional Volume
 
Fair Value Asset (Liability)
 
Effect of Hypothetical 10% Change
Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
 
 
 
 
 
 
 
 
 
 
 
           
(Trading)
 
 
 
 
 
 
 
 
 
 
 
           
Natural Gas (BBtu):
 
 
 
 
 
 
 
 
 
 
 
           
Basis Swaps IFERC/NYMEX (1)
(19,673
)
 
$
14

 
$
4

 
(35,208
)
 
$
2

 
$
5

(20,433) $10
 $4
 (35,208) $2
 $5
Fixed Swaps/Futures
1,688

 
—

 
—

 
1,483

 
—

 
—

373
 —
 —
 1,483
 —
 —
Power (Megawatt):
 
 
 
 
 
 
 
 
 
 
 
           
Forwards
2,125,200

 
6

 
5

 
3,213,450

 
6

 
8

1,338,776
 4
 3
 3,213,450
 6
 8
Futures
329,896

 
—

 
1

 
(353,527
)
 
1

 
2

204,090
 —
 1
 (353,527) 1
 2
Options – Puts
621,860

 
2

 
—

 
51,615

 
1

 
—

Options – Calls
4,035,972

 
1

 
—

 
(2,704,330
)
 
1

 
—

Options – Puts(340,743) 1
 —
 51,615
 1
 —
Options – Calls(1,268,532) 1
 —
 (2,704,330) 1
 —
(Non-Trading)
 
 
 
 
 
 
 
 
 
 
 
           
Natural Gas (BBtu):
 
 
 
 
 
 
 
 
 
 
 
           
Basis Swaps IFERC/NYMEX
(15,860
)
 
10

 
9

 
(18,923
)
 
(35
)
 
15

(27,713) 19
 8
 (18,923) (35) 15
Swing Swaps IFERC
31,505

 
—

 
2

 
(9,265
)
 
—

 
4

(35,590) (3) 8
 (9,265) —
 4
Fixed Swaps/Futures
(1,425
)
 
(2
)
 
1

 
(3,085
)
 
(1
)
 
1

(10,708) (20) 20
 (3,085) (1) 1
Forward Physical Contracts
(36,691
)
 
5

 
8

 
(13,364
)
 
3

 
3

(23,980) 6
 6
 (13,364) 3
 3
NGLs (MBbls) – Forwards/Swaps
(2,235
)
 
36

 
8

 
(1,300
)
 
(18
)
 
18

Refined Products (MBbls) – Futures
(1,779
)
 
(7
)
 
4

 
(2,473
)
 
(2
)
 
16

Crude (MBbls) – Forwards/Swaps
5,260

 
3

 
1

 
4,465

 
13

 
2

NGLs (MBbls) – Forwards/Swaps(8,830) (10) 20
 (1,300) (18) 18
Refined Products (MBbls) – Futures(3,370) (17) 1
 (2,473) (2) 16
Crude (MBbls) – Forwards/Swaps3,393
 2
 —
 4,465
 13
 2
Corn (thousand bushels)
(140
)
 
—

 
—

 
(1,210
)
 
—

 
—

—
 —
 —
 (1,210) —
 —
Fair Value Hedging Derivatives
 
 
 
 
 
 
 
 
 
 
 
           
(Non-Trading)
 
 
 
 
 
 
 
 
 
 
 
           
Natural Gas (BBtu):
 
 
 
 
 
 
 
 
 
 
 
           
Basis Swaps IFERC/NYMEX
(32,695
)
 
(1
)
 
8

 
(31,780
)
 
1

 
7

(43,235) —
 10
 (31,780) 1
 7
Fixed Swaps/Futures
(32,695
)
 
—

 
9

 
(31,780
)
 
23

 
7

(43,235) (4) 11
 (31,780) 23
 7
(1) 
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
The fair values of the commodity-related financial positions have been determined using independent third-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial


64
Table of Contents

instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.
Interest Rate Risk
As of March 31,June 30, 2020, we had $5.50$6.78 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $55$68 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of


56
Table of Contents

our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.
The following table summarizes our interest rate swaps outstanding (dollars in millions), none of which are designated as hedges for accounting purposes:
Term
 
Type(1)
 
Notional Amount Outstanding
 
Type(1)
 Notional Amount Outstanding
March 31, 2020
 
December 31, 2019
June 30,
2020		 December 31,
2019
July 2020(2)(3)
 
Forward-starting to pay a fixed rate of 3.52% and receive a floating rate
 
$
—

 
$
400

 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate $—
 $400
July 2021(2)
 
Forward-starting to pay a fixed rate of 3.55% and receive a floating rate
 
400

 
400

 Forward-starting to pay a fixed rate of 3.55% and receive a floating rate 400
 400
July 2022(2)
 
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
 
400

 
400

 Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 400
 400
(1)Floating rates are based on 3-month LIBOR.  
(2) 
Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.  
(3)The July 2020 interest rate swaps were terminated in January 2020.
A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a net change in the fair value of interest rate derivatives and earnings (recognized in gains and losses on interest rate derivatives) of $312$311 million as of March 31, 2020.June 30, 2020. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’sSEC’s rules and forms.
Under the supervision and with the participation of senior management, including the Chief Executive Officer (“(“Principal Executive Officer”Officer”) and the Chief Financial Officer (“(“Principal Financial Officer”Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of March 31,June 30, 2020 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC’sSEC’s rules and forms, and (ii) is accumulated and communicated to management, including the Principal Executive Officer and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
During thethree months endedJune 30, 2020, certain of the Partnership’s subsidiaries implemented an enterprise resource planning (“ERP”) system, in order to update existing technology and to integrate, simplify and standardize processes among the Partnership and its subsidiaries. Accordingly, we have made changes to our internal controls to address systems and/or processes impacted by the ERP implementation. Neither the ERP implementation nor the related control changes were undertaken in response to any deficiencies in the Partnership’s internal control over financial reporting.


65
ThereTable of Contents

Other than as discussed above, there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended March 31,June 30, 2020 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.


57

66
Table of Contents

PART II –– OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information regarding legal proceedings, see our Annual Report on Form 10-K filed with the SEC on February 21, 2020 and Note 10 – – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Operating, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.June 30, 2020.
Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed below were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report governmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $100,000.$100,000.
Pursuant to the instructions to Form 10-Q, matters disclosed in this Part II - Item 1 include any reportable legal proceeding (i) that has been terminated during the period covered by this report, (ii) that became a reportable event during the period covered by this report, or (iii) for which there has been a material development during the period covered by this report.
On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma.  The rupture occurred on the Noble to Douglas 8” pipeline in an area of external corrosion and caused the release of approximately fifteen barrels of crude oil.  SPLP responded immediately to the release and remediated the surrounding environment and pipeline in cooperation with the OCC.  The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the pipeline causing the failure.  SPLP negotiated a settlement agreement with the OCC for $500,000 and agreed to perform close interval potential surveys on all SPLP intrastate hazardous liquid transmission pipeline segments in Oklahoma, which could affect high consequence areas.  SPLP is awaiting signature by the OCC commissioners to finalize the settlement agreement.
For a description of other legal proceedings, see Note 10 to our consolidated financial statements included in “Item“Item 1. Financial Statements.””
ITEM 1A. RISK FACTORS
The following risk factors should be read in conjunction with our risk factors described in “Part"Part I - Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2019 filed with the SEC on February 21, 2020.
The outbreak of COVID-19 and recent geopolitical developmentsFactors" in the crude oil market could adversely impact our business, financial condition and results of operations.
On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency because of a new strain of coronavirus known as COVID-19 due to the risks it imposes on the international community as the virus spreads globally. In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally. The global spread of COVID-19 caused a significant decline in economic activity and a reduced demand for goods and services, particularly in the energy industry, due to reduced operations and/or closures of businesses, “shelter in place” and other similar requirements imposed by government authorities, or other actions voluntarily undertaken by individuals and businesses concerned about exposure to COVID-19. The extent to which the COVID-19 pandemic continues to impact our business, operations and financial results depends on numerous evolving factors that we cannot accurately predict, including: the duration and scope of the pandemic; governmental, business and individuals’ actions taken in response to the pandemic and the associated impact on economic activity; the effect on the level of demand for natural gas, NGLs, refined products and/or crude oil; our ability to procure materials and services from third parties that are necessary for the operation of our business; our ability to provide our services, including as a result of travel restrictions on our employees and employees of third parties that we utilize in connection with our services; the potential for key executives or employees to fall ill with COVID-19; and the ability of our customers to pay for our services if their businesses suffer as a result of the pandemic.
In addition, policy disputes between the Organization of Petroleum Exporting Countries (“OPEC”) and Russia in the first quarter of 2020 resulted in Saudi Arabia significantly discounting the price of its crude oil, as well as Saudi Arabia and Russia significantly increasing the amount of crude oil they produce. These actions have led to significant declines in crude oil prices. More specifically, the spot price for West Texas Intermediate (WTI) crude oil, for physical delivery at Cushing, Oklahoma, decreased from $63.27 per barrel on January 6, 2020 to $-(36.98) per barrel on April 20, 2020.
Reduced demand for natural gas, NGLs, refined products and/or crude oil caused by the COVID-19 pandemic and a continuation of low WTI crude oil prices caused by the actions of foreign oil-producing nations may result in the shut-in of production from


58
Table of Contents

U.S. oil and gas wells, which in turn may result in decreased utilization of our midstream services related to crude oil, NGLs, refined products and natural gas. In addition, reduced demand and increased supply of crude oil has resulted in an increase in worldwide crude oil storage inventories, which limits our options for end-markets for the products we transport.
The factors discussed above could have a material adverse effect on our business, results of operations and financial condition. In addition, significant price fluctuations for natural gas, NGLs, refined products and oil commodities could materially affect the value of our inventory, as well as the linefill and tank bottoms that we account for as non-current assets. We may be forced to delay some of our capital projects and our customers, who may be in financial distress, may slow down decision-making, delay planned projects or seek to renegotiate or terminate agreements with us. To the extent our counterparties are successful, we may not be able to obtain new contract terms that are favorable to us or to replace contracts that are terminated. Counterparties may also be forced to file for bankruptcy protection, in which case our existing contracts with those counterparties may be rejected by the bankruptcy court.
Further, the effects of the pandemic and geopolitical developments have caused a decline in the trading price of our common units, which increases our cost of capital. Additional capital may be more difficult for us to obtain or available only on terms less favorable to us. Our inability to fund capital expenditures could have a material impact on our results of operations.
At this time, we cannot estimate the magnitude and duration of potential social, economic and labor instability as a direct result of COVID-19, or of potential industry disruption as a direct result of geopolitical developments in the oil market. Should any of these potential impacts continue for an extended period of time, it will have a negative impact on the demand for our services and an adverse effect on our financial position and results of operations. To the extent these factors adversely affect our business and financial results, they may also have the effect of heightening many of the other risks described in this “Risk Factors” section and the “Risk Factors” section of ourPartnership's Annual Report on Form 10-K for the year ended December 31, 2019 such as those relating to our indebtedness, our need to generate sufficient cash flows to service our indebtedness and our ability to complyfiled with the covenants containedSEC on February 21, 2020 and from the risk factors described in "Part II - Item 1A. Risk Factors" in the agreements that govern our indebtedness.Partnership's Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 filed with the SEC on May 11, 2020.
Income fromLegal or regulatory actions related to the Partnership’s midstream, transportation, terminalling and storageDakota Access Pipeline could cause an interruption to current or future operations, is exposed to risks due to fluctuations in the demand for and price of natural gas, NGLs, refined products and crude oil that are beyond our control.
The prices for natural gas, NGLs, crude oil and refined products reflect market demand that fluctuates with changes in global and United States economic conditions and other factors, including:
•
the level of domestic natural gas, NGL, refined products and oil production;
•
the level of natural gas, NGL, refined products and oil imports and exports, including liquefied natural gas;
•
actions taken by natural gas and oil producing nations;
•
instability or other events affecting natural gas and oil producing nations;
•
the impact of weather, public health crises such as pandemics (including COVID-19), and other events of nature on the demand for natural gas, NGLs, refined products and oil;
•
the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;
•
the price, availability and marketing of competitive fuels;
•
the demand for electricity;
•
activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas and related products;
•
the cost of capital needed to maintain or increase production levels and to construct and expand facilities;
•
the impact of energy conservation and fuel efficiency efforts; and
•
the extent of governmental regulations, taxation, fees and duties.
In the past, the prices of natural gas, NGLs, refined products and oil have been extremely volatile, and we expect this volatility to continue.
Any loss of business from existing customers or our inability to attract new customers due to a decline in demand for natural gas, NGLs, refined products or oilwhich could have a materialan adverse effect on our revenuesbusiness and results of operations.
On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia challenging permits issued by the United States Army Corps of Engineers (“USACE”) permitting Dakota Access, LLC (“Dakota Access”) to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE allowing the pipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively with SRST and CRST, the “Tribes”). Plaintiffs and Defendants filed cross motions for summary judgment. On March 25, 2020, the Court remanded the case back to the USACE for preparation of an Environment Impact Statement. On July 6, 2020, the Court vacated the easement and ordered Dakota Access to be shut down and emptied of oil by August 5, 2020. Dakota Access and USACE have filed notices of appeal with the United States Court of Appeals for the District of Columbia (“Court of Appeals”) with respect to the Court’s ruling related to the preparation of an Environmental Impact Statement and also filed motions for a stay of the Court’s July 6, 2020 Order. On July 14, 2020, the Court of Appeals administratively stayed the Court’s July 6 Order and ordered further briefing with respect to the motion to stay. On August 5, 2020, the Court of Appeals granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil. The Court of Appeals also denied a stay of the March 25 Order and the remaining portion of the July 6 Order vacating the easement. As a result, no court order stops Dakota Access from continuing to operate the Pipeline. The August 5 Order contemplates that the USACE will make a determination under its regulations and procedures whether vacating the easement requires oil to stop flowing. The Order also contemplates further proceedings in the District Court, and it expedites the appeal with briefing to conclude by September 30, 2020.
While we believe that the pending lawsuits are unlikely to adversely affect the continued operation or potential expansion of the pipeline, we cannot assure this outcome. At this time, we cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.
In addition, significant price fluctuations for natural gas, NGL, refined productslawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and oil commodities could materially affect our profitability.results of operations.


5967
Table of Contents

ITEM 6. EXHIBITS
The exhibits listed below are filed or furnished, as indicated, as part of this report:
Exhibit Number
 
Description
3.1
 
Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 of Form S-1, File No. 333-71968, filed October 22, 2001)
3.2
 
Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of August 28, 2015 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, File No. 1-31219, filed September 1, 2015)
3.3
 
Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of April 28, 2017 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, File No. 1-31219, filed April 28, 2017)
3.4
 
Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P. (formerly known as Sunoco Logistics Partners L.P.) (incorporated by reference to Exhibit 3.3 to Registrant’sthe Current Report on Form 8-K, File No. 1-31219, filed on April 28, 2017)
3.5
 
Certificate of Merger of Streamline Merger Sub, LLC, with and into Energy Transfer Partners, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, File No. 1-31219, filed October 19, 2018)
3.6
 
Restated Certificate of Limited Partnership of Energy Transfer Partners GP, L.P. (incorporated by reference to Exhibit 3.14 to the Registrant’sRegistrant’s Form 10-Q for the quarter ended March 31, 2010)
3.7
 
Certificate of Formation of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.13 to the Registrant’sRegistrant’s Form 10-Q for the quarter ended March 31, 2010)
3.8
 
Certificate of Amendment of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.1 to the Registrant’sRegistrant’s Form 10-Q for the quarter ended March 31, 2010)
3.9
 
Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, File No. 1-31219, filed October 19, 2018)
3.10
 
Amendment No. 1, dated as of December 31, 2018, to Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, File No. 1-31219, filed January 4, 2019)
3.11
 
Amendment No. 2, dated as of April 25, 2019, to Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, File No. 1-31219, filed April 25, 2019)
3.12
 
Amendment No. 3, dated as of July 1, 2019, to Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, File No. 1-31219, filed July 2, 2019)
3.13
 
Amendment No. 4 to Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K File No. 1-31219, filed January 22, 2020)
3.14
 Amendment No. 5 to Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K File No. 1-31219, filed May 5, 2020)
3.15
Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P., dated as of April 17, 2007 (incorporated by reference to Exhibit 3.5 to the Registrant’sRegistrant’s Form 10-Q for the quarter ended May 31, 2007)
3.15
3.16
 
Amendment No. 2, dated March 26, 2012, to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P. (incorporated by reference to Exhibit 3.2 to Registrant’sthe Current Report on Form 8-K, File No. 1-31219, filed on March 28, 2012)
3.16
3.17
 
Fourth Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.1 to the Registrant’sCurrent Report on Form 8-K, File No. 1-31219, filed August 10, 2010)
3.17
3.18
 
Amendment No. 1, dated March 26, 2012, to the Fourth Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C., dated as of August 10, 2010 (incorporated by reference to Exhibit 3.3 to Registrant’sthe Current Report on Form 8-K, File No. 1-31219, filed on March 28, 2012)


68
Table of Contents

4.1
 
4.1
Fourth Supplemental Indenture, dated as of January 22, 2020, by and among Energy Transfer Operating, L.P., as issuer, Sunoco Logistics Partners Operations L.P., as guarantor, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2. to the Registrant’s Current Report on Form 8-K, File No. 1-31219, filed January 22, 2020)
4.2
 
Forms of Notes (included in Exhibit 4.1 hereto, incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K, File No. 1-31219, filed January 22, 2020)
18.1*
22.1
 


60
Table of Contents

22.1*
 
Issuers and Guarantors of Registered Securities (incorporated by reference to Exhibit 22.1 to the Registrant’s Form 10-Q for the quarter ended March 31, 2020)
31.1*
 
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*
 
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**
 
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**
 
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101*
 
Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of March 31,June 30, 2020 and December 31, 2019; (ii) our Consolidated Statements of Operations for the three and six months ended March 31,June 30, 2020 and 2019; (iii) our Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended March 31,June 30, 2020 and 2019; (iv) our Consolidated Statements of Partners'Partners’ Capital for the three and six months ended March 31,June 30, 2020 and 2019; (v) our Consolidated Statements of Cash Flows for the threesix months ended March 31,June 30, 2020 and 2019; and (vi) the notes to our Consolidated Financial Statements.
104
 
Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)
*
 
Filed herewith.
**
 
Furnished herewith.


6169
Table of Contents

SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
ENERGY TRANSFER OPERATING, L.P.
 
 
 
 
 
 
By:
Energy Transfer Partners GP, L.P.,
 
 
 
its general partner
 
 
 
 
 
 
By:
Energy Transfer Partners, L.L.C.,
 
 
 
its general partner
 
 
 
 
Date:
May 11,August 6, 2020
By:
/s/ A. Troy Sturrock
 
 
 
A. Troy Sturrock
 
 
 
Senior Vice President, Controller and Principal Accounting Officer
(duly authorized to sign on behalf of the registrant)


6270