

x(Mark One)
☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the ~~Quarterly Period Ended~~ quarterly period ended September 30, ~~2017~~



¨☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

~~Delaware~~

Delaware

27-0005456

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

(Registrant’s telephone number, including area code)


Securities Registered pursuant to Section 12(b) of the Act
Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common Units Representing Limited Partnership Interests	MPLX	New York Stock Exchange

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 x No ¨

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files.) Yes x 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 accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

Accelerated filer

¨☐

Non-accelerated filer

☐

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 x

MPLX LP had ~~407,066,320~~1,001,217,044 common units ~~and 8,307,473 general partner units~~ outstanding atas of October 27, ~~2017.~~

~~Quarter Ended September 30, 2017~~

Unless otherwise stated or the context otherwise ~~requires,~~indicates, all references in this ~~report~~Form 10-Q to “MPLX LP,” “MPLX,” “the Partnership,” “we,” “our,” “us,” or like terms refer to MPLX LP and its subsidiaries, including MPLX Operations LLC (“MPLX Operations”), MPLX Terminal and Storage LLC (“MPLX Terminal and Storage”), MarkWest Energy Partners, L.P. (“MarkWest”), MarkWest Hydrocarbon, L.L.C. (“MarkWest Hydrocarbon”), MarkWest Pioneer, L.L.C. (“MarkWest Pioneer”), MPLX Pipe Line Holdings LLC (“Pipe Line Holdings”), Marathon Pipe Line LLC (“MPL”), Ohio River Pipe Line LLC (“ORPL”), Hardin Street Marine LLC (“HSM”), Hardin Street Transportation LLC (“HST”), Woodhaven Cavern LLC (“WHC”) and MPLX Terminals LLC (“MPLXT”). We have partial ownership interests in a number of joint venture legal entities, including MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”) and its subsidiary Ohio Gathering Company, L.L.C. (“Ohio Gathering”), Ohio Condensate Company, L.L.C. (“Ohio Condensate”), Wirth Gathering Partnership (“Wirth”), MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”), Sherwood Midstream LLC (“Sherwood Midstream”), Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”), MarEn Bakken Company, LLC (“MarEn Bakken”), Johnston County Terminal, LLC (“Johnston Terminal”), Guilford County Terminal Company, LLC (“Guilford Terminal”), LOOP LLC (“LOOP”), LOCAP LLC (“LOCAP”), Illinois Extension Pipeline Company, L.L.C. (“Illinois Extension”) and Explorer Pipeline Company (“Explorer”).consolidated subsidiaries. References to ~~“MPC”~~our sponsor and customer, “MPC,” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership. Unless otherwise specified, references to “Predecessor” refer collectively to HSM’s, HST’s, WHC’s and MPLXT’s related assets, liabilities and results of operations prior to the dates of their respective acquisitions effective January 1, 2014 for HSM, January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT.

Table of Contents

Glossary of Terms

The abbreviations, acronyms and industry technology used in this report are defined as ~~follows.~~follows:


ASC		Accounting Standards Codification
ASU		Accounting Standards Update

Barrel		One stock tank barrel, or 42 U.S. gallons of liquid volume, used in reference to crude oil or other liquid hydrocarbons


~~ATM Program~~		A continuous offering, or at-the-market program, by which the Partnership may offer common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of any offerings
~~Bbl~~		~~Barrels~~
~~Bcf/d~~		~~One billion cubic feet of natural gas per day~~
~~Btu~~	~~One British thermal unit, an energy measurement~~
~~Condensate~~	~~A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions~~
DCF (a non-GAAP financial measure)	Distributable Cash Flow
~~Dth/d~~		~~Dekatherms per day~~
EBITDA (a non-GAAP financial measure)		Earnings Before Interest, Taxes, Depreciation and Amortization
~~EPA~~		~~United States Environmental Protection Agency~~
~~FASB~~
FASB		Financial Accounting Standards Board
~~GAAP~~FCF (a non-GAAP financial measure)		Free Cash Flow
GAAP		Accounting principles generally accepted in the United States of America
~~Gal~~		~~Gallon~~
~~Gal/d~~		~~Gallons per day~~
~~IDR~~		~~Incentive distribution right~~
~~Initial Offering~~G&P		~~Initial public offering on October 31, 2012~~Gathering and Processing segment
~~LIBOR~~L&S		~~London Interbank Offered Rate~~Logistics and Storage segment
~~MarkWest Merger~~mbpd		~~On December 4, 2015, a wholly-owned subsidiary of the Partnership merged with MarkWest Energy Partners, L.P.~~
~~mbpd~~	Thousand barrels per day
~~MMBtu~~
MMBtu		One million British thermal units, an energy measurement
MMcf/d		One million cubic feet of natural gas per day
~~Net operating margin (a non-GAAP financial measure)~~NGL		~~Segment revenues, less segment purchased product costs, less realized derivative gains (losses) related to purchased product costs~~
~~NGL~~	Natural gas liquids, such as ethane, propane, butanes and natural gasoline
~~NYSE~~		~~New York Stock Exchange~~
~~OTC~~		~~Over-the-Counter~~
~~Partnership Agreement~~		~~Third Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of October 31, 2016, as amended~~
~~Predecessor~~		~~Collectively:~~ ~~- HSM’s related assets, liabilities and results of operations prior to the date of its acquisition, March 31, 2016, effective January 1, 2015.~~ - HST’s, WHC’s and MPLXT’s related assets, liabilities and results of operations prior to the date of the acquisition, March 1, 2017, effective January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT.
~~Realized derivative gain/loss~~		~~The gain or loss recognized when a derivative matures or is settled~~
SEC		~~United States~~U.S. Securities and Exchange Commission
~~SMR~~SOFR		~~Steam methane reformer, operated by a third party and located at the Javelina gas processing and fractionation complex in Corpus Christi, Texas~~Secured Overnight Financing Rate
~~Unrealized derivative gain/loss~~VIE		~~The gain or loss recognized on a derivative due to changes in fair value prior to the instrument maturing or settling~~
~~VIE~~	Variable interest entity
~~WTI~~		~~West Texas Intermediate~~

Table of Contents

Part I—Financial Information

Item 1. Financial Statements

MPLX LP

Consolidated Statements of Income (Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions, except per unit data)	2023		2022		2023		2022
Revenues and other income:
Service revenue	$	641	$	627	$	1,881	$	1,758
Service revenue - related parties	1,038		948		2,962		2,801
Service revenue - product related	75		83		214		324
Rental income	61		75		181		268
Rental income - related parties	207		201		612		564
Product sales	478		617		1,274		1,812
Product sales - related parties	51		46		155		142

Sales-type lease revenue	34		28		101		28
Sales-type lease revenue - related parties	129		118		379		343
Income from equity method investments	159		125		438		335
Other income	7		505		28		494
Other income - related parties	32		28		90		82
Total revenues and other income	2,912		3,401		8,315		8,951
Costs and expenses:
Cost of revenues (excludes items below)	367		371		1,023		981
Purchased product costs	474		540		1,234		1,670
Rental cost of sales	20		22		60		101
Rental cost of sales - related parties	8		10		24		44
Purchases - related parties	442		364		1,160		1,034
Depreciation and amortization	301		302		907		925

General and administrative expenses	102		88		280		248

Other taxes	44		30		102		97
Total costs and expenses	1,758		1,727		4,790		5,100
Income from operations	1,154		1,674		3,525		3,851
Related-party interest and other financial costs	—		—		—		5
Interest expense, net of amounts capitalized	223		217		673		627
Other financial costs, net	2		19		28		59
Income before income taxes	929		1,438		2,824		3,160
Provision for income taxes	1		1		2		6
Net income	928		1,437		2,822		3,154
Less: Net income attributable to noncontrolling interests	10		9		28		26
Net income attributable to MPLX LP	918		1,428		2,794		3,128
Less: Series A preferred unitholders interest in net income	25		23		71		65
Less: Series B preferred unitholders interest in net income	—		10		5		31
Limited partners' interest in net income attributable to MPLX LP	$	893	$	1,395	$	2,718	$	3,032
Per Unit Data (See Note 6)
Net income attributable to MPLX LP per limited partner unit:
Common - basic	$	0.89	$	1.36	$	2.70	$	2.97
Common - diluted	$	0.89	$	1.36	$	2.70	$	2.97
Weighted average limited partner units outstanding:
Common - basic	1,001		1,010		1,001		1,012
Common - diluted	1,001		1,011		1,001		1,013

Three Months Ended
September 30, Nine Months Ended
September 30,
(In millions, except per unit data) 2017
2016⁽¹⁾
2017
2016⁽¹⁾
Revenues and other income:
Service revenue $ 299
$ 250
$ 845
$ 712
Service revenue - related parties 276
253
801
676
Rental income 69
77
208
218
Rental income - related parties 70
68
207
172
Product sales 217
157
611
394
Product sales - related parties 2
2
6
8
Gain on sale of assets —
1
1
1
Income (loss) from equity method investments 23
6
29
(72 )
Other income 2
2
5
5
Other income - related parties 22
22
69
67
Total revenues and other income 980
838
2,782
2,181
Costs and expenses:
Cost of revenues (excludes items below) 129
122
381
329
Purchased product costs 170
117
441
310
Rental cost of sales 19
13
44
42
Rental cost of sales - related parties —
—
1
1
Purchases - related parties 114
109
330
286
Depreciation and amortization 164
151
515
438
Impairment expense —
—
—
130
General and administrative expenses 59
56
174
172
Other taxes 14
12
40
37
Total costs and expenses 669
580
1,926
1,745
Income from operations 311
258
856
436
Related party interest and other financial costs 1
—
1
1
Interest expense (net of amounts capitalized of $6 million, $7 million, $24 million and $21 million, respectively) 77
51
217
158
Other financial costs 15
13
40
37
Income before income taxes 218
194
598
240
Provision (benefit) for income taxes 1
—
3
(12 )
Net income 217
194
595
252
Less: Net income attributable to noncontrolling interests 1
2
3
3
Less: Net income attributable to Predecessor —
51
36
149
Net income attributable to MPLX LP 216
141
556
100
Less: Preferred unit distributions 16
16
49
25
Less: General partner’s interest in net income attributable to MPLX LP 86
51
222
136
Limited partners’ interest in net income (loss) attributable to MPLX LP $ 114
$ 74
$ 285
$ (61 )
Per Unit Data (See Note 6)
Net income (loss) attributable to MPLX LP per limited partner unit:
Common - basic $ 0.29
$ 0.22
$ 0.75
$ (0.19 )
Common - diluted 0.29
0.21
0.75
(0.19 )
Weighted average limited partner units outstanding:
Common - basic 394
341
378
324
Common - diluted 395
346
381
324
Cash distributions declared per limited partner common unit $ 0.5875
$ 0.5150
$ 1.6900
$ 1.5300


~~(1)~~	~~Financial information has been retrospectively adjusted for the acquisition of HST, WHC and MPLXT from MPC. See Notes 1 and 3.~~

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

~~MPLX LP~~

~~Consolidated Balance Sheets (Unaudited)~~

(In millions) September 30, 2017 December 31, 2016
Assets
Current assets:
Cash and cash equivalents $ 3
$ 234
Receivables, net 320
299
Receivables - related parties 152
247
Inventories 64
55
Other current assets 32
33
Total current assets 571
868
Equity method investments 3,997
2,471
Property, plant and equipment, net 11,922
11,408
Intangibles, net 463
492
Goodwill 2,245
2,245
Long-term receivables - related parties 18
11
Other noncurrent assets 22
14
Total assets $ 19,238
$ 17,509
Liabilities
Current liabilities:
Accounts payable $ 152
$ 140
Accrued liabilities 202
232
Payables - related parties 317
87
Deferred revenue 3
2
Deferred revenue - related parties 42
38
Accrued property, plant and equipment 183
146
Accrued taxes 44
38
Accrued interest payable 64
53
Other current liabilities 41
27
Total current liabilities 1,048
763
Long-term deferred revenue 34
12
Long-term deferred revenue - related parties 40
19
Long-term debt 6,848
4,422
Deferred income taxes 7
6
Deferred credits and other liabilities 175
177
Total liabilities 8,152
5,399
Commitments and contingencies (see Note 17)

Redeemable preferred units 1,000
1,000
Equity
Common unitholders - public (289 million and 271 million units issued and outstanding) 8,457
8,086
Class B unitholders (0 million and 4 million units issued and outstanding) —
133
Common unitholder - MPC (95 million and 86 million units issued and outstanding) 1,302
1,069
Common unitholder - GP (23 million and 0 units issued and outstanding) 822
—
General partner - MPC (8 million and 7 million units issued and outstanding) (626 ) 1,013
Equity of Predecessor —
791
Accumulated other comprehensive loss (14 ) —
Total MPLX LP partners’ capital 9,941
11,092
Noncontrolling interests 145
18
Total equity 10,086
11,110
Total liabilities, preferred units and equity $ 19,238
$ 17,509

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

Table of Contents

MPLX LP

Consolidated Statements of ~~Cash Flows~~Comprehensive Income (Unaudited)

Nine Months Ended
September 30,
(In millions) 2017
2016⁽¹⁾
(Decrease) increase in cash and cash equivalents
Operating activities:
Net income $ 595
$ 252
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred financing costs 38
34
Depreciation and amortization 515
438
Impairment expense —
130
Deferred income taxes 2
(16 )
Asset retirement expenditures (2 ) (4 )
Gain on disposal of assets (1 ) (1 )
(Income) loss from equity method investments (29 ) 72
Distributions from unconsolidated affiliates 136
111
Changes in:
Current receivables (20 ) (43 )
Inventories (3 ) (4 )
Fair value of derivatives (3 ) 28
Current accounts payable and accrued liabilities 6
64
Receivables from / liabilities to related parties 61
(104 )
All other, net 43
18
Net cash provided by operating activities 1,338
975
Investing activities:
Additions to property, plant and equipment (1,004 ) (943 )
Acquisitions, net of cash acquired (249 ) —
Disposal of assets 4
—
Investments - net related party loans 80
103
Investments in unconsolidated affiliates (690 ) (56 )
Distributions from unconsolidated affiliates - return of capital 24
—
All other, net (2 ) 4
Net cash used in investing activities (1,837 ) (892 )
Financing activities:
Long-term debt - borrowings 2,661
434
- repayments (251 ) (1,312 )
Related party debt - borrowings 829
2,215
- repayments (627 ) (2,223 )
Debt issuance costs (25 ) —
Net proceeds from equity offerings 483
510
Issuance of redeemable preferred units —
984
Distribution to MPC for acquisition (1,931 ) —
Distributions to preferred unitholders (49 ) (9 )
Distributions to unitholders and general partner (800 ) (612 )
Distributions to noncontrolling interests (4 ) (3 )
Contributions from noncontrolling interests 128
4
Consideration payment to Class B unitholders (25 ) (25 )
All other, net (8 ) (2 )
Contribution from MPC —
225
Distributions to MPC from Predecessor (113 ) (104 )
Net cash provided by financing activities 268
82
Net (decrease) increase in cash and cash equivalents (231 ) 165
Cash and cash equivalents at beginning of period 234
43
Cash and cash equivalents at end of period $ 3
$ 208


	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2023		2022		2023		2022
Net income	$	928	$	1,437	$	2,822	$	3,154
Other comprehensive income, net of tax:
Remeasurements of pension and other postretirement benefits related to equity method investments, net of tax	—		—		4		9
Comprehensive income	928		1,437		2,826		3,163
Less comprehensive income attributable to:
Noncontrolling interests	10		9		28		26
Comprehensive income attributable to MPLX LP	$	918	$	1,428	$	2,798	$	3,137


~~(1)~~	~~Financial information has been retrospectively adjusted for the acquisition of HST, WHC and MPLXT from MPC. See Notes 1 and 3.~~

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

Table of Contents

MPLX LP

Consolidated ~~Statements of Equity~~Balance Sheets (Unaudited)


(In millions)	September 30, 2023		December 31, 2022
Assets
Cash and cash equivalents	$	960	$	238

Receivables, net	833		737
Current assets - related parties	759		729
Inventories	154		148

Other current assets	30		53
Total current assets	2,736		1,905
Equity method investments	4,099		4,095
Property, plant and equipment, net	18,620		18,848
Intangibles, net	609		705
Goodwill	7,645		7,645
Right of use assets, net	271		283
Noncurrent assets - related parties	1,174		1,225
Other noncurrent assets	966		959
Total assets	36,120		35,665

Liabilities
Accounts payable	132		224
Accrued liabilities	332		269
Current liabilities - related parties	387		343
Accrued property, plant and equipment	140		128

Long-term debt due within one year	1		988
Accrued interest payable	187		237
Operating lease liabilities	48		46

Other current liabilities	172		166
Total current liabilities	1,399		2,401
Long-term deferred revenue	295		219
Long-term liabilities - related parties	343		338
Long-term debt	20,417		18,808
Deferred income taxes	12		13
Long-term operating lease liabilities	219		230
Other long-term liabilities	119		142
Total liabilities	22,804		22,151
Commitments and contingencies (see Note 15)
Series A preferred units (30 million and 30 million units issued and outstanding)	970		968

Equity
Common unitholders - public (354 million and 354 million units issued and outstanding)	8,533		8,413
Common unitholders - MPC (647 million and 647 million units issued and outstanding)	3,581		3,293
Series B preferred units (0 million and 0.6 million units issued and outstanding)	—		611
Accumulated other comprehensive loss	(4)		(8)
Total MPLX LP partners’ capital	12,110		12,309
Noncontrolling interests	236		237
Total equity	12,346		12,546
Total liabilities, preferred units and equity	$	36,120	$	35,665

Partnership
(In millions)
Common
Unit-holders
Public
Class B Unit-holders Public
Common
Unit-holder
MPC

Common Unit-holder
GP

General
Partner
MPC
Accumulated Other Comprehensive Loss
Non-controlling
Interests

Equity of Predecessor⁽¹⁾
Total
Balance at December 31, 2015 $ 7,691
$ 266
$ 465
$ —
$ 819
$ —
$ 13
$ 692
$ 9,946
Distributions to MPC from Predecessor —
—
—
—
—
—
—
(104 ) (104 )
Contribution from MPC —
—
84
—
141
—
—
—
225
Contribution of MarkWest Hydrocarbon from MPC —
—
—
—
(188 ) —
—
—
(188 )
Distribution of MarkWest Hydrocarbon to MPC —
—
—
—
565
—
—
—
565
Issuance of units under ATM Program 499
—
—
—
11
—
—
—
510
Net (loss) income (51 ) —
(10 ) —
136
—
3
149
227
Allocation of MPC's net investment at acquisition —
—
669
—
(337 ) —
—
(332 ) —
Distributions to unitholders and general partner (378 ) —
(98 ) —
(136 ) —
—
—
(612 )
Distributions to noncontrolling interests —
—
—
—
—
—
(3 ) —
(3 )
Contributions from noncontrolling interests —
—
—
—
—
—
4
—
4
Class B unit conversion 133
(133 ) —
—
—
—
—
—
—
Non-cash contribution from MPC —
—
—
—
—
—
—
334
334
Equity-based compensation 6
—
—
—
—
—
—
—
6
Deferred income tax impact from changes in equity (2 ) —
(13 ) —
(2 ) —
—
—
(17 )
Balance at September 30, 2016 $ 7,898
$ 133
$ 1,097

$ —
$ 1,009

$ —
$ 17
$ 739
$ 10,893

Balance at December 31, 2016 $ 8,086
$ 133
$ 1,069
$ —
$ 1,013
$ —
$ 18
$ 791
$ 11,110
Distributions to MPC from Predecessor —
—
—
—
—
—
—
(113 ) (113 )
Distributions of cash received from Joint-Interest Acquisition entities to MPC —
—
—
—
(13 ) —
—
—
(13 )
Issuance of units under ATM Program 473
—
—
—
10
—
—
—
483
Net income 212
—
68
5
222
—
3
36
546
Contribution from MPC —
—
—
—
—
(14 ) —
689
675
Allocation of MPC's net investment at acquisition —
—
845
824
(266 ) —
—
(1,403 ) —
Distribution to MPC for acquisitions —
—
(537 ) —
(1,394 ) —
—
—
(1,931 )
Distributions to unitholders and general partner (452 ) —
(143 ) (7 ) (198 ) —
—
—
(800 )
Distributions to noncontrolling interests —
—
—
—
—
—
(4 ) —
(4 )
Contributions from noncontrolling interests —
—
—
—
—
—
128
—
128
Class B unit conversion 133
(133 ) —
—
—
—
—
—
—
Equity-based compensation 5
—
—
—
—
—
—
—
5
Balance at September 30, 2017 $ 8,457
$ —
$ 1,302

$ 822
$ (626 ) $ (14 ) $ 145
$ —
$ 10,086


~~(1)~~	~~Financial information has been retrospectively adjusted for the acquisition of HST, WHC and MPLXT from MPC. See Notes 1 and 3.~~

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

Table of Contents

MPLX LP

Consolidated Statements of Cash Flows (Unaudited)


	Nine Months Ended September 30,
(In millions)	2023		2022
Operating activities:
Net income	$	2,822	$	3,154
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred financing costs	42		55
Depreciation and amortization	907		925

Deferred income taxes	(1)		4

Gain on sales-type leases	—		(509)
(Gain)/loss on disposal of assets	(15)		23
Income from equity method investments	(438)		(335)
Distributions from unconsolidated affiliates	526		405
Change in fair value of derivatives	(3)		(62)
Changes in:
Receivables	(31)		(219)
Inventories	(15)		(7)
Accounts payable and accrued liabilities	(56)		49
Assets/liabilities - related parties	89		52

Right of use assets/operating lease liabilities	4		1
Deferred revenue	65		64
All other, net	12		51
Net cash provided by operating activities	3,908		3,651
Investing activities:
Additions to property, plant and equipment	(662)		(535)
Acquisitions, net of cash acquired	—		(28)
Disposal of assets	25		74

Investments in unconsolidated affiliates	(90)		(198)

Distributions from unconsolidated affiliates - return of capital	—		11

Net cash used in investing activities	(727)		(676)
Financing activities:
Long-term debt borrowings	1,589		3,379
Long-term debt repayments	(1,001)		(2,202)
Related party debt borrowings	—		2,824
Related party debt repayments	—		(4,274)
Debt issuance costs	(15)		(29)

Unit repurchases	—		(315)
Redemption of Series B preferred units	(600)		—




Distributions to noncontrolling interests	(30)		(29)
Distributions to Series A preferred unitholders	(69)		(63)
Distributions to Series B preferred unitholders	(21)		(41)
Distributions to unitholders and general partner	(2,329)		(2,144)

Contributions from MPC	20		30

All other, net	(3)		(3)
Net cash used in financing activities	(2,459)		(2,867)
Net change in cash, cash equivalents and restricted cash	722		108
Cash, cash equivalents and restricted cash at beginning of period	238		13
Cash, cash equivalents and restricted cash at end of period	$	960	$	121

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

Table of Contents

MPLX LP

Consolidated Statements of Equity and Series A Preferred Units (Unaudited)


	Partnership
(In millions)	Common Unit-holders Public		Common Unit-holder MPC		Series B Preferred Unit-holders		Accumulated Other Comprehensive Loss		Non-controlling Interests		Total		Series A Preferred Unit-holders
Balance at December 31, 2022	$	8,413	$	3,293	$	611	$	(8)	$	237	$	12,546	$	968
Net income	323		592		5		—		9		929		23

Redemption of Series B preferred units	(2)		(3)		(595)		—		—		(600)		—
Distributions	(275)		(502)		(21)		—		(10)		(808)		(23)
Contributions	—		8		—		—		—		8		—
Other	—		—		—		4		1		5		—
Balance at March 31, 2023	$	8,459	$	3,388	$	—	$	(4)	$	237	$	12,080	$	968
Net income	322		588		—		—		9		919		23

Distributions	(274)		(502)		—		—		(9)		(785)		(23)
Contributions	—		5		—		—		—		5		—
Other	1		1		—		—		—		2		—
Balance at June 30, 2023	$	8,508	$	3,480	$	—	$	(4)	$	237	$	12,221	$	968
Net income	297		596		—		—		10		903		25
Unit repurchases	—		—		—		—		—		—		—
Distributions	(274)		(502)		—		—		(11)		(787)		(23)
Contributions	—		7		—		—		—		7		—
Other	2		—		—		—		—		2		—
Balance at September 30, 2023	$	8,533	$	3,581	$	—	$	(4)	$	236	$	12,346	$	970

	Partnership
	Common Unit-holders Public		Common Unit-holder MPC		Series B Preferred Unit-holders		Accumulated Other Comprehensive Loss		Non-controlling Interests		Total		Series A Preferred Unit-holders
Balance at December 31, 2021	$	8,579	$	2,638	$	611	$	(17)	$	241	$	12,052	$	965
Net income	287		506		11		—		8		812		21
Unit repurchases	(100)		—		—		—		—		(100)		—
Distributions	(260)		(456)		(21)		—		(9)		(746)		(21)
Contributions	—		10		—		—		—		10		—
Other	(1)		—		—		9		—		8		—
Balance at March 31, 2022	$	8,505	$	2,698	$	601	$	(8)	$	240	$	12,036	$	965
Net income	304		540		10		—		9		863		21
Unit repurchases	(35)		—		—		—		—		(35)		—
Distributions	(257)		(457)		—		—		(10)		(724)		(21)
Contributions	—		2		—		—		—		2		—
Other	1		1		—		—		—		2		—
Balance at June 30, 2022	$	8,518	$	2,784	$	611	$	(8)	$	239	$	12,144	$	965
Net income	502		893		10		—		9		1,414		23
Unit repurchases	(196)		—		—		—		—		(196)		—
Distributions	(258)		(456)		(20)		—		(10)		(744)		(21)
Contributions	—		55		—		—		—		55		—
Other	3		—		—		—		—		3		—
Balance at September 30, 2022	$	8,569	$	3,276	$	601	$	(8)	$	238	$	12,676	$	967

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

Table of Contents

Notes to Consolidated Financial Statements (Unaudited)

1. Description of the Business and Basis of Presentation

Description of the Business –

MPLX LP is a diversified, ~~growth-oriented~~large-cap master limited partnership formed by Marathon Petroleum ~~Corporation. MPLX LP~~Corporation that owns and ~~its subsidiaries (collectively, the “Partnership”)~~operates midstream energy infrastructure and logistics assets, and provides fuels distribution services. We are engaged in the gathering, transportation, storage and distribution of crude oil, refined products, other hydrocarbon-based products and renewables; the gathering, processing and transportation of natural gas; and the ~~gathering,~~ transportation, fractionation, storage and marketing of ~~NGLs;~~NGLs. MPLX’s principal executive office is located in Findlay, Ohio. MPLX was formed on March 27, 2012 as a Delaware limited partnership and ~~the transportation, storage and distribution of crude oil and refined petroleum products, principally for our sponsor. References to “MPC” refer collectively to Marathon Petroleum Corporation and~~completed its ~~subsidiaries, other than the Partnership.~~initial public offering on October 31, 2012.

~~The Partnership’s~~MPLX’s business consists of two segments based on the nature of services it offers: Logistics and Storage (“L&S”), which ~~is focused on~~relates primarily to crude oil, refined products, other hydrocarbon-based products and ~~refined petroleum products~~renewables; and Gathering and Processing (“G&P”), which ~~is focused on~~relates primarily to natural gas and NGLs. See Note ~~9 for additional information regarding operations.~~

~~Basis of Presentation~~ – The Partnership’s consolidated financial statements include all majority-owned and controlled subsidiaries. For non-wholly-owned consolidated subsidiaries, the interests owned by third parties have been recorded as ~~Noncontrolling interests~~ in the accompanying Consolidated Balance Sheets. Intercompany investments, accounts and transactions have been eliminated. The Partnership’s investments in which the Partnership exercises significant influence but does not control and does not have a controlling financial interest are accounted for using the equity method. The Partnership’s investments in a VIE in which the Partnership exercises significant influence but does not control and is not the primary beneficiary are also accounted for using the equity method.

Effective March 1, 2017, the Partnership acquired pipeline, storage and terminal businesses that are operated through Hardin Street Transportation LLC (“HST”), Woodhaven Cavern LLC (“WHC”) and MPLX Terminals LLC (“MPLXT”) (collectively with Hardin Street Marine LLC (“HSM”), “Predecessor”) from MPC. The acquisition from MPC was considered a transfer between entities under common control. Accordingly, the Partnership recorded the acquisition from MPC on its Consolidated Balance Sheets at MPC’s historical basis instead of fair value. Transfers of businesses between entities under common control require prior periods to be retrospectively adjusted to furnish comparative information since inception of common control. Therefore, the accompanying consolidated financial statements and related notes of MPLX LP have been retrospectively adjusted to include the historical results of the businesses acquired from MPC prior to the effective dates of the acquisition. See Note 37 for additional information regarding the ~~HST, WHC~~operations and ~~MPLXT acquisition. The accompanying financial statements and related notes present the combined financial position,~~ results of ~~operations, cash flows and equity~~these segments.

Basis of Predecessor on a historical basis. The financial statements of Predecessor have been prepared from the separate records maintained by MPC and may not necessarily be indicative of the conditions or the results of operations that would have existed if Predecessor had been operated as an unaffiliated entity.Presentation

In preparing the Consolidated Statements of Equity, net income attributable to MPLX LP is allocated to preferred unitholders based on a fixed distribution schedule, as discussed in Note 8, and subsequently allocated to the general partner and limited partner unitholders. Distributions, although earned, are not accrued until declared. However, when distributions related to the IDRs are made, earnings equal to the amount of those distributions are first allocated to the general partner before the remaining earnings are allocated to the limited partner unitholders based on their respective ownership percentages. The allocation of net income attributable to MPLX LP for purposes of calculating net income per limited partner unit is described in Note 6.

~~The accompanying~~These interim consolidated financial statements are unaudited; however, in the opinion of ~~the Partnership’s~~MPLX’s management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These interim consolidated financial statements, including the notes, have been prepared in accordance with the rules and regulations of the SEC applicable to interim period financial statements and do not include all of the information and disclosures required by GAAP for complete financial statements. Certain information derived from our audited annual financial statements, prepared in accordance with GAAP, has been condensed or omitted from these interim financial statements.

These interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in ~~the~~our Annual Report on Form 10-K for the year ended December 31, ~~2016, as updated by our Current Report on Form 8-K filed on May 1, 2017.~~2022. The results of operations for the three and nine months ended September 30, ~~2017~~2023 are not necessarily indicative of the results to be expected for the full year.

MPLX’s consolidated financial statements include all majority-owned and controlled subsidiaries. For non-wholly owned consolidated subsidiaries, the interests owned by third parties have been recorded as Noncontrolling interests on the accompanying Consolidated Balance Sheets. Intercompany accounts and transactions have been eliminated. MPLX’s investments in which MPLX exercises significant influence but does not control and does not have a controlling financial interest are accounted for using the equity method. MPLX’s investments in VIEs in which MPLX exercises significant influence but does not control and is not the primary beneficiary are also accounted for using the equity method.

2. Accounting Standards

~~Recently~~Not Yet Adopted

ASU 2023-01, Leases (Topic 842): Common Control Arrangements

In ~~October 2016,~~March 2023, the FASB issued an ~~accounting standards update~~ASU to amend ~~the consolidation guidance issued in February 2015~~certain provisions of ASC 842 that apply to ~~require that a decision maker consider, in the determination of the primary beneficiary, its indirect interest in a VIE held by a~~arrangements between related ~~party that is~~parties under common ~~control on a proportionate basis only.~~control. The change was effective for the financial statements for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. The Partnership was required to apply the standard retrospectively to January 1, 2016, the date on which the Partnership adopted the consolidation guidance issued in February 2015. The Partnership adopted this accounting standards update in the first quarter of 2017 and it did not have an impact on the consolidated financial statements.

~~In March 2016, the FASB issued an accounting standards update on~~ASU amends the accounting for ~~employee share-based payments. This update~~the amortization period of leasehold improvements in common-control leases for all entities and requires certain disclosures when the ~~recognition of income tax effects of awards through~~lease term is shorter than the income statement when awards vest or are settled. It also increases the amount an employer can withhold for tax purposes without triggering liability accounting. Lastly, it allows employers to make a policy election to account for forfeitures as they occur. The changes were effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Under the new guidance, the Partnership will continue estimating forfeiture rates to calculate compensation cost. The Partnership adopted this accounting standards update in the first quarter of 2017 and it did not have a material impact on the consolidated financial statements.

~~Not Yet Adopted~~

In August 2017, the FASB issued an accounting standards update to amend the hedge accounting rules to simplify the application of hedge accounting guidance and better portray the economic results of risk management activities in the financial statements. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirement to separately measure and report hedge ineffectiveness, as well as eases certain hedge effectiveness assessment requirements. The guidance is effective beginning in 2019 with early adoption permitted. The Partnership is in the process of determining the impact of this guidance, including transition elections and required disclosures, on the consolidated financial statements and the timing of adoption.

In May 2017, the FASB issued an accounting standards update to provide guidance about when changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. An entity should account for the effects of a modification unless the fair value, vesting conditions and balance sheet classificationuseful life of the modified award is the same as the original award immediately before the original award is modified. The Partnership will adopt the new standard on a prospective basis beginning on January 1, 2018. The application of this new accounting standard is not expected to have a material impact on the consolidated financial statements.

In February 2017, the FASB issued an accounting standards update addressing the derecognition of nonfinancial assets. The guidance defines in-substance nonfinancial assets, and states that the derecognition of business activities should be evaluated under the consolidation guidance, with limited exceptions related to conveyances of oil and gas mineral rights or contracts with customers. The standard eliminates the previous exclusion for businesses that are in-substance real estate, and eliminates some differences based on whether a transferred set is that of assets or a business and whether the transfer is to a joint venture. The standard must be implemented in conjunction with the implementation of the revenue recognition accounting standards update, which the Partnership will implement January 1, 2018. The Partnership plans to adopt the new standard using the modified retrospective method and does not expect the application of this accounting standards update to have a material impact on the consolidated financial statements.

In January 2017, the FASB issued an accounting standards update which simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test. Under the new guidance, the recognition of an impairment charge is calculated based on the amount by which the carrying amount exceeds the reporting unit’s fair value, which could be different from the amount calculated under the current method using the implied fair value of the goodwill; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. The guidance should be applied on a prospective basis, and is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Partnership is in the process of determining the impact of the accounting standards update on the consolidated financial statements.

In January 2017, the FASB issued an accounting standards update to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of

~~assets or businesses. The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs. The change~~asset. This ASU is effective for fiscal years beginning after December 15, ~~2017, and~~2023, including interim periods within those fiscal years. ~~The guidance will be applied prospectively and early~~Early adoption is ~~permitted for certain transactions. The Partnership is in~~permitted. We do not expect the ~~process of evaluating this accounting standards update and determining whether it will early adopt.~~

In November 2016, the FASB issued an accounting standards update requiring that the statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. The change is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. Retrospective application is required. The application of this ~~accounting standards update will not have a material impact on the Consolidated Statements of Cash Flows.~~

In August 2016, the FASB issued an accounting standards update related to the classification of certain cash flows. The accounting standards update provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees, to reduce diversity in practice. The change is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. Retrospective application is required. The Partnership does not expect application of this accounting standards updateASU to have a material impact on ~~the Consolidated Statements of Cash Flows.~~

In June 2016, the FASB issued an accounting standards update related to the accounting for credit losses on certain financial instruments. The guidance requires that for most financial assets, losses are based on an expected loss approach which includes estimates of losses over the life of exposure that considers historical, current and forecasted information. Expanded disclosures related to the methods used to estimate the losses as well as a specific disaggregation of balances for financial assets are also required. The change is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Partnership does not expect application of this accounting standards update to have a material impact on the consolidated financial statements.

In February 2016, the FASB issued an accounting standards update requiring lessees to record virtually all leases on their balance sheets. The accounting standards update also requires expanded disclosures to help financial statement users better understand the amount, timing and uncertainty of cash flows arising from leases. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. The change will be effective on a modified retrospective basis for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. The Partnership is currently evaluating the impact of this standard on the Partnership’s financial statements and disclosures, internal controls and accounting policies. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population and analyzing the practical expedients in order to determine the best path to implementation. The Partnership does not plan to early adopt the standard. The Partnership believes the impact will be material on theour consolidated financial statements as all operating leases will be recognized as a right of use asset and lease obligation. Based on results of the evaluation process to date, the Partnership also believes the impact on existing processes, controls and information systems may be material.or financial disclosures.

In January 2016, the FASB issued an accounting standards update requiring unconsolidated equity investments, not accounted for under the equity method, to be measured at fair value with changes in fair value recognized in net income. The update also requires the use of the exit price notion when measuring the fair value of financial instruments for disclosure purposes and the separate presentation of financial assets and liabilities by measurement category and form on the balance sheet and accompanying notes. The update eliminates the requirement to disclose the methods and assumptions used in estimating the fair value of financial instruments measured at amortized cost. Lastly, the accounting standards update requires separate presentation in other comprehensive income of the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when electing to measure the liability at fair value in accordance with the fair value option for financial instruments. The changes are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted only for guidance regarding presentation of the liability’s credit risk. The Partnership does not expect application of this accounting standards update to have a material impact on the consolidated financial statements.

The Partnership will adopt the revenue recognition standard during the first quarter of 2018. The Partnership plans to adopt the new standard using the modified retrospective method, which will result in a cumulative effect adjustment as of the date of adoption. By selecting this adoption method, the Partnership will disclose the amount by which each financial statement line item is affected by the standard in the current reporting period after adoption as compared with the guidance that was in effect before adoption.

The Partnership is currently evaluating the impact of the revenue recognition standard on its consolidated financial statements and disclosures, internal controls and accounting policies. This evaluation process includes a phased approach, the first phase of which includes reviewing a sample of contracts and transaction types across segments. This phase was completed as of September 30, 2017.

Based on the results of the first phase assessment, the Partnership has reached conclusions for all material contract types. Revenue recognition patterns will not change for fee-based or percent-of-proceeds contracts. The Partnership does expect certain amounts to be grossed up in revenue and cost of revenues as a result of implementation, specifically related to third-party reimbursements from customers and commodities received as consideration in service agreements, such as keep-whole arrangements. In the third quarter of 2017, the Partnership finalized a conclusion on the valuation of non-cash consideration received in the form of a commodity product, with the valuation being performed on the date the service performance obligation is completed.

The Partnership is in the process of finalizing the second phase of implementation, which includes the calculation of the impact of the new standard on results and the development of new policies, procedures and disclosures related to the application upon adoption. The Partnership believes third-party reimbursements included in the transaction price would have resulted in a gross up in 2016 and 2017 service revenue and cost of revenues between $300 million and $350 million annually, with no impact to net income. The Partnership will provide a summary of the total ASC 606 impact in the Annual Report on Form 10-K for the year ended December 31, 2017.

3. ~~Acquisitions~~Investments and Noncontrolling Interests

~~Joint-Interest Acquisition~~

On September 1, 2017, the Partnership entered into a Membership Interests and Shares Contributions Agreement (the “September 2017 Contributions Agreement”) with MPLX GP LLC (“MPLX GP”), MPLX Logistics Holdings LLC (“MPLX Logistics”), MPLX Holdings Inc. (“MPLX Holdings”) and MPC Investment LLC (“MPC Investment”), each a wholly-owned subsidiary of MPC, whereby the Partnership agreed to acquire certain ownership interests in joint venture entities indirectly held by MPC. Pursuant to the September 2017 Contributions Agreement, MPC Investment agreed to contribute: all of the membership interests of Lincoln Pipeline LLC, which holds a 35 percent interest in Illinois Extension Pipeline Company, L.L.C. (“Illinois Extension”); all of the membership interests of MPL Louisiana Holdings LLC, which holds a 40.7 percent interest in LOOP LLC (“LOOP”); a 58.52 percent interest in LOCAP LLC (“LOCAP”); and a 24.51 percent interest in Explorer Pipeline Company (“Explorer”), through a series of intercompany contributions to the Partnership for an agreed upon purchase price of approximately $420 million in cash and equity consideration valued at approximately $630 million for total consideration of $1.05 billion (collectively, the “Joint-Interest Acquisition”). The number of common units representing the equity consideration was then determined by dividing the contribution amount by the simple average of the ten day trading volume weighted average NYSE price of a common unit for the ten trading days ending at market close on August 31, 2017. The fair value of the common and general partner units issued was approximately $653 million based on the closing common unit price as of September 1, 2017, as recorded on the Consolidated Statements of Equity, for a total purchase price of $1.07 billion. The equity issued consisted of: (i) 13,719,017 common units to MPLX GP, (ii) 3,350,893 common units to MPLX Logistics and (iii) 1,441,224 common units to MPLX Holdings. The Partnership also issued 377,778 general partner units to MPLX GP in order to maintain its two percent general partner interest (“GP Interest”) in the Partnership.

Illinois Extension operates the 168-mile, 24-inch diameter Southern Access Extension (“SAX”) crude oil pipeline from Flanagan, Illinois to Patoka, Illinois, as well as additional tankage and two pump stations. LOOP owns and operates midstream crude oil infrastructure, including a deep water oil port offshore of Louisiana, pipelines and onshore storage facilities. LOOP also manages the operations of LOCAP, an affiliate pipeline system. LOCAP owns and operates a crude oil pipeline and tank facility in St. James, Louisiana, that distributes oil received from LOOP’s storage facilities and other connecting pipelines to nearby refineries and into the mid-continent region of the United States. Explorer owns and operates an approximate 1,830-mile common carrier pipeline that primarily transports gasoline, diesel, diluent and jet fuel from the Gulf Coast refining complex to the Midwest United States. The Partnership accounts for the Joint-Interest Acquisition entities as equity method investments within its L&S segment.

As a transfer between entities under common control, the Partnership recorded the Joint-Interest Acquisition on its Consolidated Balance Sheets at MPC’s historical basis, which included accumulated other comprehensive loss. The Partnership recognizes an accumulated other comprehensive loss on its Consolidated Balance Sheets relating to pension and other post-retirement benefits provided by the LOOP and Explorer joint-interests to their employees. MPLX LP is not a sponsor of these benefit plans. There were no changes to ~~Accumulated other comprehensive loss~~ ~~during the period September 1, 2017 through September 30, 2017.~~

Distributions of cash received from the entities and interests acquired in the Joint-Interest Acquisition related to periods prior to the acquisition will be prorated on a daily basis with MPLX LP retaining the portion of distributions beginning on the closing date. All amounts distributed to MPLX LP related to periods before the acquisition will be paid to MPC. Additionally, MPLX LP has agreed to pay MPC for any distributions of cash from LOOP related to the sale of LOOP’s excess crude oil inventory. Because the future distributions or payments cannot be reasonably quantified, a liability was not recorded in connection with the acquisition. MPLX LP subsequently received distributions related to the third quarter 2017 and recorded a liability to MPC and a corresponding decrease to the general partner’s equity for $13 million, as shown on the Consolidated Statements of Equity.

There is no income associated with the Joint-Interest Acquisition included in the Consolidated Statements of Income since the September 1, 2017 acquisition date, as the Partnership accounts for these investments in arrears using the most recently available information. The Partnership’s investment balance at September 30, 2017 related to the acquired interests is approximately $645 million and reported under the caption ~~Equity method investments~~ on the Consolidated Balance Sheets. MPC agreed to waive approximately two-thirds of the third quarter 2017 distributions on the common units issued in connection with the Joint-Interest Acquisition. As a result of this waiver, MPC did not receive approximately two-thirds of the distributions or IDRs that would have otherwise accrued on such common units with respect to the third quarter 2017 distributions. The value of these waived distributions was $10 million.

~~Acquisition of Hardin Street Transportation LLC, Woodhaven Cavern LLC and MPLX Terminals LLC~~

MPC contributed the assets of HST, WHC and MPLXT to newly created and wholly-owned subsidiaries and entered into commercial agreements related to services provided by these new entities to MPC on January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT. Pursuant to a Membership Interests Contributions Agreement entered into on March 1, 2017 by the Partnership with MPLX GP, MPLX Logistics, MPLX Holdings and MPC Investment, each a wholly-owned subsidiary of MPC, MPC Investment agreed to contribute the outstanding membership interests in HST, WHC and MPLXT through a series of intercompany contributions to the Partnership for approximately $1.5 billion in cash and equity consideration valued at approximately $504 million (the “Transaction”). The number of common units representing the equity consideration was determined by dividing the contribution amount by the simple average of the ten day trailing volume weighted average NYSE price of a common unit for the ten trading days ending at market close on February 28, 2017. The fair value of the common and general partner units issued was approximately $503 million, as recorded on the Consolidated Statements of Equity, and consisted of (i) 9,197,900 common units to MPLX GP, (ii) 2,630,427 common units to MPLX Logistics and (iii) 1,132,049 common units to MPLX Holdings. The Partnership also issued 264,497 general partner units to MPLX GP in order to maintain its two percent GP Interest in the Partnership. MPC agreed to waive two-thirds of the first quarter 2017 distributions on the common units issued in connection with the Transaction. As a result of this waiver, MPC did not receive two-thirds of the general partner distributions or IDRs that would have otherwise accrued on such common units with respect to the first quarter 2017 distributions. The value of these waived distributions was $6 million.

HST owns and operates various private crude oil and refined product pipeline systems and associated storage tanks. As of the acquisition date, these pipeline systems consisted of 174 miles of crude oil pipelines and 430 miles of refined products pipelines. WHC owns and operates nine butane and propane storage caverns located in Michigan with approximately 1.8 million barrels of NGL storage capacity. As of the acquisition date, MPLXT owned and operated 59 terminals for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products. Additionally, MPLXT operated one leased terminal and had partial ownership interest in two terminals. Collectively, these 62 terminals have a combined shell capacity of approximately 23.6 million barrels. The terminal facilities are located primarily in the Midwest, Gulf Coast and Southeast regions of the United States. The Partnership accounts for these businesses within its L&S segment.

The Partnership retrospectively adjusted the historical financial results for all periods to give effect to the acquisition of HST and WHC effective January 1, 2015, and the acquisition of MPLXT effective April 1, 2016, as required for transactions between entities under common control. Prior to these dates, these entities were not considered businesses and, therefore, there are no financial results from which to recast.

The following tables present the Partnership’s previously reported unaudited Consolidated Statements of Income for the three and nine months ended September 30, 2016, retrospectively adjusted for the acquisition of HST, WHC and MPLXT:

Three Months Ended September 30, 2016
(In millions, except per unit data) MPLX LP (Previously Reported) HST/WHC MPLXT
Eliminations⁽¹⁾
MPLX LP (Currently Reported)
Revenues and other income:
Service revenue $ 250
$ —
$ —
$ —
$ 250
Service revenue - related parties 153
28
72
—
253
Rental income 77
—
—
—
77
Rental income - related parties 29
13
26
—
68
Product sales 157
—
—
—
157
Product sales - related parties 2
—
—
—
2
Income from equity method investments 6
—
—
—
6
Gain on sale of assets 1
—
—
—
1
Other income 2
—
—
—
2
Other income - related parties 26
—
—
(4 ) 22
Total revenues and other income 703
41
98
(4 ) 838
Costs and expenses:
Cost of revenues (excludes items below) 90
10
22
—
122
Purchased product costs 117
—
—
—
117
Rental cost of sales 11
2
—
—
13
Rental cost of sales - related parties —
1
—
(1 ) —
Purchases - related parties 84
4
24
(3 ) 109
Depreciation and amortization 138
4
9
—
151
General and administrative expenses 46
2
8
—
56
Other taxes 10
—
2
—
12
Total costs and expenses 496
23
65
(4 ) 580
Income from operations 207
18
33
—
258
Interest expense (net of amounts capitalized) 51
—
—
—
51
Other financial costs 13
—
—
—
13
Income before income taxes 143
18
33
—
194
Net income 143
18
33
—
194
Less: Net income attributable to noncontrolling interests 2
—
—
—
2
Less: Net income attributable to Predecessor —
18
33
—
51
Net income attributable to MPLX LP 141
—
—
—
141
Less: Preferred unit distributions 16
—
—
—
16
Less: General partner’s interest in net income attributable to MPLX LP 51
—
—
—
51
Limited partners’ interest in net income attributable to MPLX LP $ 74
$ —
$ —
$ —
$ 74

Nine Months Ended September 30, 2016
(In millions, except per unit data) MPLX LP (Previously Reported) HST/WHC MPLXT
Eliminations⁽¹⁾
MPLX LP (Currently Reported)
Revenues and other income:
Service revenue $ 712
$ —
$ —
$ —
$ 712
Service revenue - related parties 448
82
146
—
676
Rental income 218
—
—
—
218
Rental income - related parties 84
36
52
—
172
Product sales 394
—
—
—
394
Product sales - related parties 8
—
—
—
8
Loss from equity method investments (72 ) —
—
—
(72 )
Gain on sale of assets 1
—
—
—
1
Other income 5
—
—
—
5
Other income - related parties 78
—
—
(11 ) 67
Total revenues and other income 1,876
118
198
(11 ) 2,181
Costs and expenses:
Cost of revenues (excludes items below) 263
24
42
—
329
Purchased product costs 310
—
—
—
310
Rental cost of sales 39
3
—
—
42
Rental cost of sales - related parties —
2
—
(1 ) 1
Purchases - related parties 238
13
45
(10 ) 286
Depreciation and amortization 407
12
19
—
438
Impairment expense 130
—
—
—
130
General and administrative expenses 147
5
20
—
172
Other taxes 32
2
3
—
37
Total costs and expenses 1,566
61
129
(11 ) 1,745
Income from operations 310
57
69
—
436
Related party interest and other financial income 1
—
—
—
1
Interest expense (net of amounts capitalized) 158
—
—
—
158
Other financial costs 37
—
—
—
37
Income before income taxes 114
57
69
—
240
Benefit for income taxes (12 ) —
—
—
(12 )
Net income 126
57
69
—
252
Less: Net income attributable to noncontrolling interests 3
—
—
—
3
Less: Net income attributable to Predecessor 23
57
69
—
149
Net income attributable to MPLX LP 100
—
—
—
100
Less: Preferred unit distributions 25
—
—
—
25
Less: General partner’s interest in net income attributable to MPLX LP 136
—
—
—
136
Limited partners’ interest in net loss attributable to MPLX LP $ (61 )
$ —

$ —

$ —

$ (61 )

The following table presents ~~the Partnership’s previously reported unaudited Consolidated Statements of Cash Flows, retrospectively adjusted for the acquisition of HST, WHC and MPLXT:~~

Nine Months Ended September 30, 2016
(In millions) MPLX LP (Previously Reported) HST/WHC MPLXT MPLX LP (Currently Reported)
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income $ 126
$ 57
$ 69
$ 252
Adjustments to reconcile net income to net cash provided by (used in) operating activities:

Amortization of deferred financing costs 34
—
—
34
Depreciation and amortization 407
12
19
438
Impairment expense 130
—
—
130
Deferred income taxes (16 ) —
—
(16 )
Asset retirement expenditures (3 ) (1 ) —
(4 )
Gain on disposal of assets (1 ) —
—
(1 )
Loss from equity method investments 72
—
—
72
Distributions from unconsolidated affiliates 111
—
—
111
Changes in:
Current receivables (44 ) 1
—
(43 )
Inventories (4 ) —
—
(4 )
Fair value of derivatives 28
—
—
28
Current accounts payable and accrued liabilities 59
(1 ) 6
64
Receivables from / liabilities to related parties 15
3
(122 ) (104 )
All other, net 18
2
(2 ) 18
Net cash provided by (used in) operating activities 932
73
(30 ) 975
Investing activities:
Additions to property, plant and equipment (874 ) (36 ) (33 ) (943 )
Investments - net related party loans 77
(37 ) 63
103
Investments in unconsolidated affiliates (56 ) —
—
(56 )
All other, net 4
—
—
4
Net cash (used in) provided by investing activities (849 ) (73 ) 30
(892 )
Financing activities:
Long-term debt - borrowings 434
—
—
434
- repayments (1,312 ) —
—
(1,312 )
Related party debt - borrowings 2,215
—
—
2,215
- repayments (2,223 ) —
—
(2,223 )
Net proceeds from equity offerings 510
—
—
510
Issuance of redeemable preferred units 984
—
—
984
Distributions to preferred unitholders (9 ) —
—
(9 )
Distributions to unitholders and general partner (612 ) —
—
(612 )
Distributions to noncontrolling interests (3 ) —
—
(3 )
Contributions from noncontrolling interests 4
—
—
4
Consideration payment to Class B unitholders (25 ) —
—
(25 )
All other, net (2 ) —
—
(2 )
Contribution from MPC 225
—
—
225
Distributions to MPC from Predecessor (104 ) —
—
(104 )
Net cash provided by financing activities 82
—
—
82
Net increase in cash and cash equivalents 165
—
—
165
Cash and cash equivalents at beginning of period 43
—
—
43
Cash and cash equivalents at end of period $ 208
$ —
$ —
$ 208

~~Acquisition of Ozark Pipeline~~

On March 1, 2017, the Partnership acquired the Ozark pipeline from Enbridge Pipelines (Ozark) LLC for approximately $219 million, including purchase price adjustments made in the second quarter of 2017. Based on the final fair value estimates of assets acquired and liabilities assumedMPLX’s equity method investments at the ~~acquisition date, the purchase price was primarily allocated to property, plant and equipment.~~dates indicated:


		Ownership as of	Carrying value at
		September 30,	September 30,		December 31,
(In millions, except ownership percentages)	VIE	2023	2023		2022
L&S
Andeavor Logistics Rio Pipeline LLC	X	67%	$	174	$	177
Illinois Extension Pipeline Company, L.L.C.		35%	238		236
LOOP LLC		41%	301		287
MarEn Bakken Company LLC(1)		25%	453		475
Minnesota Pipe Line Company, LLC		17%	174		178
Whistler Pipeline LLC		38%	212		211
Other(2)	X		298		269
Total L&S			1,850		1,833
G&P
Centrahoma Processing LLC		40%	117		131
MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C	X	67%	339		335
MarkWest Torñado GP, L.L.C.	X	60%	310		306
MarkWest Utica EMG, L.L.C.	X	58%	684		669
Rendezvous Gas Services, L.L.C.	X	78%	130		137
Sherwood Midstream Holdings LLC	X	51%	116		125
Sherwood Midstream LLC	X	50%	507		512
Other(2)	X		46		47
Total G&P			2,249		2,262
Total			$	4,099	$	4,095

(1) The ~~Ozark pipeline is a 433-mile, 22-inch crude oil pipeline originating~~investment in ~~Cushing, Oklahoma, and terminating in Wood River, Illinois, capable of transporting approximately 230 mbpd. The Partnership accounts for the Ozark pipeline within its L&S segment.~~

~~The amounts of revenue and income from operations associated with the acquisition included in the Consolidated Statements of Income, since the March 1, 2017 acquisition date, are as follows:~~

(In millions) Three Months Ended September 30, 2017 Seven Months Ended September 30, 2017
Revenues and other income $ 19
$ 45
Income from operations 6
17

~~Assuming the acquisition of the Ozark pipeline had occurred on January 1, 2016, the consolidated pro forma results would not have been materially different from reported results.~~

~~On February 15, 2017, the Partnership closed on a joint venture,~~ MarEn Bakken Company LLC ~~(“MarEn Bakken”), with Enbridge Energy Partners L.P. in which MPLX LP acquired a partial,~~includes our 9.19 percent indirect interest in a joint venture (“Dakota Access”) that owns and operates the Dakota Access Pipeline and Energy Transfer Crude Oil ~~Company~~ Pipeline projects, collectively referred to as the Bakken Pipeline system from Energy Transfer Partners, L.P. and Sunoco Logistics Partners, L.P. The Partnership contributed $500 million of the $2.0 billion purchase price paid by MarEn Bakken to acquire a 36.75 percent indirect interest in the Bakken Pipeline system. The Partnership holds, through a subsidiary, a 25 percent interest in MarEn Bakken, which equates to a 9.1875 percent indirect interest in the Bakken Pipeline system.or DAPL.

The Partnership accounts for its investment in MarEn Bakken as an equity method investment and bases the equity method accounting for this joint venture in arrears using the most recently available information. The Partnership’s investment balance at September 30, 2017 is approximately $520 million and reported under the caption ~~Equity method~~(2) Some investments on the Consolidated Balance Sheets. In connection with the Partnership’s acquisition of a partial, indirect equity interest in the Bakken Pipeline system, MPC agreed to waive its right to receive incentive distributions of $1.6 million per quarter for twelve consecutive quarters, beginning with distributions declared in the first quarter of 2017 and paid to MPC in the second quarter of 2017, which was prorated to $0.8 million from the acquisition date.

~~Acquisition of Hardin Street Marine LLC~~

On March 14, 2016, the Partnership entered into a Membership Interests Contribution Agreement (the “Contribution Agreement”) with MPLX GP, MPLX Logistics and MPC Investment, each a wholly-owned subsidiary of MPC, related to the acquisition of HSM, MPC’s inland marine business, from MPC. Pursuant to the Contribution Agreement, the transaction was valued at $600 million consisting of a fixed number of common units and general partner units of 22,534,002 and 459,878, respectively. The general partner units maintain MPC’s two percent GP Interest in the Partnership. The acquisition closed on March 31, 2016 and the fair value of the common units and general partner units issued was $669 million and $14 million, respectively, as recorded on the Consolidated Statements of Equity. MPC agreed to waive distributions in the first quarter of 2016 on common units issued in connection with this transaction. As a result of this waiver, MPC did not receive general partner distributions or IDRs that would included within Other have ~~otherwise accrued on such common units with respect to the first quarter 2016 distributions. The value of these waived distributions was $15 million.~~

The inland marine business, comprised of 18 tow boats and 219 owned and leased barges as of the acquisition date, which transport light products, heavy oils, crude oil, renewable fuels, chemicals and feedstocks in the Midwest and Gulf Coast regions of the United States, accounted for nearly 60 percent of the total volumes MPC shipped by inland marine vessels as of March 31, 2016. The Partnership accounts for HSM within its L&S segment.

~~4. Investments and Noncontrolling Interests~~

~~Summarized financial information for the Partnership’s equity method investments for the nine months ended September 30, 2017 and 2016 is as follows:~~

Nine Months Ended September 30, 2017
(In millions) MarkWest Utica EMG Other VIEs Non-VIEs Total
Revenues and other income $ 137
$ 49
$ 178
$ 364
Costs and expenses 72
29
115
216
Income from operations 65
20
63
148
Net income 65
19
28
112
Income from equity method investments⁽¹⁾
6
7
16
29

Nine Months Ended September 30, 2016
(In millions) MarkWest Utica EMG
Other VIEs⁽²⁾
Non-VIEs Total
Revenues and other income $ 165
$ 13
$ 108
$ 286
Costs and expenses 70
107
80
257
Income (loss) from operations 95
(94 ) 28
29
Net income (loss) 94
(94 ) 28
28
Income (loss) from equity method investments⁽¹⁾
10
(88 ) 6
(72 )

~~Income (loss) from equity method investments~~ ~~includes the impact of any basis differential amortization or accretion.~~

~~Summarized balance sheet information for the Partnership’s equity method investments as of September 30, 2017 and December 31, 2016 is as follows:~~

September 30, 2017
(In millions)
MarkWest Utica EMG⁽¹⁾
Other VIEs Non-VIEs Total
Current assets $ 72
$ 47
$ 379
$ 498
Noncurrent assets 2,092
878
4,614
7,584
Current liabilities 37
55
492
584
Noncurrent liabilities 2
12
562
576

December 31, 2016
(In millions)
MarkWest Utica EMG⁽¹⁾
Other VIEs Non-VIEs Total
Current assets $ 45
$ 2
$ 40
$ 87
Noncurrent assets 2,173
132
390
2,695
Current liabilities 30
4
26
60
Noncurrent liabilities 2
13
—
15

As of September 30, 2017 and December 31, 2016, the carrying value of the Partnership’s equity method investments exceeded the underlying net assets of its investees by $1.1 billion. This basis difference is being amortized or accreted into net income over the remaining estimated useful lives of the underlying net assets, except for $459 million of excess related to goodwill.

~~MarkWest Utica EMG~~

Effective January 1, 2012, MarkWest Utica Operating Company, LLC (“Utica Operating”), a wholly-owned and consolidated subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”), and EMG Utica, LLC (“EMG Utica” and together with Utica Operating, the “Members”) executed agreements to form a joint venture, MarkWest Utica EMG, to develop significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure in eastern Ohio. The related limited liability company agreement hasalso been amended from time to time (the limited liability company agreement currently in effect is referred to as the “Amended LLC Agreement”). The aggregate funding commitment of EMG Utica was $950 million. Thereafter, Utica Operating was required to fund, as needed, 100 percent of future capital for MarkWest Utica EMG until the aggregate capital that had been contributed by the Members reached $2.0 billion, which occurred prior to the MarkWest Merger. Until such time as the investment balances of Utica Operating and EMG Utica are in the ratio of 70 percent and 30 percent, respectively (such time being referred to as the “Second Equalization Date”), EMG Utica will have the right, but not the obligation, to fund up to 10 percent of each capital call for MarkWest Utica EMG, and Utica Operating will be required to fund all remaining capital not elected to be funded by EMG Utica. After the Second Equalization Date, Utica Operating and EMG Utica will have the right, but not the obligation, to fund their pro rata portion (based on their respective investment balances) of any additional required capital and may also fund additional capital that the other party elects not to fund. As of September 30, 2017, EMG Utica has contributed approximately $1.2 billion and Utica Operating has contributed approximately $1.5 billion to MarkWest Utica EMG.

Under the Amended LLC Agreement, prior to December 31, 2016, EMG Utica’s investment balance was increased by a quarterly special non-cash allocation of income (“Preference Amount”), calculated based upon the amount of capital contributed by EMG Utica in excess of $500 million. After December 31, 2016, no Preference Amount will accrue to EMG Utica’s investment balance. EMG Utica received a Preference Amount totaling approximately $4 million and $12 million for the three and nine months ended September 30, 2016, respectively.

Under the Amended LLC Agreement, after December 31, 2016, cash generated by MarkWest Utica EMG that is available for distribution will be allocated to the Members in proportion to their respective investment balances. As of September 30, 2017, Utica Operating’s investment balance in MarkWest Utica EMG was approximately 56 percent.

~~MarkWest Utica EMG is~~ deemed to be ~~a VIE. Utica Operating is not~~VIEs.

For those entities that have been deemed to be VIEs, neither MPLX nor any of its subsidiaries have been deemed to be the primary beneficiary due to ~~EMG Utica’s~~ voting rights on significant matters. ~~The Partnership’s investment~~While we have the ability to exercise influence through participation in ~~MarkWest Utica EMG’s,~~the management committees which ~~was $2.2 billion at September 30, 2017~~make all significant decisions, we have equal influence over each committee as a joint interest partner and ~~December 31, 2016, is reported under~~all significant decisions require the ~~caption~~ ~~Equity~~consent of the other investors without regard to economic interest. As such, we have determined that these entities should not be consolidated and applied the equity method of accounting with respect to our investments ~~on the Consolidated Balance Sheets. The Partnership’s~~ in each entity.

MPLX’s maximum exposure to loss as a result of its involvement with ~~MarkWest Utica EMG~~equity method investments includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. ~~The Partnership~~MPLX did not provide any financial support to MarkWest Utica EMG that it was not contractually obligated to provide during the three and nine months ended September 30, 2017 and 2016, respectively. The Partnership receives management fee revenue for engineering and construction and administrative services for operating MarkWest Utica EMG, and is also reimbursed for personnel services (“Operational Service revenue”). Operational Service revenue is reported as ~~Other income-related parties~~ in the Consolidated Statements of Income. The amount of Operational Service revenue related to MarkWest Utica EMG for the three and nine months ended September 30, 2017, totaled $5 million and $13 million, respectively. The amount of Operational Service revenue related to MarkWest Utica EMG for the three and nine months ended September 30, 2016, totaled approximately $5 million and $12 million, respectively.

Ohio Gathering is a subsidiary of MarkWest Utica EMG and is engaged in providing natural gas gathering services in the Utica Shale in eastern Ohio. Ohio Gathering is a joint venture between MarkWest Utica EMG and Summit Midstream Partners, LLC. As of September 30, 2017, the Partnership has an approximate 34 percent indirect ownership interest in Ohio Gathering. As Ohio Gathering is a subsidiary of MarkWest Utica EMG, which is accounted for as an equity method investment, the Partnership reports its portion of Ohio Gathering’s net assets as a component of its investment in MarkWest Utica EMG. The Partnership receives Operational Service revenue for operating Ohio Gathering which is reported as ~~Other income-related parties~~ in the Consolidated Statements of Income. The amount of Operational Service revenue related to Ohio Gathering for the three and nine months ended September 30, 2017, totaled $4 million and $12 million, respectively. The amount of Operational Service revenue related to Ohio Gathering for the three and nine months ended September 30, 2016, totaled approximately $5 million and $12 million, respectively.

~~Sherwood Midstream~~

Effective January 1, 2017, MarkWest Liberty Midstream & Resources, L.L.C. (“MarkWest Liberty Midstream”), a wholly-owned and consolidated subsidiary of MarkWest, and Antero Midstream Partners, LP (“Antero Midstream”) formed a joint venture, Sherwood Midstream LLC (“Sherwood Midstream”), to support Antero Resources Corporation’s development in the Marcellus Shale. MarkWest Liberty Midstream has a 50 percent ownership interest in Sherwood Midstream. Pursuant to the terms of the related limited liability company agreement (the “LLC Agreement”), MarkWest Liberty Midstream contributed assets then under construction with a fair value of approximately $134 million and cash of approximately $20 million. Antero Midstream made an initial capital contribution of approximately $154 million.

Also effective January 1, 2017, MarkWest Liberty Midstream converted all of its ownership interests in MarkWest Ohio Fractionation Company, L.L.C. (“Ohio Fractionation”), a previously wholly-owned subsidiary, to Class A Interests and amended its LLC Agreement to create Class B-3 Interests, which were sold to Sherwood Midstream for $126 million in cash. The Class B-3 Interests provide Sherwood Midstream with the right to fractionation revenue and the obligation to pay expenses related to 20 mbpd of capacity in the Hopedale 3 fractionator. Sherwood Midstream accounts for its investment in Ohio Fractionation, which is a VIE, as an equity method investment as Sherwood Midstream does not control Ohio Fractionation. MarkWest Liberty Midstream has been deemed to be the primary beneficiary of Ohio Fractionation because it has control over the decisions that could significantly impact its financial performance, and as a result, consolidates Ohio Fractionation. The carrying amounts of assets and liabilities included in the Partnership’s Consolidated Balance Sheets pertaining to Ohio Fractionation at September 30, 2017, were current assets of $51 million, non-current assets of $406 million and current liabilities of $26 million. The creditors of Ohio Fractionation do not have recourse to MPLX LP’s general credit through guarantees or other financial arrangements. The assets of Ohio Fractionation are the property of Ohio Fractionation and cannot be used to satisfy the obligations of MPLX LP. Sherwood Midstream’s interests are reflected in ~~Net income attributable to noncontrolling interests~~ ~~in the Consolidated Statements of Income and~~ ~~Noncontrolling interests~~ ~~in the Consolidated Balance Sheets.~~

~~Under the LLC Agreement, cash generated by Sherwood Midstream that is available for distribution will be allocated to the members in proportion to their respective investment balances.~~

Sherwood Midstream is deemed to be a VIE. MarkWest Liberty Midstream is not deemed to be the primary beneficiary, due to Antero Midstream’s voting rights on significant matters. The Partnership’s investment in Sherwood Midstream, which was approximately $220 million at September 30, 2017, is reported under the caption ~~Equity method~~ investments on the Consolidated Balance Sheets. The Partnership’s maximum exposure to loss as a result of its involvement with Sherwood Midstream includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. The Partnership did not provide any financial support to Sherwood Midstream that it was not contractually obligated to provide during the nine months ended September 30, ~~2017. The Partnership receives Operational Service revenue~~2023. See Note 15 for ~~operating Sherwood Midstream. The amount of Operational Service revenue~~information on our Guarantees related to ~~Sherwood Midstream for the three and nine months ended September 30, 2017, totaled approximately $2 million and $6 million, respectively, and is reported as~~ ~~Other income-related parties~~ ~~in the Consolidated Statements~~indebtedness of ~~Income.~~

~~Sherwood Midstream Holdings~~

Effective January 1, 2017, MarkWest Liberty Midstream and Sherwood Midstream formed a joint venture, Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”), for the purpose of owning, operating and maintaining all of the shared assets that support the operations of the gas plants and other assets owned by Sherwood Midstream and the gas plants and deethanization facilities owned by MarkWest Liberty Midstream. MarkWest Liberty Midstream initially contributed certain real property, equipment and facilities with a fair value of approximately $209 million to Sherwood Midstream Holdings in exchange for a 79 percent initial ownership interest. Sherwood Midstream contributed cash of approximately $44 million to Sherwood Midstream Holdings in exchange for a 21 percent ownership interest. During the second quarter ended June 30, 2017, true-ups to the initial contributions were finalized. MarkWest Liberty Midstream contributed certain additional real property, equipment and facilities with a fair value of approximately $10 million to Sherwood Midstream Holdings and Sherwood Midstream contributed cash of approximately $4 million to Sherwood Midstream Holdings. Collectively, the real property, equipment, facilities and cash initially contributed, or that may be subsequently constructed by or contributed, to Sherwood Midstream Holdings are referred to as the “Shared Assets.” The net book value of the contributed assets was approximately $203 million. The contribution was determined to be an in-substance sale of real estate. As such, the Partnership only recognized a gain for the portion attributable to Antero Midstream’s indirect interest of approximately $2 million, included in ~~Gain on sale of assets~~ in the Consolidated Statements of Income. MarkWest Liberty Midstream’s portion of the gain attributable to its direct and indirect interests of approximately $14 million is included in its investment in Sherwood

~~Midstream Holdings and is reported under the caption~~ ~~Equity method investments~~ ~~on the Consolidated Balance Sheets. In connection with the initial contributions, MarkWest Liberty Midstream received a special distribution of approximately $45 million.~~

MarkWest Liberty Midstream’s and Sherwood Midstream’s ownership interests in Sherwood Midstream Holdings will fluctuate over time. As new Shared Assets are constructed, the members will make additional capital contributions to Sherwood Midstream Holdings. The amount that each member must contribute will be based on the expected utilization of the Shared Assets, as defined in the LLC Agreement. Pursuant to the terms of the LLC Agreement, MarkWest Liberty Midstream will serve as the operator for Sherwood Midstream Holdings.

~~The Partnership accounts for Sherwood Midstream Holdings, which is a VIE, as an~~ equity method investment as Sherwood Midstream is considered to be the general partner and controls all decisions. The Partnership’s investment in Sherwood Midstream Holdings, which was approximately $163 million at September 30, 2017, is reported under the caption ~~Equity method investments~~ on the Consolidated Balance Sheets. The Partnership’s maximum exposure to loss as a result of its involvement with Sherwood Midstream Holdings includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. The Partnership did not provide any financial support to Sherwood Midstream Holdings that it was not contractually obligated to provide during the nine months ended September 30, 2017.investees.

Sherwood Midstream has been deemed the primary beneficiary of Sherwood Midstream Holdings due to its controlling financial interest through its authority to manage the joint venture. As a result, Sherwood Midstream consolidates Sherwood Midstream Holdings. Therefore, the Partnership also reports its portion of Sherwood Midstream Holdings’ net assets as a component of its investment in Sherwood Midstream. As of September 30, 2017, the Partnership has a 14.7 percent indirect ownership interest in Sherwood Midstream Holdings through Sherwood Midstream.

5.4. Related Party Agreements and Transactions

~~The Partnership’s material~~MPLX engages in transactions with both MPC and certain of its equity method investments as part of its normal business; however, transactions with MPC make up the majority of MPLX’s related party transactions. Transactions with related parties ~~include:~~are further described below.

~~MPC, which refines, markets and transports crude oil and petroleum products, primarily in the Midwest, Gulf Coast, East Coast and Southeast regions of the United States.~~

~~Related Party Agreements~~

~~The Partnership~~ has various long-term, fee-based commercial agreements with MPC. Under these agreements, ~~the Partnership~~MPLX provides transportation, gathering, terminal, fuels distribution, marketing, storage, management, operational and ~~storage~~other services to ~~MPC, and~~MPC. MPC has committed to provide ~~the Partnership~~MPLX with minimum quarterly throughput volumes on crude oil and refined products ~~systems~~ and ~~minimum~~other fees for storage ~~volumes~~capacity; operating and management fees; and reimbursements for certain direct and indirect costs. MPC has also committed to provide a fixed fee for 100 percent of ~~crude oil, refined products~~available capacity for boats, barges and ~~butane.~~third-party chartered equipment under the marine transportation service agreement. MPLX also has a keep-whole commodity agreement with MPC under which MPC pays us a processing fee for NGLs related to keep-whole agreements and delivers shrink gas to the producers on our

~~In addition,~~behalf. We pay MPC a marketing fee in exchange for assuming the ~~Partnership~~commodity risk. Additionally, MPLX has obligations to MPC for services provided to MPLX by MPC under omnibus and employee services-type agreements as well as other agreements.

During the second quarter of 2023, several terminal and storage services agreements with MPC were amended for certain items, including exercise of a five-year renewal option, with terms now extending to 2028.

MPLX is party to a loan agreement (the “MPC Loan Agreement”) with ~~MPC Investment, a wholly-owned subsidiary of~~ MPC. Under the terms of the ~~agreement,~~ MPC ~~Investment will make a loan or~~Loan Agreement, MPC extends loans to ~~the Partnership~~MPLX on a revolving basis as requested by ~~the Partnership~~MPLX and as agreed to by MPC. The borrowing capacity of the MPC ~~Investment, in an amount or amounts that do not result in the~~Loan Agreement is $1.5 billion aggregate principal amount of all loans outstanding ~~exceeding $500 million~~ at any one time. The ~~entire unpaid principal amount of~~MPC Loan Agreement is scheduled to expire, and borrowings under the loan ~~together with all accrued~~agreement are scheduled to mature and ~~unpaid interest and other amounts (if any), shall~~ become due and payable, on ~~December 4, 2020.~~July 31, 2024, provided that MPC ~~Investment~~ may demand payment of all or any portion of the outstanding principal amount of the loan, together with all accrued and unpaid interest and other amounts (if any), at any time prior to ~~December 4, 2020.~~maturity. Borrowings under the ~~loan will~~MPC Loan Agreement bear interest at ~~LIBOR~~one-month term SOFR adjusted upward by 0.10 percent plus ~~1.50 percent. During~~1.25 percent or such lower rate as would be applicable to such loans under the ~~nine months ended September 30, 2017, the Partnership borrowed $829 million and repaid $627 million, resulting~~MPLX Credit Agreement as discussed in ~~$202 million outstanding balance at September 30, 2017, which is included in~~ ~~Payables-related parties~~Note 11.

There was no activity on the ~~Consolidated Balance Sheets. Borrowings were at an average interest rate of 2.721 percent, per annum,~~MPC Loan Agreement for the nine months ended September 30, 2017. During the year ended December 31, 2016, the Partnership borrowed $2.5 billion and repaid $2.5 billion, resulting in no outstanding balance at December 31, 2016. Borrowings were at an average interest rate of 1.939 percent, per annum, for the year ended December 31, 2016. For additional information regarding the Partnership’s commercial and other agreements with MPC, see Item 1. Business in the Annual Report on Form 10-K for the year ended December 31, 2016.2023.

~~The Partnership believes the terms and conditions under its agreements with MPC are generally comparable to those with unrelated parties.~~

~~HST, WHC and MPLXT Agreements~~

As discussed in Note 3, the Partnership acquired HST, WHC and MPLXT on March 1, 2017. HST, WHC and MPLXT have various operating, transportation services, terminal services, storage services and employee services agreements with MPC, which were assumed by the Partnership with the closing of the Transaction.

HST is a party to a transportation services agreement with MPC dated January 1, 2015. Under this agreement, HST provides pipeline transportation of crude oil and refined products, as well as related services, for MPC. MPC pays HST for such services based on contractual rates related to MPC crude oil and refined product deliveries as well as any viscosity surcharges, loading, handling, transfers or other related charges. This agreement is set to expire on December 31, 2026 and automatically renews for two additional renewal terms of four years each unless terminated by either party.

On January 1, 2015, HST entered into various three-year term storage services agreements with MPC. Under the storage services agreements, HST receives a monthly fee from MPC based on a contractual rate per barrel multiplied by the total commitment volume respective to each storage tank. The contractual rate per barrel is subject to an annual review and adjustment for inflation. HST is not obligated to measure volume gains and losses per the terms of these agreements.

On January 1, 2015, WHC entered into a long-term, fee-based storage and services agreement with MPC related to storage at its butane and propane caverns with an initial term of 10 years. Under this storage and services agreement, WHC receives a monthly fee from MPC based on a contractual rate per barrel multiplied by the total commitment volume respective to each storage cavern. The contractual rate per barrel includes utilization of the caverns and related services. The agreement is subject to an annual review and adjustment for inflation.

Under the storage services agreements with both HST and WHC, the Partnership is obligated to make available to MPC, on a firm basis, the available storage capacity at the tank farms and butane and propane caverns and MPC pays the Partnership a per-barrel fee for such storage capacity regardless of whether MPC fully utilizes the available capacity.

MPLXT is a party to a terminal services agreement with MPC, dated March 1, 2017. Under this agreement, MPLXT provides terminal storage for refined petroleum products, as well as related services, for MPC. MPC pays MPLXT monthly for such services based on contractual fees relating to MPC product deliveries as well as any viscosity surcharges, loading, handling, transfers or other related charges. This agreement is set to expire on March 31, 2026 and automatically renews for two additional renewal terms of five years each unless terminated by either party.

The Partnership is party to various employee services agreements with MPC under which the Partnership reimburses MPC for employee benefit expenses, along with the provision of operational and management services, including those in support of HST, WHC and MPLXT.

Related Party ~~Transactions~~Revenue

~~Sales to related parties were as follows:~~

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
Service revenues
MPC $ 276
$ 253
$ 801
$ 676
Rental income
MPC $ 70
$ 68
$ 207
$ 172
Product sales⁽¹⁾

MPC $ 2
$ 2
$ 6
$ 8

Related party sales to MPC primarily consist of crude oil and refined products pipeline ~~transportation services~~ based on ~~regulated~~ tariff ~~rates,~~or contracted rates; storage, terminal and fuels distribution services based on contracted ~~rates~~rates; and marine transportation services. Related party sales to MPC also consist of revenue related to volume deficiency credits.

MPLX also has operating agreements with MPC under which it receives a fee for operating MPC’s retained pipeline assets and a fixed annual fee for providing oversight and management services required to run the marine business. MPLX also receives management fee revenue for engineering, construction and administrative services for operating certain of its equity method investments. Amounts earned under these agreements are classified as Other income - related parties in the Consolidated Statements of Income.

Certain product sales to MPC and other related parties net to zero within the consolidated financial statements as the transactions are recorded net due to the terms of the agreements under which such product was sold. For the three and nine months ended September 30, 2023, these sales totaled $192 million and $540 million, respectively. For the three and nine months ended September 30, 2022, these sales totaled $235 million and $809 million, respectively.

Related Party Expenses

MPC charges MPLX for executive management services and certain general and administrative services provided ~~by HSM. Under~~to MPLX under the ~~Partnership’s pipeline transportation~~terms of our omnibus agreements (“Omnibus charges”) and for certain employee services provided to MPLX under employee services agreements if(“ESA charges”). Omnibus charges and ESA charges are classified as Rental cost of sales - related parties, Purchases - related parties, or General and administrative expenses depending on the nature of the asset or activity with which the costs are associated. In addition to these agreements, MPLX purchases products from MPC, makes payments to MPC in its capacity as general contractor to MPLX, and has certain rent and lease agreements with MPC.

For the three and nine months ended September 30, 2023, General and administrative expenses incurred from MPC totaled $72 million and $197 million, respectively. For the three and nine months ended September 30, 2022, General and administrative expenses incurred from MPC totaled $60 million and $173 million, respectively.

Some charges incurred under the omnibus and employee service agreements are related to engineering services and are associated with assets under construction. These charges are added to Property, plant and equipment, net on the Consolidated Balance Sheets. For the three and nine months ended September 30, 2023, these charges totaled $28 million and $56 million, respectively. For the three and nine months ended September 30, 2022, these charges totaled $16 million and $54 million, respectively.

Related Party Assets and Liabilities

Assets and liabilities with related parties appearing in the Consolidated Balance Sheets are detailed in the table below. This table identifies the various components of related party assets and liabilities, including those associated with leases and deferred revenue on minimum volume commitments. If MPC fails to ~~transport~~meet its minimum ~~throughput~~committed volumes, ~~during any quarter, then~~ MPC will pay ~~the Partnership~~MPLX a deficiency payment ~~equal to~~based on the ~~volume~~terms of the ~~deficiency multiplied by the tariff rate then in effect.~~agreement. The deficiency amounts received under these agreements (excluding payments received under agreements classified as sales-type leases) are recorded as ~~Deferred revenue-related parties~~.Current liabilities - related parties. In many cases, MPC may then apply the amount of any such deficiency payments as a credit for volumes ~~transported on the applicable pipeline system~~ in excess of its minimum volume commitment ~~during the following four or eight quarters~~in future periods under the terms of the applicable ~~transportation services agreement. The Partnership~~agreements. MPLX recognizes related party revenues for the deficiency payments when credits are used for volumes ~~transported~~ in excess of minimum quarterly volume commitments, ~~when~~where it ~~becomes impossible to physically transport volumes necessary to utilize~~is

probable the ~~credits~~customer will not use the credit in future periods or upon the expiration of the credits. The use or expiration of the credits is a decrease in ~~Deferred revenue-related parties~~.

~~The revenue received from~~Current liabilities - related ~~parties, included in~~ ~~Other income-related parties~~ ~~on the Consolidated Statements of Income, was as follows:~~

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
MPC $ 9
$ 10
$ 30
$ 36
MarkWest Utica EMG 5
5
13
12
Ohio Gathering 4
5
12
12
Other 4
2
14
7
Total $ 22
$ 22
$ 69
$ 67

~~MPC provides executive management services and certain general and administrative services to the Partnership~~parties. Deficiency payments under ~~the terms of an omnibus agreement. Expenses incurred under this agreement are shown in the table below by the income statement line where they were recorded. Charges for services included in~~ ~~Purchases-related parties~~ ~~primarily relate to services~~agreements that ~~support the Partnership’s operations and maintenance activities, as well as compensation expenses. Charges for services included in~~ ~~General and administrative expenses~~ ~~primarily relate to services that support the Partnership’s executive management, accounting and human resources activities. These charges were as follows:~~

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
Purchases - related parties $ 17
$ 11
$ 50
$ 29
General and administrative expenses 9
11
28
33
Total $ 26
$ 22
$ 78
$ 62

~~Also under terms of the omnibus agreement, some service costs related to engineering services are associated with assets under construction. These costs added to~~ ~~Property, plant and equipment~~ ~~were as follows:~~

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
MPC $ 11
$ 14
$ 33
$ 36

MPLX LP obtains employee services from MPC under employee services agreements. Expenses incurred under these agreements are shown in the table below by the income statement line where they were recorded. The costs of personnel directly involved in or supporting operations and maintenance activities arehave been classified as ~~Purchases-related parties. The costs of personnel involved in executive management, accounting and human resources activities~~sales-type leases are ~~classified~~recorded as ~~General and administrative~~ ~~expenses in~~a reduction against the ~~Consolidated Statements of Income.~~

~~Employee services expenses from related parties were as follows:~~

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
Purchases - related parties $ 97
$ 98
$ 280
$ 257
General and administrative expenses 25
27
74
75
Total $ 122
$ 125
$ 354
$ 332

~~Receivables from related parties, which for December 31, 2016 included reimbursements from the MarkWest Merger to be provided by MPC for the conversion of Class B units, were as follows:~~

(In millions) September 30, 2017 December 31, 2016
MPC $ 144
$ 242
MarkWest Utica EMG 2
2
Ohio Gathering 2
2
Other 4
1
Total $ 152
$ 247

~~Long-term receivables with related parties, which includes straight-line rental income, were as follows:~~

(In millions) September 30, 2017 December 31, 2016
MPC $ 18
$ 11

~~Payables to related parties were as follows:~~

(In millions) September 30, 2017 December 31, 2016
MPC⁽¹⁾
$ 277
$ 63
MarkWest Utica EMG 30
24
Other 10
—
Total $ 317
$ 87

~~During the nine months ended September 30, 2017 and the year ended December 31, 2016, MPC did not ship its minimum committed volumes on certain pipeline systems.~~corresponding lease receivable. In addition, capital projects ~~the Partnership is undertaking~~MPLX undertakes at the request of MPC are reimbursed in cash and recognized ~~in income~~as revenue over the remaining term of the applicable ~~agreements. The~~ ~~Deferred revenue-related parties~~ ~~balance associated with~~agreements or in some cases, as a contribution from MPC.


(In millions)	September 30, 2023		December 31, 2022
Current assets - related parties
Receivables	$	599	$	610
Lease receivables	140		111
Prepaid	14		5
Other	6		3
Total	759		729
Noncurrent assets - related parties
Long-term lease receivables	811		883
Right of use assets	227		228
Unguaranteed residual asset	115		87
Long-term receivables	21		27
Total	1,174		1,225
Current liabilities - related parties
MPC loan agreement and other payables(1)	312		262
Deferred revenue	74		80
Operating lease liabilities	1		1
Total	387		343
Long-term liabilities - related parties
Long-term operating lease liabilities	226		228
Long-term deferred revenue	117		110
Total	$	343	$	338

(1) There were no borrowings outstanding on the ~~minimum volume deficiencies and project reimbursements were~~MPC Loan Agreement as ~~follows:~~

(In millions) September 30, 2017 December 31, 2016
Minimum volume deficiencies - MPC $ 55
$ 48
Project reimbursements - MPC 27
9
Total $ 82
$ 57

~~6. Net Income (Loss) Per Limited Partner Unit~~

Net income (loss) per unit applicable to common limited partner units is computed by dividing the respective limited partners’ interest in net income (loss) attributable to MPLX LP by the weighted average number of common units outstanding. Because the Partnership has more than one class of participating securities, it uses the two-class method when calculating the net income (loss) per unit applicable to limited partners. The classes of participating securities include common units, general partner units, Preferred units, certain equity-based compensation awards and IDRs.

As discussed in Note 1, the HST, WHC and MPLXT acquisition was a transfer between entities under common control. As entities under common control with MPC, prior periods were retrospectively adjusted to furnish comparative information. Accordingly, the prior period earnings have been allocated to the general partner and do not affect the net income (loss) per unit calculation. The earnings for the entities acquired under common control will be included in the net income (loss) per unit calculation prospectively as described above.

~~For the three months ended~~ September 30, ~~2017,~~2023 or December 31, 2022.

Other Related Party Transactions

From time to time, MPLX may also sell to or purchase from related parties, assets and inventory at the ~~Partnership had dilutive potential common units consisting~~lesser of certain equity-based compensation awards. For the three months ended September 30, 2016 and the nine months ended September 30, 2017 and 2016, the Partnership had dilutive potential common units consisting of certain equity-based compensation awards and Class B units. Potential common units omitted from the diluted earnings peraverage unit calculation for the three and nine months ended September 30, 2017 were less than one million and for the three and nine months ended September 30, 2016 were less than one million and approximately eight million, respectively.cost or net realizable value.

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
Net income attributable to MPLX LP $ 216
$ 141
$ 556
$ 100
Less: Limited partners’ distributions declared
on Preferred units⁽¹⁾
16
16
49
25
General partner’s distributions declared (including IDRs)⁽¹⁾
88
54
229
148
Limited partners’ distributions declared on common units⁽¹⁾
232
179
648
507
Undistributed net loss attributable to MPLX LP $ (120 )
$ (108 ) $ (370 ) $ (580 )

Three Months Ended September 30, 2017
(In millions, except per unit data)
General
Partner

Limited
Partners’
Common
Units
Redeemable Preferred Units Total
Basic and diluted net income attributable to MPLX LP per unit:
Net income attributable to MPLX LP:
Distributions declared (including IDRs) $ 88
$ 232
$ 16
$ 336
Undistributed net loss attributable to MPLX LP (2 ) (118 ) —
(120 )
Net income attributable to MPLX LP⁽¹⁾
$ 86
$ 114
$ 16
$ 216
Weighted average units outstanding:
Basic 8
394
31
433
Diluted 8
395
31
434
Net income attributable to MPLX LP per limited partner unit:
Basic $ 0.29

Diluted $ 0.29

Three Months Ended September 30, 2016
(In millions, except per unit data)
General
Partner

Limited
Partners’
Common
Units
Redeemable Preferred Units Total
Basic and diluted net income attributable to MPLX LP per unit:
Net income attributable to MPLX LP:
Distributions declared (including IDRs) $ 54
$ 179
$ 16
$ 249
Undistributed net loss attributable to MPLX LP (3 ) (105 ) —
(108 )
Net income attributable to MPLX LP⁽¹⁾
$ 51
$ 74
$ 16
$ 141
Weighted average units outstanding:
Basic 7
341
31
379
Diluted 7
346
31
384
Net income attributable to MPLX LP per limited partner unit:
Basic $ 0.22

Diluted $ 0.21

Nine Months Ended September 30, 2017
(In millions, except per unit data)
General
Partner

Limited
Partners’
Common
Units
Redeemable Preferred Units Total
Basic and diluted net income attributable to MPLX LP per unit:
Net income attributable to MPLX LP:
Distributions declared (including IDRs) $ 229
$ 648
$ 49
$ 926
Undistributed net loss attributable to MPLX LP (7 ) (363 ) —
(370 )
Net income attributable to MPLX LP⁽¹⁾
$ 222
$ 285
$ 49
$ 556
Weighted average units outstanding:
Basic 8
378
31
417
Diluted 8
381
31
420
Net income attributable to MPLX LP per limited partner unit:
Basic $ 0.75

Diluted $ 0.75

Nine Months Ended September 30, 2016
(In millions, except per unit data)
General
Partner

Limited
Partners’
Common
Units
Redeemable Preferred Units Total
Basic and diluted net loss attributable to MPLX LP per unit:
Net income (loss) attributable to MPLX LP:
Distributions declared (including IDRs) $ 148
$ 507
$ 25
$ 680
Undistributed net loss attributable to MPLX LP (12 ) (568 ) —
(580 )
Net income (loss) attributable to MPLX LP⁽¹⁾
$ 136
$ (61 ) $ 25
$ 100
Weighted average units outstanding:
Basic 7
324
16
347
Diluted 7
324
16
347
Net loss attributable to MPLX LP per limited partner unit:
Basic $ (0.19 )

Diluted $ (0.19 )

The changes in the number of common units ~~outstanding~~ during the nine months ended September 30, ~~2017~~2023 are summarized below:

(In units) Common Class B General Partner Total
Balance at December 31, 2016 357,193,288
3,990,878
7,371,105
368,555,271
Unit-based compensation awards⁽¹⁾
183,509
—
3,745
187,254
Issuance of units under the ATM Program⁽²⁾
13,846,998
—
282,591
14,129,589
Contribution of HST/WHC/MPLXT⁽³⁾
12,960,376
—
264,497
13,224,873
Contribution of the Joint-Interest Acquisition⁽³⁾
18,511,134
—
377,778
18,888,912
Class B conversion⁽⁴⁾
4,350,057
(3,990,878 ) 7,330
366,509
Balance at September 30, 2017 407,045,362

—

8,307,046

415,352,408

Unit Repurchase Program

On August 2, 2022, we announced the board authorization for the repurchase of up to $1 billion of MPLX common units held by the public. This unit repurchase authorization has no expiration date. We may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, accelerated unit repurchases, tender offers or open market solicitations for units, some of which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.

No units were repurchased during the three or nine months ended September ~~1, 2016,~~30, 2023. As of September 30, 2023, we had $846 million remaining under the ~~Partnership~~unit repurchase authorization.

Redemption of the Series B Preferred Units

On February 15, 2023, MPLX exercised its right to redeem all 600,000 outstanding 6.875 percent Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series B preferred units”). MPLX paid unitholders the Series B preferred unit redemption price of $1,000 per unit.

Distributions on the Series B preferred units were payable semi-annually in arrears on the 15th day, or the first business day thereafter, of February and ~~various affiliates initiated a series~~August of ~~reorganization transactions in order~~each year up to ~~simplify the Partnership’s ownership structure~~ and ~~its financial and tax reporting requirements.~~including February 15, 2023. In ~~connection~~accordance with these ~~transactions, the issued and outstanding~~terms, MPLX ~~LP Class A units, all~~made a final cash distribution of which were held by MarkWest Hydrocarbon, were either distributed to or purchased by MPC in exchange for $84 million in cash, 21,401,137 MPLX LP common units and 436,758 MPLX LP general partner units. Following these initial transactions, all of the MPLX LP Class A units were exchanged on a one-for-one basis for newly issued common units representing limited partner interests in MPLX LP. MPC also contributed $141$21 million to ~~facilitate~~Series B preferred unitholders on February 15, 2023, in conjunction with the repayment of intercompany debt between MarkWest Hydrocarbon and MarkWest. As a result of these transactions, the MPLX LP Class A units were eliminated, are no longer outstanding and no longer participate in distributions of cash from the Partnership. Cash that is derived from or attributable to MarkWest Hydrocarbon’s operations is now treatedredemption.

The changes in the ~~same manner as cash derived from or attributable to other operations of~~Series B preferred unit balance during the ~~Partnership~~nine months ended September 30, 2023 and ~~its subsidiaries.~~

~~Net Income Allocation~~–~~In preparing~~September 30, 2022 are included in the Consolidated Statements of Equity ~~net income (loss) attributable to~~within Series B preferred units.

On October 24, 2023, MPLX LP is allocated to Preferred unitholders based on a fixed distribution schedule, as discussed in Note 8, and subsequently allocated to the general partner and limited partner unitholders. However, when distributions related to the IDRs are made, earnings equal to the amount of those distributions are first allocated to the general partner before the remaining earnings are allocated to the unitholders, based on their respective ownership percentages. The following table presents the allocation of the general partner’s GP Interest in net income attributable to MPLX LP:

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
Net income attributable to MPLX LP $ 216
$ 141
$ 556
$ 100
Less: Preferred unit distributions 16
16
49
25
General partner's IDRs and other 83
49
216
137
Net income (loss) attributable to MPLX LP available to general and limited partners $ 117
$ 76
$ 291
$ (62 )

General partner's two percent GP Interest in net income (loss) attributable to MPLX LP $ 3
$ 2
$ 6
$ (1 )
General partner's IDRs and other 83
49
216
137
General partner's GP Interest in net income attributable to MPLX LP $ 86
$ 51
$ 222
$ 136

~~Cash distributions~~–The Partnership Agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, Preferred unitholders and general partner will receive. In accordance with the Partnership Agreement, on October 25, 2017, the Partnership declared a ~~quarterly~~ cash distribution ~~based on the results of~~for the third quarter of ~~2017,~~2023, totaling ~~$320~~$851 million, or ~~$0.5875~~$0.850 per common unit. ~~These distributions~~This distribution will be paid on November ~~14, 2017~~13, 2023 to common unitholders of record on November ~~6, 2017.~~3, 2023. This rate will also be received by Series A preferred unitholders.

Quarterly distributions for 2023 and 2022 are summarized below:


(Per common unit)	2023		2022
March 31,	$	0.775	$	0.705
June 30,	0.775		0.705
September 30,	$	0.850	$	0.775

The allocation of total quarterly cash distributions to ~~general,~~ limited and ~~Preferred~~preferred unitholders is as follows for the three and nine months ended September 30, ~~2017~~2023 and ~~2016. The Partnership’s~~September 30, 2022. Distributions, although earned, are not accrued until declared. MPLX’s distributions are declared subsequent to quarter end; therefore, the following table represents total cash distributions applicable to the period in which the distributions were earned.


	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2023		2022		2023		2022
Common and preferred unit distributions:
Common unitholders, includes common units of general partner	$	851	$	777	$	2,403	$	2,204
Series A preferred unit distributions	25		23		71		65
Series B preferred unit distributions(1)	—		10		5		31
Total cash distributions declared	$	876	$	810	$	2,479	$	2,300

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
General partner's distributions:
General partner's distributions on general partner units $ 7
$ 5
$ 18
$ 13
General partner's distributions on IDRs 81
49
211
135
Total distribution on general partner units and IDRs $ 88
$ 54
$ 229
$ 148
Common and preferred unit distributions:
Common unitholders, includes common units of general partner $ 232
$ 179
$ 648
$ 507
Preferred unit distributions 16
16
49
25
Total cash distributions declared $ 336
$ 249
$ 926
$ 680

~~8. Redeemable Preferred Units~~

~~Private Placement of Preferred Units~~ –~~On May 13, 2016, MPLX LP completed~~(1) The nine months ended September 30, 2023 includes the private placement of approximately 30.8 million 6.5 percent Series A Convertible Preferred units (the "Preferred units") for a cash purchase price of $32.50 per unit. The aggregate net proceeds of approximately $984 million from the saleportion of the ~~Preferred units were used for capital expenditures, repayment of debt and general partnership purposes.~~$21 million distribution paid to the Series B preferred unitholders on February 15, 2023 that was earned during the period prior to redemption.

The Preferred units rank senior to all common units with respect to distributions and rights upon liquidation. The holders of the Preferred units are entitled to receive cumulative quarterly distributions equal to $0.528125 per unit. Following the second anniversary of the issuance of the Preferred units, the holders of the Preferred units will receive as a distribution the greater of $0.528125

6. Net Income Per Limited Partner Unit

Net income per unit ~~or the amount of per unit distributions paid~~applicable to ~~holders of MPLX LP common units.~~

~~The changes in the redeemable preferred balance from December 31, 2016 through September 30, 2017 are summarized below:~~

(In millions) Redeemable Preferred Units
Balance at December 31, 2016 $ 1,000
Net income 49
Distributions received by Preferred unitholders (49 )
Balance at September 30, 2017 $ 1,000

The holders may convert their Preferred units into common units at any time after the third anniversary of the issuance date or prior to liquidation, dissolution or winding up of the Partnership, in full or in part, subject to minimum conversion amounts and conditions. After the fourth anniversary of the issuance date, the Partnership may convert the Preferred units into common units at any time, in whole or in part, subject to certain minimum conversion amounts and conditions, if the closing price of MPLX LP common units is ~~greater than $48.75~~computed by dividing net income attributable to MPLX LP less income allocated to participating securities by the weighted average number of common units outstanding.

During the three and nine months ended September 30, 2023 and September 30, 2022, MPLX had participating securities consisting of common units, certain equity-based compensation awards, Series A preferred units, and Series B preferred units and also had dilutive potential common units consisting of certain equity-based compensation awards. Potential common units omitted from the diluted earnings per unit calculation for the ~~20 day trading period immediately preceding the conversion notice date. The conversion rate~~three and nine months ended September 30, 2023 andSeptember 30, 2022 were less than 1 million.


	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2023		2022		2023		2022
Net income attributable to MPLX LP	$	918	$	1,428	$	2,794	$	3,128
Less: Distributions declared on Series A preferred units	25		23		71		65

Distributions declared on Series B preferred units	—		10		5		31
Limited partners’ distributions declared on MPLX common units (including common units of general partner)	851		777		2,403		2,204

Undistributed net gain attributable to MPLX LP	$	42	$	618	$	315	$	828


	Three Months Ended September 30, 2023
(In millions, except per unit data)	Limited Partners’ Common Units		Series A Preferred Units		Total
Basic and diluted net income attributable to MPLX LP per unit
Net income attributable to MPLX LP:
Distributions declared	$	851	$	25	$	876
Undistributed net gain attributable to MPLX LP	41		1		42
Net income attributable to MPLX LP(1)	$	892	$	26	$	918


Weighted average units outstanding:
Basic	1,001
Diluted	1,001
Net income attributable to MPLX LP per limited partner unit:
Basic	$	0.89
Diluted	$	0.89

(1) Allocation of net income attributable to MPLX LP assumes all earnings for the ~~Preferred units shall be the quotient of (a) the sum of (i) $32.50, plus (ii) any unpaid cash distributions~~period had been distributed based on the distribution priorities applicable Preferred unit, divided by (b) $32.50. The holders of the Preferred units are entitled to vote on an as-converted basis with the common unitholders and will have certain other class voting rights with respect to any amendment to the ~~Partnership Agreement that would adversely affect any rights, preferences or privileges~~period.


	Three Months Ended September 30, 2022
(In millions, except per unit data)	Limited Partners’ Common Units		Series A Preferred Units		Series B Preferred Units		Total
Basic and diluted net income attributable to MPLX LP per unit
Net income attributable to MPLX LP:
Distributions declared	$	777	$	23	$	10	$	810
Undistributed net gain attributable to MPLX LP(1)	600		18		—		618
Net income attributable to MPLX LP(2)	$	1,377	$	41	$	10	$	1,428
Weighted average units outstanding:
Basic	1,010
Diluted	1,011
Net income attributable to MPLX LP per limited partner unit:
Basic	$	1.36
Diluted	$	1.36

(1) The undistributed net gain attributable to MPLX LP includes a $509 million non-cash gain on a lease reclassification for the three months ended September 30, 2022. See Note 14 for additional information.

(2) Allocation of net income attributable to MPLX LP assumes all earnings for the ~~Preferred units. In addition, upon certain events involving a change of control~~period had been distributed based on the ~~holders of Preferred units may elect, among other potential elections,~~distribution priorities applicable to ~~convert their Preferred units to common units at~~ the ~~then-change of control conversion rate.~~period.

Table of Contents


	Nine Months Ended September 30, 2023
(In millions, except per unit data)	Limited Partners’ Common Units		Series A Preferred Units		Series B Preferred Units		Total
Basic and diluted net income attributable to MPLX LP per unit
Net income attributable to MPLX LP:
Distributions declared	$	2,403	$	71	$	5	$	2,479
Undistributed net gain attributable to MPLX LP	306		9		—		315
Net income attributable to MPLX LP(1)	2,709		$	80	$	5	2,794
Impact of redemption of Series B preferred units	(5)						(5)
Income available to common unitholders	$	2,704					$	2,789
Weighted average units outstanding:
Basic	1,001
Diluted	1,001
Net income attributable to MPLX LP per limited partner unit:
Basic	$	2.70
Diluted	$	2.70

~~The Preferred units are considered redeemable securities under GAAP due~~(1) Allocation of net income attributable to MPLX LP assumes all earnings for the period had been distributed based on the distribution priorities applicable to the ~~existence~~period.


	Nine Months Ended September 30, 2022
(In millions, except per unit data)	Limited Partners’ Common Units		Series A Preferred Units		Series B Preferred Units		Total
Basic and diluted net income attributable to MPLX LP per unit
Net income attributable to MPLX LP:
Distributions declared	$	2,204	$	65	$	31	$	2,300
Undistributed net gain attributable to MPLX LP(1)	804		24		—		828
Net income attributable to MPLX LP(2)	$	3,008	$	89	$	31	$	3,128
Weighted average units outstanding:
Basic	1,012
Diluted	1,013
Net income attributable to MPLX LP per limited partner unit:
Basic	$	2.97
Diluted	$	2.97

(1) The undistributed net gain attributable to MPLX LP includes a $509 million non-cash gain on a lease reclassification for the nine months ended September 30, 2022. See Note 14 for additional information.

(2) Allocation of ~~redemption provisions upon a deemed liquidation event which is outside~~net income attributable to MPLX LP assumes all earnings for the ~~Partnership’s control. Therefore, they are presented as temporary equity in~~period had been distributed based on the mezzanine section of the Consolidated Balance Sheets. The Preferred units have been recorded at their issuance date fair value, net of issuance costs. Income allocations increase the carrying value, and declared distributions decreased the carrying value of the Preferred units. As the Preferred units are not currently redeemable and not probable of becoming redeemable, adjustmentdistribution priorities applicable to the ~~initial carrying amount is not necessary and would only be required if it becomes probable that the Preferred units would become redeemable.~~period.

9.7. Segment Information

~~The Partnership’s~~MPLX’s chief operating decision maker (“CODM”) is the chief executive officer ~~(“CEO”)~~ of its general partner. The ~~CEO~~CODM reviews ~~the Partnership’s~~MPLX’s discrete financial information, makes operating decisions, assesses financial performance and allocates resources on a type of service basis. ~~The Partnership~~MPLX has two reportable segments: L&S and G&P. Each of these segments ~~are~~is organized and managed based upon the nature of the products and services it offers.

•L&S – gathers, transports, stores and distributes crude oil, refined products, other hydrocarbon-based products and ~~refined petroleum products. Segment information for prior periods~~renewables. Also includes ~~retrospective adjustments in connection with~~ the ~~acquisition~~operation of ~~HST, WHC~~refining logistics, fuels distribution and ~~MPLXT. Segment information is not included for periods prior to the Joint-Interest Acquisition~~inland marine businesses, terminals, rail facilities, and ~~the Ozark pipeline acquisition. See Note 3 for more detail of these acquisitions.~~storage caverns.

•G&P – gathers, processes and transports natural gas; ~~gathers,~~and transports, fractionates, stores and markets NGLs.

~~The Partnership has investments~~Our CODM evaluates the performance of our segments using Segment Adjusted EBITDA. Amounts included in ~~entities that are accounted for using the~~net income and excluded from Segment Adjusted EBITDA include: (i) depreciation and amortization; (ii) interest and other financial costs; (iii) income/(loss) from equity method ~~of accounting (see Note 4). However, the CEO views the Partnership-operated~~investments; (iv) distributions and adjustments related to equity method ~~investments’ financial information~~investments; (v) gain on sales-type leases; (vi) impairment expense; (vii) noncontrolling interests; and (viii) other adjustments, as ~~if those investments were consolidated.~~applicable. These items are either: (i) believed to be non-recurring in nature; (ii) not believed to be allocable or controlled by the segment; or (iii) are

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~~Segment operating income represents income from operations attributable~~not tied to the ~~reportable segments. Corporate general and administrative expenses, unrealized derivative gains (losses), goodwill impairment, certain management fees and depreciation and amortization~~operational performance of the segment. Assets by segment are not ~~allocated~~a measure used to assess the reportable segments. Management does not consider these items allocable to or controllable by any individual segment and, therefore, excludes these items when evaluating segment performance. Segment results are also adjusted to exclude the portion of income from operations attributable to the noncontrolling interests related to partially-owned entities that are either consolidated or accounted for as equity method investments. Segment operating income attributable to MPLX LP excludes the operating income related to Predecessorsperformance of the ~~HSM, HST, WHC~~Partnership by our CODM and ~~MPLXT businesses prior to the dates they were acquired by MPLX LP.~~thus are not reported in our disclosures.

The tables below present information about revenues and other income, ~~from operations and~~Segment Adjusted EBITDA, capital expenditures and investments in unconsolidated affiliates for our reportable segments:


	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2023		2022		2023		2022
L&S
Service revenue	$	1,130	$	1,038	$	3,223	$	3,031
Rental income	216		210		638		593
Product related revenue	6		4		14		15
Sales-type lease revenue	129		118		379		343
Income from equity method investments	95		72		248		183
Other income	15		8		47		42
Total segment revenues and other income(1)	1,591		1,450		4,549		4,207
Segment Adjusted EBITDA(2)	1,091		969		3,139		2,839
Capital expenditures	73		80		251		238
Investments in unconsolidated affiliates	7		12		23		90
G&P
Service revenue	549		537		1,620		1,528
Rental income	52		66		155		239
Product related revenue	598		742		1,629		2,263
Sales-type lease revenue	34		28		101		28
Income from equity method investments	64		53		190		152
Other income(3)	24		525		71		534
Total segment revenues and other income(1)	1,321		1,951		3,766		4,744
Segment Adjusted EBITDA(2)	505		502		1,507		1,482
Capital expenditures	151		146		417		336
Investments in unconsolidated affiliates	$	6	$	30	$	67	$	108

(1) Within the total segment revenues and other income amounts presented above, third party revenues for the ~~reported segments:~~

L&S segment were $207 million and $564 million for the three and nine months ended September 30, 2023, respectively, and $175 million and $468 million for the three and nine months ended September 30, 2022, respectively. Third party revenues for the G&P segment were $1,248 million and $3,553 million for the three and nine months ended September 30, 2023, respectively, and $1,885 million and $4,551 million for the three and nine months ended September 30, 2022, respectively.

Three Months Ended September 30, 2017
(In millions) L&S G&P Total
Revenues and other income:
Segment revenues $ 378
$ 669
$ 1,047
Segment other income 11
1
12
Total segment revenues and other income 389
670
1,059
Costs and expenses:
Segment cost of revenues 176
276
452
Segment operating income before portion attributable to noncontrolling interests and Predecessor 213
394
607
Segment portion attributable to noncontrolling interests and Predecessor —
45
45
Segment operating income attributable to MPLX LP $ 213
$ 349
$ 562
(2) See below for the reconciliation from Segment Adjusted EBITDA to Net income.

(3) The three and nine months ended September 30, 2022 include a $509 million non-cash gain on a lease reclassification. See Note 14 in the unaudited consolidated financial statements for additional information.

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Three Months Ended September 30, 2016
(In millions) L&S G&P Total
Revenues and other income:
Segment revenues $ 339
$ 567
$ 906
Segment other income 12
1
13
Total segment revenues and other income 351
568
919
Costs and expenses:
Segment cost of revenues 153
239
392
Segment operating income before portion attributable to noncontrolling interests and Predecessor 198
329
527
Segment portion attributable to noncontrolling interests and Predecessor 74
36
110
Segment operating income attributable to MPLX LP $ 124
$ 293
$ 417

Nine Months Ended September 30, 2017
(In millions) L&S G&P Total
Revenues and other income:
Segment revenues $ 1,095
$ 1,869
$ 2,964
Segment other income 35
2
37
Total segment revenues and other income 1,130
1,871
3,001
Costs and expenses:
Segment cost of revenues 500
781
1,281
Segment operating income before portion attributable to noncontrolling interests and Predecessor 630
1,090
1,720
Segment portion attributable to noncontrolling interests and Predecessor 53
119
172
Segment operating income attributable to MPLX LP $ 577
$ 971
$ 1,548

Nine Months Ended September 30, 2016
(In millions) L&S G&P Total
Revenues and other income:
Segment revenues $ 901
$ 1,595
$ 2,496
Segment other income 42
1
43
Total segment revenues and other income 943
1,596
2,539
Costs and expenses:
Segment cost of revenues 392
662
1,054
Segment operating income before portion attributable to noncontrolling interests and Predecessor 551
934
1,485
Segment portion attributable to noncontrolling interests and Predecessor 216
113
329
Segment operating income attributable to MPLX LP $ 335
$ 821
$ 1,156

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
Reconciliation to Income from operations:
L&S segment operating income attributable to MPLX LP $ 213
$ 124
$ 577
$ 335
G&P segment operating income attributable to MPLX LP 349
293
971
821
Segment operating income attributable to MPLX LP 562
417
1,548
1,156
Segment portion attributable to unconsolidated affiliates (47 ) (41 ) (125 ) (130 )
Segment portion attributable to Predecessor —
74
53
216
Income (loss) from equity method investments 23
6
29
(72 )
Other income - related parties 13
11
38
29
Unrealized derivative (losses) gains⁽¹⁾
(17 ) (2 ) 2
(23 )
Depreciation and amortization (164 ) (151 ) (515 ) (438 )
Impairment expense —
—
—
(130 )
General and administrative expenses (59 ) (56 ) (174 ) (172 )
Income from operations $ 311
$ 258
$ 856
$ 436

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
Reconciliation to Total revenues and other income:
Total segment revenues and other income $ 1,059
$ 919
$ 3,001
$ 2,539
Revenue adjustment from unconsolidated affiliates (107 ) (100 ) (287 ) (303 )
Income (loss) from equity method investments 23
6
29
(72 )
Other income - related parties 13
11
38
29
Unrealized derivative (losses) gains related to product sales⁽¹⁾
(8 ) 2
1
(12 )
Total revenues and other income $ 980
$ 838
$ 2,782
$ 2,181

~~(1)~~

The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
Reconciliation to Net income attributable to noncontrolling interests and Predecessor:
Segment portion attributable to noncontrolling interests and Predecessor $ 45
$ 110
$ 172
$ 329
Portion of noncontrolling interests and Predecessor related to items below segment income from operations (21 ) (39 ) (84 ) (157 )
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates (23 ) (18 ) (49 ) (20 )
Net income attributable to noncontrolling interests and Predecessor $ 1
$ 53
$ 39
$ 152

The ~~following~~ table ~~reconciles segment capital expenditures~~below provides a reconciliation of Segment Adjusted EBITDA for reportable segments to ~~total capital expenditures:~~Net income.


	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2023		2022		2023		2022
Reconciliation to Net income:
L&S Segment Adjusted EBITDA	$	1,091	$	969	$	3,139	$	2,839
G&P Segment Adjusted EBITDA	505		502		1,507		1,482
Total reportable segments	1,596		1,471		4,646		4,321
Depreciation and amortization(1)	(301)		(302)		(907)		(925)
Gain on sales-type leases	—		509		—		509
Interest and other financial costs	(225)		(236)		(701)		(691)
Income from equity method investments	159		125		438		335
Distributions/adjustments related to equity method investments	(208)		(166)		(551)		(450)
Adjusted EBITDA attributable to noncontrolling interests	11		10		31		29
Garyville incident response costs(2)	(63)		—		(63)		—
Other(3)	(41)		26		(71)		26
Net income	$	928	$	1,437	$	2,822	$	3,154

(1) Depreciation and amortization attributable to L&S was $130 million and $399 million for the three and nine months ended September 30, 2023, respectively, and $128 million and $387 million for the three and nine months ended September 30, 2022, respectively. Depreciation and amortization attributable to G&P was $171 million and $508 million for the three and nine months ended September 30, 2023, respectively, and $174 million and $538 million for the three and nine months ended September 30, 2022, respectively.

(2) In August 2023, a naphtha release and resulting fire occurred at our Garyville Tank Farm resulting in the loss of four storage tanks with a combined shell capacity of 894 thousand barrels. We incurred $63 million of incident response costs during the three and nine months ended September 30, 2023.

(3) Includes unrealized derivative gain/(loss), non-cash equity-based compensation, provision for income taxes, and other miscellaneous items.

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
L&S segment capital expenditures $ 120
$ 188
$ 353
$ 369
G&P segment capital expenditures 333
183
957
668
Total segment capital expenditures 453
371
1,310
1,037
Less: Capital expenditures for Partnership-operated, non-wholly-owned subsidiaries in G&P segment 101
34
306
94
Total capital expenditures $ 352
$ 337
$ 1,004
$ 943

~~Total assets by reportable segment were:~~

(In millions) September 30, 2017 December 31, 2016
Cash and cash equivalents $ 3
$ 234
L&S 4,520
2,978
G&P 14,715
14,297
Total assets $ 19,238
$ 17,509

~~10. Inventories~~

~~Inventories consist of the following:~~

(In millions) September 30, 2017 December 31, 2016
NGLs $ 3
$ 2
Line fill 9
9
Spare parts, materials and supplies 52
44
Total inventories $ 64
$ 55

~~11.~~8. Property, Plant and Equipment

Property, plant and equipment with associated accumulated depreciation is shown below:


	September 30, 2023						December 31, 2022
(In millions)	Gross PP&E		Accumulated Depreciation		Net PP&E		Gross PP&E		Accumulated Depreciation		Net PP&E
L&S	$	12,633	$	3,919	$	8,714	$	12,416	$	3,554	$	8,862
G&P	13,844		3,938		9,906		13,495		3,509		9,986
Total	$	26,477	$	7,857	$	18,620	$	25,911	$	7,063	$	18,848

We capitalize interest as part of the cost of major projects during the construction period. Capitalized interest totaled $4 million and $11 million for the three and nine months ended September 30, 2023, respectively, and $2 million and $7 million for the three and nine months ended September 30, 2022, respectively.

(In millions) September 30, 2017 December 31, 2016
Natural gas gathering and NGL transportation pipelines and facilities $ 5,101
$ 4,748
Processing, fractionation and storage facilities⁽¹⁾
3,753
3,547
Pipelines and related assets 2,181
1,799
Barges and towing vessels 484
479
Terminals and related assets⁽¹⁾
794
759
Land, building, office equipment and other 755
757
Construction-in-progress 986
1,013
Total 14,054
13,102
Less accumulated depreciation 2,132
1,694
Property, plant and equipment, net $ 11,922
$ 11,408

~~12.~~9. Fair Value Measurements

Fair Values – Recurring

~~Fair value measurements and disclosures relate primarily to~~The following table presents the ~~Partnership’s derivative positions as discussed in Note 13. Money market funds, which are included in~~ ~~Cash and cash equivalents~~impact on the Consolidated Balance Sheets ~~are measured at fair value and are included in Level 1 measurements~~ of the valuation hierarchy. Level 2 instruments include crude oil and natural gas swap contracts. Level 3 instruments include all NGL transactions and embedded derivatives in commodity contracts. The following table presents theMPLX’s financial instruments carried at fair value ~~classified by the valuation hierarchy:~~

September 30, 2017 December 31, 2016
(In millions) Assets Liabilities Assets Liabilities
Significant other observable inputs (Level 2)
Commodity contracts $ —
$ —
$ —
$ —
Significant unobservable inputs (Level 3)
Commodity contracts —
(5 ) —
(6 )
Embedded derivatives in commodity contracts —
(52 ) —
(54 )
Total carrying value in Consolidated Balance Sheets $ —
$ (57 ) $ —
$ (60 )

~~The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments~~on a recurring basis as of September 30, ~~2017. The market approach is used for valuation of all instruments.~~2023 and December 31, 2022 by fair value hierarchy level.


	September 30, 2023				December 31, 2022
(In millions)	Asset		Liability		Asset		Liability
Commodity contracts (Level 2)
Other current assets / Other current liabilities	$	2	$	—	$	—	$	—
Embedded derivatives in commodity contracts (Level 3)
Other current assets / Other current liabilities	—		10		—		10
Other noncurrent assets / Other long-term liabilities	—		50		—		51
Total carrying value in Consolidated Balance Sheets	$	2	$	60	$	—	$	61



~~Level 3 Instrument~~	~~Balance Sheet Classification~~	~~Unobservable Inputs~~	~~Value Range~~	~~Time Period~~
~~Commodity contracts~~	~~Liabilities~~	~~Forward ethane prices (per Gal)~~⁽¹⁾	~~$0.27 - $0.28~~	~~Oct. 17 - Dec. 17~~
		~~Forward propane prices (per Gal)~~⁽¹⁾	~~$0.68 - $0.91~~	~~Oct. 17 - Dec. 18~~
		~~Forward isobutane prices (per Gal)~~⁽¹⁾	~~$0.82 - $1.06~~	~~Oct. 17 - Dec. 18~~
		~~Forward normal butane prices (per Gal)~~⁽¹⁾	~~$0.76 - $1.03~~	~~Oct. 17 - Dec. 18~~
		~~Forward natural gasoline prices (per Gal)~~⁽¹⁾	~~$1.18 - $1.22~~	~~Oct. 17 - Dec. 18~~

~~Embedded derivatives in commodity contracts~~	~~Assets~~	~~ERCOT Pricing (per MegaWatt Hour)~~	~~$24.19 - $26.05~~	~~Oct. 17 - Dec. 17~~
	~~Liabilities~~	~~Forward propane prices (per Gal)~~⁽¹⁾	~~$0.61 - $0.91~~	~~Oct. 17 - Dec. 22~~
		~~Forward isobutane prices (per Gal)~~⁽¹⁾	~~$0.75 - $1.06~~	~~Oct. 17 - Dec. 22~~
		~~Forward normal butane prices (per Gal)~~⁽¹⁾	~~$0.69 - $1.03~~	~~Oct. 17 - Dec. 22~~
		~~Forward natural gasoline prices (per Gal)~~⁽¹⁾	~~$1.15 - $1.22~~	~~Oct. 17 - Dec. 22~~
		~~Forward natural gas prices (per MMBtu)~~⁽²⁾	~~$2.30 - $3.11~~	~~Oct. 17 - Dec. 22~~
		~~Probability of renewal~~⁽³⁾	~~50.0%~~
		~~Probability of renewal for second 5-yr term~~⁽³⁾	~~75.0%~~


~~(1)~~	~~NGL prices used in the valuations decrease over time.~~


~~(2)~~	~~Natural gas prices used in the valuations decrease over time.~~

~~(3)~~

The producer counterparty to the embedded derivative has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five-year terms after 2022. The embedded gas purchase agreement cannot be renewed without the renewal of the related keep-whole processing agreement. Due to the significant number of years until the renewal options are exercisable and the high level of uncertainty regarding the counterparty’s future

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~~business strategy,~~Level 2 instruments include over-the-counter fixed swaps to mitigate the ~~future commodity~~ price ~~environment, and the future competitive environment for midstream services~~risk from our sales of propane. The swap valuations are based on observable inputs in the ~~Southern Appalachian region, management determined that~~form of forward prices based on Mont Belvieu propane forward spot prices and contain no significant unobservable inputs.

Level 3 instruments relate to an embedded derivative liability for a 50natural gas purchase commitment embedded in a keep-whole processing agreement. The fair value calculation for these Level 3 instruments used significant unobservable inputs including: (1) NGL prices interpolated and extrapolated due to inactive markets ranging from $0.61 to $1.66 per gallon with a weighted average of $0.79 per gallon and (2) a 100 percent probability of renewal for the ~~first five-year~~five-year renewal term of the gas purchase commitment and ~~75 percent for the second five-year term are appropriate assumptions. Included in this assumption is a further extension of management’s estimates of future frac spreads through 2032.~~

~~Fair Value Sensitivity Related to Unobservable Inputs~~

~~Commodity contracts (assets and liabilities) –~~ ~~For the Partnership’s commodity contracts, increases in forward NGL prices result in a decrease~~related keep-whole processing agreement. Increases or decreases in the fair value of the derivative assets and an increase in the fair value of the derivative liabilities. The forward prices for the individual NGL products generally increase or decrease in a positive correlation with one another.

~~Embedded derivatives in commodity contracts –~~ ~~The Partnership has two embedded derivatives in commodity contracts, as follows:~~

A single embedded derivative liability comprised of both the purchase of natural gas at prices impacted by the frac spread and the probability of contract renewal (the “Natural Gas Embedded Derivative”), as discussed further in Note 13. Increases (decreases) in the fracfractionation spread result in an increase ~~(decrease) in the fair value of the embedded derivative liability. An increase in the probability of renewal would result in an increase in the fair value of the related embedded derivative liability.~~

~~An embedded derivative related to utilities costs discussed further in Note 13. Increases in the forward Electric Reliability Council of Texas (“ERCOT”) prices result in a~~or decrease in the fair value of the embedded derivative ~~liability.~~liability, respectively.

~~Level 3 Valuation Process~~

The Partnership’s Risk Management Department (the “Risk Department”) is responsible for the valuation of the Partnership’s commodity derivative contracts and embedded derivatives in commodity contracts, except for the Natural Gas Embedded Derivative. The Risk Department reports to the Chief Financial Officer and is responsible for the oversight of the Partnership’s commodity risk management program. The members of the Risk Department have the requisite experience, knowledge and day-to-day involvement in the energy commodity markets to ensure appropriate valuations and understand the changes in the valuations from period to period. The valuations of the Level 3 commodity derivative contracts are performed by a third-party pricing service and are reviewed and validated on a quarterly basis by the Risk Department by comparing the pricing and option volatilities to actual market data and/or data provided by at least one other independent third-party pricing service.

Management is responsible for the valuation of the Natural Gas Embedded Derivative discussed in Note 13. Included in the valuation of the Natural Gas Embedded Derivative are assumptions about the forward price curves for NGLs and natural gas for periods in which price curves are not available from third-party pricing services due to insufficient market data. The Risk Department must develop forward price curves for NGLs and natural gas through the initial contract term (October 2017 through December 2022) for management’s use in determining the fair value of the Natural Gas Embedded Derivative. In developing the pricing curves for these periods, the Risk Department maximizes its use of the latest known market data and trends as well as its understanding of the historical relationships between forward NGL and natural gas prices and the forward market data that is available for the required period, such as crude oil pricing and natural gas pricing from other markets. However, there is very limited actual market data available to validate the Risk Department’s estimated price curves. Management also assesses the probability of the producer customer’s renewal of the contracts, which includes consideration of:

The estimated favorability of the contracts to the producer customer as compared to other options that would be available to them at the time and in the relative geographic area of their producing assets;

~~Extrapolated pricing curves, using a weighted average probability method that is based on historical frac spreads, which impact the calculation of favorability; and~~

~~The producer customer’s potential business strategy decision points that may exist at the time the counterparty would elect whether to renew the contracts.~~

Changes in Level 3 Fair Value Measurements

The ~~tables below include~~following table is a ~~rollforward~~reconciliation of the ~~balance sheet amounts~~net beginning and ending balances recorded for ~~the three and nine months ended September 30, 2017 and 2016, respectively (including the change in fair value), for assets and~~net liabilities classified ~~by the Partnership within~~as Level 3 ofin the ~~valuation~~fair value hierarchy.


	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2023		2022		2023		2022

Beginning balance	$	(53)	$	(92)	$	(61)	$	(108)
Unrealized and realized (loss)/gain included in Net Income(1)	(10)		44		(7)		52
Settlements	3		2		8		10

Ending balance	$	(60)	$	(46)	$	(60)	$	(46)

The amount of total (loss)/gain for the period included in earnings attributable to the change in unrealized gain relating to liabilities still held at end of period	$	(9)	$	42	$	(6)	$	50

Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
(In millions) Commodity Derivative Contracts (net) Embedded Derivatives in Commodity Contracts (net) Commodity Derivative Contracts (net) Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period $ 2
$ (43 ) $ (6 ) $ (54 )
Total losses (realized and unrealized) included in earnings⁽¹⁾
(10 ) (12 ) (3 ) (4 )
Settlements 3
3
4
6
Fair value at end of period $ (5 ) $ (52 ) $ (5 ) $ (52 )
The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to liabilities still held at end of period $ (7 ) $ (10 ) $ (4 ) $ (4 )
(1) (Loss)/gain on derivatives embedded in commodity contracts are recorded in Purchased product costs in the Consolidated Statements of Income.

Three Months Ended September 30, 2016 Nine Months Ended September 30, 2016
(In millions) Commodity Derivative Contracts (net) Embedded Derivatives in Commodity Contracts (net) Commodity Derivative Contracts (net) Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period $ (4 ) $ (40 ) $ 7
$ (32 )
Total gains (losses) (realized and unrealized) included in earnings⁽¹⁾
2
(6 ) (5 ) (17 )
Settlements (1 ) 2
(6 ) 5
Netting adjustment⁽²⁾
—
—
1
—
Fair value at end of period $ (3 ) $ (44 ) $ (3 ) $ (44 )
The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to liabilities still held at end of period $ —
$ (4 ) $ (4 ) $ (15 )


~~(1)~~	~~Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in~~ ~~Product sales~~ ~~in the accompanying Consolidated Statements of Income. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in~~ ~~Purchased product costs~~ ~~and~~ ~~Cost of revenues~~.

~~(2)~~

Certain derivative positions are subject to master netting agreements; therefore, the Partnership has elected to offset derivative assets and liabilities where legally permissible. The Partnership may hold positions with certain counterparties, which for GAAP purposes are classified within different levels of the fair value hierarchy and may be legally permissible to offset. This adjustment represents the total impact of offsetting Level 2 positions with Level 3 positions as of September 30, 2016.

Fair Values – Reported

~~The Partnership’s primary~~We believe the carrying value of our other financial instruments, ~~are~~including cash and cash equivalents, receivables, receivables from related parties, lease receivables, lease receivables from related parties, accounts payable, and payables to related parties, ~~and long-term debt. The Partnership’s~~approximate fair value. MPLX’s fair value assessment incorporates a variety of considerations, including ~~(1)~~ the ~~short-term~~ duration of the instruments, ~~(2)~~ MPC’s investment-grade credit rating, and ~~(3)~~ the historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk. ~~The Partnership believes the carrying values of its current assets and liabilities approximate fair value.~~ The recorded value of the amounts outstanding under the bank revolving credit facility, if any, approximates fair value due to the variable interest rate that approximates current market rates. Derivative instruments are recorded at fair value, based on available market information (see Note ~~13)~~10).

The fair value of ~~the Partnership’s long-term~~MPLX’s debt is estimated based on prices from recent ~~market non-binding indicative quotes. The~~trade activity and is categorized in Level 3 of the fair value of the SMR liability is estimated using a discounted cash flow approach based on the contractual cash flows and the Partnership’s unsecured borrowing rate. The long-term debt and SMR liability fair values are considered Level 3 measurements.hierarchy. The following table summarizes the fair value and carrying value of ~~the long-term~~our third-party debt, excluding ~~capital~~finance leases and ~~SMR liability:~~unamortized debt issuance costs:

September 30, 2017 December 31, 2016
(In millions) Fair Value Carrying Value Fair Value Carrying Value
Long-term debt $ 7,619
$ 6,869
$ 4,953
$ 4,422
SMR liability 106
92
108
96


	September 30, 2023				December 31, 2022
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Outstanding debt(1)	$	17,922	$	20,536	$	18,095	$	19,905

~~13. Derivative Financial Instruments~~

~~Commodity Derivatives~~

~~NGL and natural gas prices~~(1) Any amounts outstanding under the MPC Loan Agreement are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond the Partnership’s control. A portion of the Partnership’s profitability is directly affected by prevailing commodity prices primarily as a result of processing or conditioning at its own or third-party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party transportation and fractionation services. To the extent that commodity prices influence the level of natural gas drilling by the Partnership’s producer customers, such prices also affect profitability. To protect itself financially against adverse price movements and to maintain more stable and predictable cash flows so that the Partnership can meet its cash distribution objectives, debt service and capital plans, the Partnership executes a strategy governed by its risk management policy. The Partnership has a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts its strategy as conditions warrant. The Partnership enters into certain derivative contracts to reduce the risks associated with unfavorable changesnot included in the ~~prices of natural gas and NGLs. Derivative contracts utilized are swaps traded on~~table above, as the ~~OTC market and fixed price forward contracts. The risk management policy does not allow the Partnership to take speculative positions with its derivative contracts.~~

~~To mitigate its cash flow exposure to fluctuations~~carrying value approximates fair value. This balance is reflected in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude oil. The Partnership currently manages the majority of its NGL price risk using direct product NGL derivative contracts. The Partnership enters into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory. A portion of the Partnership’s NGL price exposure is managed by using crude oil contracts. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the crude oil contracts create increased risk and additional gains or losses. The Partnership may settle its crude oil contracts prior to the contractual settlement date in order to take advantage of favorable terms and reduce the future exposure resulting from the less effective crude oil contracts. Based on its current volume forecasts, the majority of its derivative positions used to manage the future commodity price exposure are expected to be direct product NGL derivative contracts.

To mitigate its cash flow exposure to fluctuations in the price of natural gas, the Partnership primarily utilizes derivative financial instruments relating to the future price of natural gas and takes into account the partial offset of its long and short gas positions resulting from normal operating activities.

As a result of its current derivative positions, the Partnership has mitigated a portion of its expected commodity price risk through the fourth quarter of 2018. The Partnership would be exposed to additional commodity risk in certain situations such as if producers under-deliver or over-deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.

Management conducts a standard credit review on counterparties to derivative contracts and has provided the counterparties with a guaranty as credit support for its obligations. A separate agreement with certain counterparties allows MarkWest Liberty Midstream to enter into derivative positions without posting cash collateral. The Partnership uses standardized agreements that allow for offset of certain positive and negative exposures (“master netting arrangements”) in the event of default or other terminating events, including bankruptcy.

~~The Partnership records derivative contracts at fair value~~Current liabilities - related parties in the Consolidated Balance ~~Sheets and has not elected hedge accounting or the normal purchases and normal sales designation (except for electricity and certain other qualifying contracts,~~Sheets.

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10. Derivatives

As of September 30, 2023, MPLX had the following outstanding commodity contracts that were executed to manage the price risk associated with sales of propane during 2023:

Derivative contracts not designated as hedging instruments

Financial Position

Notional Quantity

Propane (gallons)

Short

16,827,000

Embedded Derivative - MPLX has a natural gas purchase commitment embedded in a keep-whole processing agreement with a producer customer in the Southern Appalachian region expiring in December 2027. The customer has the unilateral option to extend the agreement for ~~which~~one five-year term through December 2032. For accounting purposes, the ~~normal purchases~~natural gas purchase commitment and ~~normal sales designation has~~the term extending option have been ~~elected).~~aggregated into a single compound embedded derivative. The ~~Partnership’s accounting~~probability of the customer exercising its option is determined based on assumptions about the customer’s potential business strategy decision points that may ~~cause volatility~~exist at the time they would elect whether to renew the contract. The changes in fair value of this compound embedded derivative are based on the difference between the contractual and index pricing, the probability of the producer customer exercising its option to extend, and the estimated favorability of these contracts compared to current market conditions. The changes in fair value are recorded in earnings through Purchased product costs in the Consolidated Statements of ~~Income as~~Income. For further information regarding the ~~Partnership recognizes all unrealized gains~~fair value measurement of derivative instruments, see Note 9. As of September 30, 2023 and ~~losses from~~December 31, 2022, the ~~changes in~~estimated fair value of ~~derivatives~~this contract was a liability of $60 million and $61 million, respectively.

Certain derivative positions are subject to master netting agreements; therefore, MPLX has elected to offset derivative assets and liabilities that are legally permissible to be offset. As of September 30, 2023 and December 31, 2022, there were no derivative assets or liabilities that were offset in ~~current earnings. The Partnership makes~~the Consolidated Balance Sheets.

We make a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed, and the realized gain or loss of the contract is recorded.

~~Volume of Commodity Derivative Activity~~

As of September 30, 2017, the Partnership had the following outstanding commodity contracts that were executed to manage the cash flow risk associated with future sales of NGLs and purchases of natural gas:



~~Derivative contracts not designated as hedging instruments~~	~~Financial Position~~	~~Notional Quantity (net)~~
~~Crude Oil (bbl)~~	~~Short~~	~~18,400~~
~~Natural Gas (MMBtu)~~	~~Long~~	~~1,096,539~~
~~NGLs (gal)~~	~~Short~~	~~33,387,904~~

~~Embedded Derivatives in Commodity Contracts~~

The Partnership has a commodity contract with a producer customer in the Southern Appalachian region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. For accounting purposes, these contracts have been aggregated into a single contract and are evaluated together. In February 2011, the Partnership executed agreements with the producer customer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022, with the producer customer’s option to extend the agreement for two successive five-year terms through December 31, 2032. The purchase of gas at prices based on the frac spread and the option to extend the agreements have been identified as a single embedded derivative, which is recorded at fair value. The probability of renewal is determined based on extrapolated pricing curves, a review of the overall expected favorability of the contracts based on such pricing curves and assumptions about the counterparty’s potential business strategy decision points that may exist at the time the counterparty would elect whether to renew the contract. The changes in fair value of this embedded derivative are based on the difference between the contractual and index pricing, the probability of the producer customer exercising its option to extend and the estimated favorability of these contracts compared to current market conditions. The changes in fair value are recorded in earnings through ~~Purchased product costs~~ ~~in the Consolidated Statements of Income. As of September 30, 2017 and December 31, 2016, the estimated fair value of this contract was a liability of $52 million and $54 million, respectively.~~

The Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at a plant location in the Southwest through the fourth quarter of 2018. The contract’s pricing is currently fixed through the fourth quarter of 2017 with the ability to fix the pricing for its remaining year. Changes in the fair value as of the derivative component of this contract were recognized as ~~Cost of Revenues~~ ~~in the Consolidated Statements of Income. As of September 30, 2017, the estimated fair value of this contract was a liability of less than $1 million.~~

~~Financial Statement Impact of Derivative Contracts~~

There were no material changes to the Partnership’s policy regarding the accounting for these instruments as previously disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016, as updated by our Current Report on Form 8-K filed on May 1, 2017. The impact of ~~the Partnership’s derivative instruments on its Consolidated Balance Sheets is summarized below:~~

(In millions) September 30, 2017 December 31, 2016
Derivative contracts not designated as hedging instruments and their balance sheet location Asset Liability Asset Liability
Commodity contracts⁽¹⁾

Other current assets / other current liabilities $ —
$ (15 ) $ —
$ (13 )
Other noncurrent assets / deferred credits and other liabilities —
(42 ) —
(47 )
Total $ —
$ (57 ) $ —
$ (60 )


~~(1)~~	~~Includes embedded derivatives in commodity contracts as discussed above.~~

Certain derivative positions are subject to master netting agreements, therefore the Partnership has elected to offset derivative assets and liabilities that are legally permissible to be offset. The net amounts in the table below equal the balances presented in the Consolidated Balance Sheets:

September 30, 2017
Assets Liabilities
(In millions) Gross Amount Gross Amounts Offset in the Consolidated Balance Sheets Net Amount of Assets in the Consolidated Balance Sheets Gross Amount Gross Amounts Offset in the Consolidated Balance Sheets Net Amount of Liabilities in the Consolidated Balance Sheets
Current
Commodity contracts $ —
$ —
$ —
$ (5 ) $ —
$ (5 )
Embedded derivatives in commodity contracts —
—
—
(10 ) —
(10 )
Total current derivative instruments —
—
—
(15 ) —
(15 )
Non-current
Commodity contracts —
—
—
—
—
—
Embedded derivatives in commodity contracts —
—
—
(42 ) —
(42 )
Total non-current derivative instruments —
—
—
(42 ) —
(42 )
Total derivative instruments $ —
$ —
$ —
$ (57 ) $ —
$ (57 )

In the table above, the Partnership does not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although the Partnership’s master netting arrangements would allow current and non-current positions to be offset in the event of default. Additionally, in the event of default, the Partnership’s master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions and other forms of non-cash collateral (such as letters of credit).

~~The impact of the Partnership’s~~MPLX’s derivative contracts not designated as hedging instruments and the location of ~~gain or (loss)~~gains and losses recognized in the Consolidated Statements of Income is summarized below:


	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2023		2022		2023		2022
Product sales:
Realized gain	$	3	$	—	$	3	$	—
Unrealized (loss)/gain	(8)		—		2		—
Product sales derivative (loss)/gain	(5)		—		5		—
Purchased product costs:
Realized loss	(3)		(2)		(8)		(10)
Unrealized (loss)/gain	(7)		46		1		62
Purchased produce cost derivative (loss)/gain	(10)		44		(7)		52





Total derivative (loss)/gain included in Net income	$	(15)	$	44	$	(2)	$	52

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
Product sales
Realized (loss) gain $ (2 ) $ —
$ (3 ) $ 6
Unrealized (loss) gain (8 ) 2
1
(12 )
Total derivative (loss) gain related to product sales (10 ) 2
(2 ) (6 )
Purchased product costs
Realized loss⁽¹⁾
(2 ) (1 ) (6 ) (4 )
Unrealized (loss) gain (9 ) (3 ) 1
(12 )
Total derivative loss related to purchased product costs (11 ) (4 ) (5 ) (16 )
Cost of revenues
Realized loss⁽¹⁾
—
—
—
(2 )
Unrealized (loss) gain —
(1 ) —
1
Total derivative loss related to cost of revenues —
(1 ) —
(1 )
Total derivative losses $ (21 ) $ (3 ) $ (7 ) $ (23 )


~~(1)~~	~~Certain prior period amounts have been updated to conform to current period presentation.~~

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~~14.~~11. Debt

~~The Partnership’s~~MPLX’s outstanding borrowings ~~consisted~~consist of the following:

(In millions) September 30, 2017 December 31, 2016
MPLX LP:
Bank revolving credit facility due 2022 $ 420
$ —
Term loan facility due 2019 —
250
5.500% senior notes due February 2023 710
710
4.500% senior notes due July 2023 989
989
4.875% senior notes due December 2024 1,149
1,149
4.000% senior notes due February 2025 500
500
4.875% senior notes due June 2025 1,189
1,189
4.125% senior notes due March 2027 1,250
—
5.200% senior notes due March 2047 1,000
—
Consolidated subsidiaries:
MarkWest - 4.500% - 5.500% senior notes, due 2023-2025 63
63
MPL - capital lease obligations due 2020 7
8
Total 7,277
4,858
Unamortized debt issuance costs (27 ) (7 )
Unamortized discount (401 ) (428 )
Amounts due within one year (1 ) (1 )
Total long-term debt due after one year $ 6,848
$ 4,422


(In millions)	September 30, 2023		December 31, 2022
MPLX LP:

MPLX Credit Agreement	$	—	$	—






























Fixed rate senior notes	20,657		20,046
Consolidated subsidiaries:
MarkWest	12		23
ANDX	31		31

Finance lease obligations	7		8
Total	20,707		20,108
Unamortized debt issuance costs	(125)		(117)
Unamortized discount	(164)		(195)
Amounts due within one year	(1)		(988)
Total long-term debt due after one year	$	20,417	$	18,808

Credit ~~Agreements~~Agreement

~~On July 21, 2017, the Partnership entered into a syndicated~~MPLX’s credit agreement ~~to replace its previously outstanding $2.0~~(the “MPLX Credit Agreement”) matures in July 2027 and, among other things, provides for a $2 billion ~~five-year bank~~unsecured revolving credit facility ~~with a $2.25~~and letter of credit issuing capacity under the facility of up to $150 million. Letter of credit issuing capacity is included in, not in addition to, the $2 billion ~~five-year bank revolving credit facility that expires in July 2022 (the “MPLX~~borrowing capacity. Borrowings under the MPLX Credit Agreement ~~2022”). The financial covenants and~~bear interest, at MPLX’s election, at either the ~~interest rate terms contained~~Adjusted Term SOFR or the Alternate Base Rate, both as defined in the ~~new credit agreement are substantially~~MPLX Credit Agreement, plus an applicable margin.

There was no activity on the ~~same as those contained in the previous bank revolving credit facility. During~~MPLX Credit Agreement during the nine months ended September 30, ~~2017, the Partnership had no borrowings under the previous bank revolving credit facility. During the nine months ended September 30, 2017, the Partnership borrowed$420 million under the MPLX Credit Agreement 2022, at an average interest rate of 2.702 percent~~. At September 30, 2017, the Partnership had $420 million outstanding borrowings and $3 million letters of credit outstanding under the new facility, resulting in total availability of $1.827 billion, or 81.2 percent of the borrowing capacity.2023.

The $250 million term loan facility was drawn in full on November 20, 2014. On July 19, 2017, MPLX LP prepaid the entire outstanding principal of this loan facility with cash on hand. The borrowings under this facility between January 1, 2017 and July 19, 2017 were at an average interest rate of 2.407 percent.

Fixed Rate Senior Notes

~~On February 10, 2017, the Partnership completed a public offering of $2.25 billion aggregate principal amount of unsecured~~MPLX’s senior notes, ~~consisting~~including those issued by consolidated subsidiaries, consist of ~~(i) $1.25 billion aggregate principal amount~~various series of ~~4.125 percent~~ senior notes ~~due in March 2027~~maturing between 2024 and ~~(ii) $1.0 billion aggregate principal amount of 5.200~~2058 with interest rates ranging from 1.750 percent senior notes due in March 2047 (collectively, the “New Senior Notes”). The net proceeds from the New Senior Notes totaled approximately $2.22 billion, after deducting underwriting discounts, and were used for general partnership purposes and capital expenditures.to 5.650 percent. Interest on each series of ~~the~~ notes is payable semi-annually in arrears on ~~March 1~~various dates depending on the series of the notes.

On February 9, 2023, MPLX issued $1.6 billion aggregate principal amount of notes, consisting of $1.1 billion principal amount of 5.00 percent senior notes due 2033 (the “2033 Senior Notes”) and ~~September 1,~~$500 million principal amount of 5.65 percent senior notes due 2053 (the “2053 Senior Notes”). The 2033 Senior Notes were offered at a price to the public of 99.170 percent of par with interest payable semi-annually in arrears, commencing on September 1, ~~2017.~~2023. The 2053 Senior Notes were offered at a price to the public of 99.536 percent of par with interest payable semi-annually in arrears, commencing on September 1, 2023.

On February 15, 2023, MPLX used $600 million of the net proceeds from the offering of the 2033 Senior Notes and 2053 Senior Notes described above to redeem all of the outstanding Series B preferred units. On March 13, 2023, MPLX used the remaining proceeds from the offering, and cash on hand, to redeem all of MPLX’s and MarkWest’s $1.0 billion aggregate principal amount of 4.50 percent senior notes due July 2023, at par, plus accrued and unpaid interest. The redemption resulted in a loss of $9 million due to the immediate expense recognition of unamortized debt discount and issuance costs for the three months ended March 31, 2023, which is included on the Consolidated Statements of Income as Other financial costs, net.

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12. Revenue

~~15.~~

Disaggregation of Revenue

The following tables represent a disaggregation of revenue for each reportable segment for the three and nine months ended September 30, 2023 and September 30, 2022:


	Three Months Ended September 30, 2023
(In millions)	L&S		G&P		Total
Revenues and other income:
Service revenue	$	97	$	544	$	641
Service revenue - related parties	1,033		5		1,038
Service revenue - product related	—		75		75
Product sales	2		476		478
Product sales - related parties	4		47		51
Total revenues from contracts with customers	$	1,136	$	1,147	2,283
Non-ASC 606 revenue(1)					629
Total revenues and other income					$	2,912


	Three Months Ended September 30, 2022
(In millions)	L&S		G&P		Total
Revenues and other income:
Service revenue	$	94	$	533	$	627
Service revenue - related parties	944		4		948
Service revenue - product related	—		83		83
Product sales	2		615		617
Product sales - related parties	2		44		46
Total revenues from contracts with customers	$	1,042	$	1,279	2,321
Non-ASC 606 revenue(1)					1,080
Total revenues and other income					$	3,401


	Nine Months Ended September 30, 2023
(In millions)	L&S		G&P		Total
Revenues and other income:
Service revenue	$	272	$	1,609	$	1,881
Service revenue - related parties	2,951		11		2,962
Service revenue - product related	—		214		214
Product sales	4		1,270		1,274
Product sales - related parties	10		145		155
Total revenues from contracts with customers	$	3,237	$	3,249	6,486
Non-ASC 606 revenue(1)					1,829
Total revenues and other income					$	8,315


	Nine Months Ended September 30, 2022
(In millions)	L&S		G&P		Total
Revenues and other income:
Service revenue	$	243	$	1,515	$	1,758
Service revenue - related parties	2,788		13		2,801
Service revenue - product related	—		324		324
Product sales	5		1,807		1,812
Product sales - related parties	10		132		142
Total revenues from contracts with customers	$	3,046	$	3,791	6,837
Non-ASC 606 revenue(1)					2,114
Total revenues and other income					$	8,951

(1) Non-ASC 606 Revenue includes rental income, sales-type lease revenue, income from equity method investments, and other income.

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Contract Balances

Our receivables are primarily associated with customer contracts. Payment terms vary by product or service type; however, the period between invoicing and payment is not significant. Included within the receivables are balances related to commodity sales on behalf of our producer customers, for which we remit the net sales price back to the producer customers upon completion of the sale. These balances are included in Receivables, net on the Consolidated Balance Sheets.

Under certain of our contracts, we recognize revenues in excess of billings which we present as contract assets. Contract assets typically relate to deficiency payments related to minimum volume commitments and aid in construction agreements where the revenue recognized and MPLX’s rights to consideration for work completed exceeds the amount billed to the customer. Contract assets are included in Other current assets and Other noncurrent assets on the Consolidated Balance Sheets.

Under certain of our contracts, we receive payments in advance of satisfying our performance obligations, which are recorded as contract liabilities. Contract liabilities, which we present as Deferred revenue and Long-term deferred revenue, typically relate to advance payments for aid in construction agreements and deferred customer credits associated with makeup rights and minimum volume commitments. Related to minimum volume commitments, breakage is estimated and recognized into service revenue in instances where it is probable the customer will not use the credit in future periods. We classify contract liabilities as current or long-term based on the timing of when we expect to recognize revenue.

The tables below reflect the changes in ASC 606 contract balances for the nine-month periods ended September 30, 2023 and September 30, 2022:


(In millions)	Balance at December 31, 2022		Additions/ (Deletions)		Revenue Recognized(1)		Balance at September 30, 2023
Contract assets	$	21	$	(19)	$	—	$	2
Long-term contract assets	1		—		—		1
Deferred revenue	57		24		(31)		50
Deferred revenue - related parties	63		63		(72)		54
Long-term deferred revenue	216		76		—		292
Long-term deferred revenue - related parties	25		5		—		30

Long-term contract liabilities	$	2	$	(2)	$	—	$	—


(In millions)	Balance at December 31, 2021		Additions/ (Deletions)		Revenue Recognized(1)		Balance at September 30, 2022
Contract assets	$	25	$	(9)	$	—	$	16
Long-term contract assets	2		—		—		2
Deferred revenue	56		40		(33)		63
Deferred revenue - related parties	60		79		(83)		56
Long-term deferred revenue	135		27		—		162
Long-term deferred revenue - related parties	31		(5)		—		26
Long-term contract liabilities	$	5	$	(1)	$	—	$	4

(1) No significant revenue was recognized related to past performance obligations in the current periods.

Remaining Performance Obligations

The table below includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied (or partially unsatisfied) as of September 30, 2023. The amounts presented below are generally limited to fixed consideration from contracts with customers that contain minimum volume commitments.

A significant portion of our future contracted revenue is excluded from the amounts presented below in accordance with ASC 606. Variable consideration that is constrained or not required to be estimated as it reflects our efforts to perform is excluded from this disclosure. Additionally, we do not disclose information on the future performance obligations for any contract with an original expected duration of one year or less, or that are terminable by our customer with little or no termination penalties. Potential future performance obligations related to renewals that have not yet been exercised or are not certain of exercise are

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excluded from the amounts presented below. Revenues classified as Rental income and Sales-type lease revenue are also excluded from this table.


(In billions)
2023	$	0.5
2024	2.0
2025	1.9
2026	1.7
2027	1.6
Thereafter	1.0
Total estimated revenue on remaining performance obligations	$	8.7

As of September 30, 2023, unsatisfied performance obligations included in the Consolidated Balance Sheets are $426 million and will be recognized as revenue as the obligations are satisfied, which is expected to occur over the next 20 years. A portion of this amount is not disclosed in the table above as it is deemed variable consideration due to volume variability.

13. Supplemental Cash Flow Information


	Nine Months Ended September 30,
(In millions)	2023		2022
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	724	$	642
Income taxes paid	4		2





Non-cash investing and financing activities:
Net transfers of property, plant and equipment (to)/from materials and supplies inventories	8		—
Net transfers of property, plant and equipment to lease receivable	$	86	$	20

Nine Months Ended September 30,
(In millions) 2017 2016
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized) $ 207
$ 158
Non-cash investing and financing activities:
Net transfers of property, plant and equipment from materials and supplies inventories $ 6
$ (4 )
Contribution of fixed assets to joint venture⁽¹⁾
337
—


~~(1)~~	~~Contribution of assets to Sherwood Midstream and Sherwood Midstream Holdings. See Note 4.~~

The Consolidated Statements of Cash Flows exclude changes to the Consolidated Balance Sheets that ~~did~~do not affect cash. The following is ~~the change~~a reconciliation of additions to property, plant and equipment to total capital expenditures:


	Nine Months Ended September 30,
(In millions)	2023		2022
Additions to property, plant and equipment	$	662	$	535
Increase in capital accruals	6		39

Total capital expenditures	$	668	$	574

14. Leases

During the third quarter of 2022, the approved expansion of a gathering and compression system triggered the first assessment of the related third-party agreement under ASC 842. Similarly, an amendment to ~~capital accruals:~~extend the term of our butane storage service agreement with MPC triggered the first assessment of the related-party agreement under ASC 842. As a result of the assessments during the third quarter of 2022, the leases were reclassified from operating leases to sales-type leases. Accordingly, the underlying property, plant and equipment, net, and associated deferred revenue, if any, were derecognized. The present value of the future lease payments and the unguaranteed residual value of the assets were recorded as a net investment in sales-type lease during the period.

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Nine Months Ended September 30,
(In millions) 2017 2016
Increase in capital accruals $ 55
$ —

~~16. Equity-Based Compensation~~

~~Phantom Units~~ – The following ~~is a summary of phantom unit award activity of MPLX LP common units for~~presents the ~~nine~~ ~~months ended~~ ~~September 30, 2017~~:

Number
of Units Weighted
Average
Fair Value
Outstanding at December 31, 2016 1,173,411
$ 33.09
Granted 653,721
36.36
Settled (288,584 ) 33.50
Forfeited (113,107 ) 34.59
Outstanding at September 30, 2017 1,425,441
34.39

~~Performance Units~~ ~~– The Partnership grants performance units under the MPLX LP 2012 Incentive Compensation Plan to certain officers~~consolidated financial statement impact of the ~~general partner and certain eligible~~sales-type lease modifications discussed above. These transactions, including any related gains recognized in the Consolidated Statements of Income, were non-cash transactions.


	Three Months Ended September 30, 2022
(In millions)		Related Party(1)		Third Party(2)
Lease receivables		$	79	$	914
Unguaranteed residual assets		6		63
Property, plant and equipment, net		(42)		(745)
Deferred revenue		—		277
Amount recognized on commencement date		$	43	$	509

(1) The amount recognized on commencement date was recorded as a Contribution from MPC ~~officers who make significant contributions to its business. These performance units pay out 75 percent~~ in ~~cash and 25 percent~~the Consolidated Statements of Equity given the underlying agreements are between entities under common control.

(2) The amount recognized on commencement date was recorded as a gain in ~~MPLX LP common units. The performance units paying out~~Other income in ~~units are accounted for as equity awards. The performance units granted in 2017 are hybrid awards having a three-year performance period~~the Consolidated Statements of January 1, 2017 through December 31, 2019. The payout of the award is dependent on two independent conditions, each constituting 50 percent of the overall target units granted. The awards have a performance condition based on MPLX LP’s DCF during the last twelve months of the performance period, and a market condition based on MPLX LP’s total unitholder return over the entire three-year performance period. The market condition was valued using a Monte Carlo valuation, with the result being combined with the expected payout of the performance condition as of the grant date, resulting in a grant date fair value of $0.90 for the 2017 equity-classified performance units.Income.

~~The following is a summary of the equity-classified performance unit award activity for the~~ ~~nine~~ ~~months ended~~ ~~September 30, 2017~~:



	~~Number of~~ ~~Units~~
~~Outstanding at December 31, 2016~~	~~1,799,249~~
~~Granted~~	~~1,407,062~~
~~Settled~~	~~(464,500~~	)
~~Forfeited~~	~~(35,217~~	)
~~Outstanding at September 30, 2017~~	~~2,706,594~~

~~17.~~15. Commitments and Contingencies

~~The Partnership~~MPLX is the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Some of these matters are discussed below. For matters for which ~~the Partnership~~MPLX has not recorded ~~an accrued~~a liability, ~~the Partnership~~MPLX is unable to estimate a range of possible ~~losses for~~loss because the ~~reasons discussed in more detail below.~~issues involved have not been fully developed through pleadings, discovery or court proceedings. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material.

Environmental Matters ~~– The Partnership~~

MPLX is subject to federal, state and local laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for non-compliance.

~~At September 30, 2017 and December 31, 2016, accrued~~Accrued liabilities for remediation totaled ~~$14~~$23 million at September 30, 2023 and $3$17 million ~~respectively. However, it~~ December 31, 2022. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties, if any, ~~which~~that may be imposed. At December 31, 2016, there was less than $1 million in receivables from MPC for indemnification of environmental costs related to incidents occurring prior to the Initial Offering. There were no such receivables at September 30, 2017.

In July 2015, representatives from the EPA and the United States Department of Justice conducted a raid on a MarkWest Liberty Midstream pipeline launcher/receiver site utilized for pipeline maintenance operations in Washington County, Pennsylvania pursuant to a search warrant issued by a magistrate of the United States District Court for the Western District of Pennsylvania. As part of this initiative, the U.S. Attorney’s Office for the Western District of Pennsylvania proceeded with an investigation of MarkWest Liberty Midstream’s launcher/receiver, pipeline and compressor station operations. In response to the investigation, MarkWest initiated independent studies which demonstrated that there was no risk to worker safety and no threat of public harm associated with MarkWest Liberty Midstream’s launcher/receiver operations. These findings were supported by a subsequent inspection and review by the Occupational Safety and Health Administration. After providing these studies, and other substantial documentation related to MarkWest Liberty Midstream's pipeline and compressor stations, and arranging site visits and conducting several meetings with the government’s representatives, on September 13, 2016, the U.S. Attorney’s Office for the Western District of Pennsylvania rendered a declination decision, dropping its criminal investigation and declining to pursue charges in this matter.

MarkWest Liberty Midstream continues to discuss with the EPA and the State of Pennsylvania civil enforcement allegations associated with permitting or other related regulatory obligations for its launcher/receiver and compressor station facilities in the region. In connection with these discussions, MarkWest Liberty Midstream received an initial proposal from the EPA to settle all civil claims associated with this matter for the combination of a proposed cash penalty of approximately $2.4 million and proposed supplemental environmental projects with an estimated cost of approximately $3.6 million. MarkWest Liberty Midstream has submitted a response asserting that this action involves novel issues surrounding primarily minor source emissions from facilities that the agencies themselves considered de minimis and were not the subject of regulation and consequently that the settlement proposal is excessive. In connection with these negotiations, MarkWest Liberty Midstream has received a revised settlement proposal from the EPA which proposes to lower the proposed cash penalty to approximately $1.24 million and the estimated cost of proposed supplemental environmental projects to an estimated cost of approximately $1.6 million. MarkWest Liberty Midstream will continue to negotiate with EPA regarding the amount and scope of the proposed settlement.

~~The Partnership~~MPLX is involved in ~~a number of other~~ environmental enforcement matters arising in the ordinary course of business. While the outcome and impact onto MPLX LP cannot be predicted with certainty, management believes the resolution of these environmental matters will not, individually or collectively, have a material adverse effect on its consolidated results of operations, financial position or cash flows.

Other ~~Lawsuits~~ – Legal Proceedings

In ~~2003,~~July 2020, Tesoro High Plains Pipeline Company, LLC (“THPP”), a subsidiary of MPLX, received a Notification of Trespass Determination from the ~~State~~Bureau of ~~Illinois brought~~Indian Affairs (“BIA”) relating to a portion of the Tesoro High Plains Pipeline that crosses the Fort Berthold Reservation in North Dakota. The notification demanded the immediate cessation of pipeline operations and assessed trespass damages of approximately $187 million. After subsequent appeal proceedings and in compliance with a new order issued by the BIA, in December 2020, THPP paid approximately $4 million in assessed trespass damages and ceased use of the portion of the pipeline that crosses the property at issue. In March 2021, the BIA issued an ~~action~~order purporting to vacate the BIA's prior orders related to THPP’s alleged trespass and direct the Regional Director of the BIA to reconsider the issue of THPP’s alleged trespass and issue a new order. In April 2021, THPP filed a lawsuit in the District of North Dakota against the ~~Premcor Refining Group, Inc. (“Premcor”~~United States of America, the U.S. Department of the Interior and the BIA (together, the “U.S. Government Parties”) ~~and Apex Refining Company (“Apex”) asserting claims for environmental cleanup~~challenging the March 2021 order purporting to vacate all previous orders related to THPP’s alleged trespass. On February 8, 2022, the ~~refinery owned by these entities~~U.S. Government Parties filed their answer and counterclaims to THPP’s suit claiming THPP is in the Hartford/Wood River, Illinois area. In 2006, Premcor and Apex filed third-party complaints against numerous owners and operators of petroleum products facilities in the Hartford/Wood River, Illinois area, including Marathon Pipe Line LLC (“MPL”). These complaints, which have been amended since filing, assert claims of common law nuisance and contribution under the Illinois Contribution Act and other laws for environmental cleanup costs that may be imposed on Premcor and Apex by the State of Illinois. On September 6, 2016, the trial court approved a settlement between Apex and the State of Illinois whereby Apex agreed to settle all claims against it for a $10 million payment. Premcor has objected to this ruling and is seeking an appeal. There are several third-party defendants in the litigation and MPL has asserted cross-claims in contribution against the various third-party defendants. This litigation is currently pending in the Third Judicial Circuit Court, Madison County,

~~Illinois. While the ultimate outcome of these litigated matters remains uncertain, neither the likelihood of an unfavorable outcome nor the ultimate liability, if any,~~continued trespass with respect to ~~this matter can be determined at this time~~the pipeline and seeking disgorgement of pipeline profits from June 1, 2013 to present, removal of the ~~Partnership is unable~~pipeline and remediation. We intend to estimate a reasonably possible loss (or range of losses) for this litigation. Under the omnibus agreement, MPC will indemnify the Partnership for the full cost of any losses should MPL be deemed responsible for any damages in this lawsuit.vigorously defend ourselves against these counterclaims.

~~The Partnership~~MPLX is also a party to a number of other lawsuits and other proceedings arising in the ordinary course of business. While the ultimate outcome and impact to ~~the Partnership~~MPLX cannot be predicted with certainty, ~~the Partnership~~management believes the resolution of these other lawsuits and proceedings will not, individually or collectively, have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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Guarantees ~~– Over~~ related to indebtedness of equity method investees

We hold a 9.19 percent indirect interest in Dakota Access, which owns and operates the ~~years,~~Bakken Pipeline system. In 2020, the ~~Partnership~~U.S. District Court for the District of Columbia (the “D.D.C.”) ordered the U.S. Army Corps of Engineers (“Army Corps”), which granted permits and an easement for the Bakken Pipeline system, to prepare an environmental impact statement (“EIS”) relating to an easement under Lake Oahe in North Dakota. The D.D.C. later vacated the easement. The Army Corps issued a draft EIS in September 2023 detailing various options for the easement going forward, including denying the easement, approving the easement with additional measures, rerouting the easement, or approving the easement with no changes. The Army Corps has ~~sold various assets~~not selected a preferred alternative, but will make a decision in its final review, after considering input from the public and other agencies. The Army Corps has not provided a definitive date as to when a final decision would be issued.

In May 2021, the D.D.C. denied a renewed request for an injunction to shut down the pipeline while the EIS is being prepared. In June 2021, the D.D.C. issued an order dismissing without prejudice the tribes’ claims against the Dakota Access Pipeline. The litigation could be reopened or new litigation challenging the EIS, once completed, could be filed. The pipeline remains operational.

We have entered into a Contingent Equity Contribution Agreement whereby MPLX LP, along with the other joint venture owners in the ~~normal course~~Bakken Pipeline system, has agreed to make equity contributions to the joint venture upon certain events occurring to allow the entities that own and operate the Bakken Pipeline system to satisfy their senior note payment obligations. The senior notes were issued to repay amounts owed by the pipeline companies to fund the cost of ~~its business. Certain~~construction of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that requireBakken Pipeline system.

If the ~~Partnership to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part~~vacatur of the ~~normal course~~easement results in a temporary shutdown of ~~selling assets. The Partnership~~the pipeline, MPLX would have to contribute its 9.19 percent pro rata share of funds required to pay interest accruing on the notes and any portion of the principal that matures while the pipeline is ~~typically not able~~shutdown. MPLX also expects to ~~calculate~~contribute its 9.19 percent pro rata share of any costs to remediate any deficiencies to reinstate the easement and/or return the pipeline into operation. If the vacatur of the easement results in a permanent shutdown of the pipeline, MPLX would have to contribute its 9.19 percent pro rata share of the cost to redeem the bonds (including the one percent redemption premium required pursuant to the indenture governing the notes) and any accrued and unpaid interest. As of September 30, 2023, our maximum potential ~~amount of future~~undiscounted payments ~~that could be made~~ under ~~such contractual provisions because of~~ the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.Contingent Equity Contribution Agreement were approximately $170 million.

Contractual Commitments and Contingencies – At September 30, 2017, the Partnership’s contractual commitments to acquire property, plant and equipment totaled $520 million. These commitments at September 30, 2017 were primarily related to plant expansion projects for the Marcellus and Southwest Operations. In addition, from

From time to time and in the ordinary course of business, ~~the Partnership~~MPLX and its affiliates provide guarantees of ~~the Partnership’s~~MPLX’s subsidiaries payment and performance obligations in the G&P segment. Certain natural gas processing and gathering arrangements require ~~the Partnership~~MPLX to construct new natural gas processing plants, natural gas gathering pipelines and NGL pipelines and contain certain fees and charges if specified construction milestones are not achieved for reasons other than force majeure. In certain cases, certain producers may have the right to cancel the processing arrangements if there are significant delays that are not due to force majeure. As of September 30, ~~2017,~~2023, management does not believe there are any indications that ~~the Partnership~~MPLX will not be able to meet the construction milestones, that force majeure does not apply or that such fees and charges will otherwise be triggered.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations should also be read in conjunction with the unaudited consolidated financial statements and accompanying footnotes included under Item 1. Financial Statements and in conjunction with our Annual Report on Form 10-K for the year ended December 31, ~~2016, as updated by our Current~~2022.

Disclosures Regarding Forward-Looking Statements

This Quarterly Report on Form ~~8-K filed on May 1, 2017.~~

10-Q, particularly Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures about Market Risk, includes ~~various~~ forward-looking statements ~~concerning trends~~that are subject to risks, contingencies or ~~events potentially affecting our business.~~uncertainties. You can identify ~~our~~ forward-looking statements by words such as “anticipate,” “believe,” ~~“estimate,~~“commitment,” ~~“objective,~~“could,” “design,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “opportunity,” “outlook,” “plan,” “policy,” “position,” “potential,” “predict,” “priority,” “project,” ~~“potential,~~“prospective,” “pursue,” “seek,” “should,” “strategy,” “target,” ~~“could,~~“will,” ~~“may,” “should,” “would,” “will”~~“would” or other similar expressions that convey the uncertainty of future events or outcomes. ~~In accordance with “safe harbor” provisions~~

Forward-looking statements include, among other things, statements regarding:

•future financial and operating results;

•environmental, social and governance (“ESG”) plans and goals, including those related to greenhouse gas emissions, diversity and inclusion and ESG reporting;

•future levels of capital, environmental or maintenance expenditures, general and administrative and other expenses;

•the ~~Private Securities Litigation Reform Act~~success or timing of ~~1995,~~completion of ongoing or anticipated capital or maintenance projects;

•business strategies, growth opportunities and expected investments;

•the timing and amount of future distributions or unit repurchases; and

•the anticipated effects of actions of third parties such as competitors, activist investors, federal, foreign, state or local regulatory authorities, or plaintiffs in litigation.

Our forward-looking statements are not guarantees of future performance and you should not rely unduly on them, as they involve risks, uncertainties and assumptions that we cannot predict. Forward-looking and other statements regarding our ESG plans and goals are not an indication that these statements are ~~accompanied~~material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current, and forward-looking ESG-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future. Material differences between actual results and any future performance suggested in our forward-looking statements could result from a variety of factors, including the following:

•general economic, political or regulatory developments, including inflation, interest rates, changes in governmental policies relating to refined petroleum products, crude oil, natural gas, NGLs, renewables, or taxation;

•the ability of MPC to achieve its strategic objectives and the effects of those strategic decisions on us;

•further impairments;

•negative capital market conditions, including an increase of the current yield on common units;

•the ability to achieve strategic and financial objectives, including with respect to distribution coverage, future distribution levels, proposed projects and completed transactions;

•the success of MPC’s portfolio optimization, including the ability to complete any divestitures on commercially reasonable terms and/or within the expected timeframe, and the effects of any such divestitures on our business, financial condition, results of operations and cash flows;

•the adequacy of capital resources and liquidity, including the availability of sufficient cash flow to pay distributions and access to debt on commercially reasonable terms, and the ability to successfully execute business plans, growth strategies and self-funding models;

•the timing and extent of changes in commodity prices and demand for crude oil, refined products, feedstocks or other hydrocarbon-based products, or renewables;

•volatility in or degradation of general economic, market, industry or business conditions as a result of the COVID-19 pandemic, other infectious disease outbreaks, natural hazards, extreme weather events, hostilities in the Middle East, the military conflict between Russia and Ukraine, other conflicts, inflation, rising interest rates or otherwise;

•changes to the expected construction costs and timing of projects and planned investments, and the ability to obtain regulatory and other approvals with respect thereto;

•completion of midstream infrastructure by ~~cautionary language identifying important factors, though not necessarily all~~competitors;

•disruptions due to equipment interruption or failure, including electrical shortages and power grid failures;

•the suspension, reduction or termination of MPC’s obligations under MPLX’s commercial agreements;

•modifications to financial policies, capital budgets, and earnings and distributions;

•the ability to manage disruptions in credit markets or changes to credit ratings;

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•compliance with federal and state environmental, economic, health and safety, energy and other policies and regulations or enforcement actions initiated thereunder;

•adverse results in litigation;

•the effect of restructuring or reorganization of business components;

•the potential effects of changes in tariff rates on our business, financial condition, results of operations and cash flows;

•foreign imports and exports of crude oil, refined products, natural gas and NGLs;

•changes in producer customers’ drilling plans or in volumes of throughput of crude oil, natural gas, NGLs, refined products, other hydrocarbon-based products, or renewables;

•changes in the cost or availability of third-party vessels, pipelines, railcars and other means of transportation for crude oil, natural gas, NGLs, feedstocks, refined products, or renewables;

•the price, availability and acceptance of alternative fuels and alternative-fuel vehicles and laws mandating such ~~factors, which~~fuels or vehicles;

•actions taken by our competitors, including pricing adjustments and the expansion and retirement of pipeline capacity, processing, fractionation and treating facilities in response to market conditions;

•expectations regarding joint venture arrangements and other acquisitions or divestitures of assets;

•midstream and refining industry overcapacity or undercapacity;

•accidents or other unscheduled shutdowns affecting our machinery, pipelines, processing, fractionation and treating facilities or equipment, means of transportation, or those of our suppliers or customers;

•our ability to maintain adequate insurance coverage and recover insurance proceeds to offset losses resulting from accidents or other insurance incidents and unscheduled shutdowns;

•acts of war, terrorism or civil unrest that could ~~cause future outcomes~~impair our ability to ~~differ materially from those set forth~~gather, process, fractionate or transport crude oil, natural gas, NGLs, refined products, or renewables;

•political pressure and influence of environmental groups upon policies and decisions related to the production, gathering, refining, processing, fractionation, transportation and marketing of crude oil or other feedstocks, refined products, natural gas, NGLs, other hydrocarbon-based products, or renewables;

•the imposition of windfall profit taxes or maximum refining margin penalties on companies operating in ~~forward-looking statements.~~ the energy industry in California or other jurisdictions; and

•our ability to successfully achieve our ESG goals and targets within the expected timeframe, if at all.

For additional risk factors affecting our business, see ~~Item 1A. Risk Factors~~the risk factors described in our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2022. We undertake no obligation to update any forward-looking statements except to the extent required by applicable law.

~~PARTNERSHIP OVERVIEW~~MPLX Overview

We are a diversified, ~~growth-oriented~~large-cap master limited partnership formed by MPC ~~to own, operate, develop~~in 2012 that owns and ~~acquire~~operates midstream energy infrastructure ~~assets. We are engaged~~and logistics assets, and provides fuels distribution services. The business consists of two segments based on the nature of services it offers: Logistics and Storage (“L&S”) and Gathering and Processing (“G&P”). The L&S segment primarily engages in the gathering, ~~processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of NGLs; and the~~ transportation, storage and distribution of crude oil, refined products, other hydrocarbon-based products, and ~~refined petroleum products.~~renewables. The L&S segment also includes the operation of our refining logistics, fuels distribution and inland marine businesses, terminals, rail facilities and storage caverns. The G&P segment provides gathering, processing and transportation of natural gas as well as the transportation, fractionation, storage and marketing of NGLs.

~~SIGNIFICANT FINANCIAL AND OTHER HIGHLIGHTS~~

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Significant Financial and Other Highlights

Significant financial ~~and other~~ highlights for the three months ended September 30, ~~2017~~2023 and September 30, 2022 are ~~listed~~shown in the chart below. Refer to the Results of Operations, ~~and~~the Liquidity and Capital Resources, and Non-GAAP Financial Information sections for further ~~details.~~information.

~~L&S segment operating income attributable to MPLX LP increased approximately $89~~(1) The 2022 amounts include a $509 million ~~or 72 percent,~~non-cash gain on a lease reclassification. See Note 14 in the unaudited consolidated financial statements for additional information.

(2) Non-GAAP measure. See reconciliations that follow for the ~~three months ended September 30, 2017 compared~~most directly comparable GAAP measures.

Other Highlights

•Returned $799 million and $2,419 million of capital to ~~the same period of 2016 due to $74 million from the inclusion of HST, WHC and MPLXT results after our acquisition as of March 1, 2017and$7 million from the acquisition of the Ozark pipeline.~~

G&P segment operating income attributable to MPLX LP increased approximately $56 million, or 19 percent, for the three months ended September 30, 2017 compared to the same period of 2016. The G&P segment realized product price increases and volume increases during the third quarter of 2017 primarily due to expansionsunitholders in the Southwest as well as growth at the Sherwood, Majorsville and Bluestone (previously referred to as Keystone) plants. Compared to the third quarter of 2016, processing volumes were up approximately 11 percent, fractionated volumes were up approximately 14 percent and gathering volumes were up approximately 13 percent.

~~Additional highlights for~~ the three and nine months ended September 30, ~~2017, including~~2023, via distributions.

•Announced a ~~look ahead to anticipated growth, are listed below.~~third quarter 2023 distribution of $0.850 per common unit, representing a 10% increase over the prior quarter’s distribution.

~~Acquisition~~Garyville Tank Farm Incident

In August 2023, a naphtha release and ~~Growth Activities~~

On September 27, 2017, MPC authorized an offer of MPLX Fuels Distributions LLC and MPLX Refining Logistics LLC to MPLX LP in exchange for cash and limited and general partnership units. MPLX Fuels Distribution LLC is structured to provide a broad range of scheduling and marketing services as MPC’s sole and exclusive agent. MPLX Refining Logistics LLC contains the integrated tank farm assets that support MPC’s refining operations. These essential logistics assets include: approximately 56 million barrels storage capacity (crude, finished products and intermediates)resulting fire occurred at our Garyville Tank Farm (“Garyville Incident”), 619 tanks, 32 rail and truck racks, and 18 docks and gasoline blenders. This offer, which is projected to contribute approximately $1.0 billion of annual EBITDA, is currently under review by the conflicts committee of the board of directors of our general partner. The transaction is expected to close no later than the end of the first quarter of 2018. If approved, this acquisition will complete a series of planned acquisitions of assets from MPC that began in early 2017. The combined sum of the three transactions totals an estimated $1.4 billion of annual EBITDA. The stable, fee-based earnings from these acquired assets add both scale and diversification to our portfolio of high-quality midstream assets.

On September 1, 2017, we acquired joint-interest ownerships in certain pipelines and storage facilities from MPC for $420 million in cash and the issuance of $653 million in MPLX LP equity. The acquired ownership interests include a 35 percent ownership interest in Illinois Extension, a 40.7 percent ownership interest in LOOP, a 58.52 percent ownership interest in LOCAP, and a 24.51 percent ownership interest in Explorer. The assets held by these entities include a 1,830-mile refined products pipeline, storage facilities, pump stations, and an offshore deep water oil port located along the Gulf Coast. The infrastructure serves primarily the Midwest and Gulf Coast regions of the United States. There is no income associated with the Joint-Interest Acquisition includedresulting in the ~~Consolidated Statements~~loss of ~~Income since the September 1, 2017 acquisition date, as we account for these equity method investments in arrears using the most recently available information.~~

~~On March 1, 2017, we acquired certain pipeline,~~four storage and terminal assets from MPC for $1.5 billion in cash and the issuance of $503 million in MPLX LP equity. As of the acquisition date, the assets consisted of 174 miles of crude oil pipelines and 430 miles of refined products pipelines, nine butane and propane storage caverns located in Michigantanks with approximately 1.8 million barrels of NGL storage capacity, 59 terminals for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products, along with one leased terminal and partial ownership interest in two terminals. Collectively, the 62 terminals had a combined ~~total~~ shell capacity of ~~approximately 23.6~~894 thousand barrels. We incurred $63 million ~~barrels. The terminal facilities are located primarily in the Midwest, Gulf Coast and Southeast regions~~ of ~~the United States.~~

On March 1, 2017, we purchased the 433-mile, 22-inch Ozark crude oil pipeline for $219 million. The pipeline is capable of transporting approximately 230 mbpd and expands the footprint of our logistics and storage segment by connecting Cushing, Oklahoma-sourced volumes to our extensive Midwest pipeline network. An expansion project to increase the line's capacity to approximately 345 mbpd is expected to be completed in the second quarter of 2018.

On February 15, 2017, we acquired a 9.1875 percent indirect equity interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Company Pipeline projects, collectively referred to as the Bakken Pipeline system, for $500 million. The Bakken Pipeline system is currently expected to deliver in excess of 520 mbpd of crude oil from the Bakken/Three Forks production area in North Dakota to the Midwest through Patoka, Illinois and ultimately to the Gulf Coast. During the third quarter 2017, MPLX LP benefited from the first full quarter of earnings from its indirect interest in the Bakken Pipeline system. Initial cash distributions related to this investment were also receivedincident response costs during the ~~third quarter 2017.~~

~~On February 6, 2017, we formed a strategic joint venture with Antero Midstream to process natural gas at the Sherwood Complex~~three and fractionate natural gas liquids at the Hopedale Complex. This unique transaction strengthens our long-term relationship with the largest producer in the Appalachian Basin and provides the Partnership with substantial future growth opportunities. As part of this agreement, Antero Midstream released to the joint venture the dedication of approximately 195,000 gross operated acres located in Tyler, Wetzel and Ritchie counties of West Virginia. We contributed cash of $20 million, along with $353 million of assets, comprised of real property, equipment and facilities, including three 200 MMcf/d gas processing plants then under construction at the Sherwood Complex. Antero Midstream contributed cash of $154 million. The joint venture commenced operations of the first new facility during the first quarter of 2017, the second new facility during the third quarter of 2017 and expects to commence operations of the third new facility during the first quarter of 2018. Construction of a fourth new facility was announced during the first quarter of 2017 and is expected to commence operations in late 2018. In addition to the four new processing facilities, the joint venture contemplates the development of up to another seven processing facilities to support Antero Resources Corporation, which would be located at both the Sherwood Complex and a new location in West Virginia. At the Hopedale Complex, the largest fractionation facility in the Marcellus and Utica shales, the joint venture will also support the growth of Antero Resources Corporation’s NGL production by investing in 20 mbpd of existing fractionation capacity, with options to invest in future fractionation expansions.

~~Financing Activities~~

On July 21, 2017, the Partnership entered into a credit agreement to replace its previous $2.0 billion five-year bank revolving credit facility with a $2.25 billion five-year bank revolving credit facility that expires in July 2022. The financial covenants and the interest rate terms contained in the new credit agreement are substantially the same as those contained in the previous bank revolving credit facility. Additionally, on July 19, 2017, MPLX LP prepaid the entire outstanding principal amount of its $250 million term loan with cash on hand.

~~On February 10, 2017, we completed a public offering of $2.25 billion aggregate principal amount of senior notes (the “New Senior Notes”).~~

~~During the~~ nine months ended September 30, ~~2017,~~2023. We are pursuing recovery of property damage and incident response costs under the relevant insurance policies, although there can be no assurance as to the amount of recovery, if any.

Current Economic Environment

In an effort to ease inflation in support of its monetary policy goals, the Federal Reserve has raised interest rates multiple times throughout 2022 and 2023. We cannot predict the effect of higher interest rates, the concern of a recession, or the impact of inflation and fuel prices on demand for our services. In response to this business environment, MPLX remains focused on executing its strategic priorities of strict capital discipline, fostering a low-cost culture, and portfolio optimization. Also, to the extent permitted by regulations and our existing agreements, many of which provide for inflation-based adjustments, we ~~issued~~have increased the fees we charge our customers to reflect higher levels of inflation.

Succession Planning

As previously disclosed, MPC maintains a mandatory retirement policy that, absent a waiver or extension, requires an ~~aggregate~~executive officer to retire from service to the company coincident with, or immediately following, the first of ~~13,846,998 commons units under~~the month after such executive officer reaches age 65 (the "Policy"). Michael J. Hennigan, President and Chief Executive Officer of our ~~ATM Program, generating net proceeds~~general partner, as well as the President and Chief Executive Officer of ~~approximately $473 million. As~~MPC, will reach mandatory retirement on August 1, 2024. Accordingly, the MPC Board of ~~September 30, 2017, $1.7 billion~~Directors, with a focus on the long-term strategic direction of ~~common units remain available for issuance through~~ the ~~ATM Program.~~company, is engaged in appropriate succession planning activities, which are expected to include, among other customary steps, the review of succession candidates, as well as consideration of any waiver or extension of the Policy respecting Mr. Hennigan.

~~NON-GAAP FINANCIAL INFORMATION~~

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Non-GAAP Financial Information

Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include the non-GAAP financial measures of Adjusted EBITDA, DCF, adjusted free cash flow (“Adjusted FCF”), and ~~DCF.~~Adjusted FCF after distributions. The amount of Adjusted EBITDA and DCF generated is considered by the board of directors of our general partner in approving ~~the Partnership’s~~MPLX’s cash distributions.

We define Adjusted EBITDA as net income adjusted ~~for~~for: (i) ~~depreciation and amortization; (ii)~~ provision ~~(benefit)~~ for income taxes; ~~(iii) amortization of deferred financing costs; (iv) non-cash equity-based compensation; (v) impairment expense; (vi) net~~(ii) interest and other financial costs; ~~(vii) (income) loss~~(iii) depreciation and amortization; (iv) income/(loss) from equity method investments; (v) distributions and adjustments related to equity method investments; (vi) gain on sales-type leases; (vii) impairment expense; (viii) ~~distributions from unconsolidated subsidiaries considering principal payments of debt~~noncontrolling interests; and ~~certain capital expenditures;~~ (ix) ~~distributions of cash received from Joint-Interest Acquisition entities to MPC; (x) unrealized derivative losses (gains); and (xi) acquisition costs.~~other adjustments, as applicable. We also use DCF, which we define as Adjusted EBITDA adjusted ~~for~~for: (i) deferred revenue impacts; (ii) sales-type lease payments, net of income; (iii) net interest and other financial costs; ~~(iii)~~(iv) net maintenance capital expenditures; (v) equity method investment capital expenditures paid out; and ~~(iv)~~(vi) other ~~non-cash items. The Partnership makes a distinction between realized or unrealized gains~~adjustments as deemed necessary.

We define Adjusted FCF as net cash provided by operating activities adjusted for: (i) net cash used in investing activities; (ii) cash contributions from MPC; and ~~losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded~~(iii) cash distributions to noncontrolling interests. We define Adjusted FCF after distributions as ~~an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed~~Adjusted FCF less base distributions to common and ~~the realized gain or loss of the contract is recorded.~~preferred unitholders.

We believe that the presentation of Adjusted EBITDA, DCF, Adjusted FCF and ~~DCF~~Adjusted FCF after distributions provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and DCF are net income and net cash provided by operating activities while the GAAP measure most directly comparable to Adjusted FCF and Adjusted FCF after distributions is net cash provided by operating activities. ~~Adjusted EBITDA and DCF~~These non-GAAP financial measures should not be considered alternatives to GAAP net income or net cash provided by operating ~~activities. Adjusted EBITDA and DCF~~activities as they have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. ~~Adjusted EBITDA and DCF~~These non-GAAP financial measures should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP. Additionally, because ~~Adjusted EBITDA and DCF~~non-GAAP financial measures may be defined differently by other companies in our industry, our definitions ~~of Adjusted EBITDA and DCF~~ may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a reconciliation of Adjusted EBITDA and DCF to their most directly comparable measures calculated and presented in accordance with GAAP, see Results of Operations.

~~Management evaluates contract performance on the basis~~ For a reconciliation of ~~net operating margin, a non-GAAP financial~~Adjusted FCF and Adjusted FCF after distributions to their most directly comparable measure which is defined as segment revenue less segment purchased product costs less realized derivative gains (losses) related to purchased product costs. These charges have been excluded for the purpose of enhancing the understanding by both managementcalculated and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting. Net operating margin does not have any standardized definition and, therefore, is unlikely to be comparable to similar measures presented ~~by other reporting companies. Net operating margin results should not be evaluated in isolation of, or as a substitute for, our financial results prepared~~ in accordance with ~~GAAP. Our use~~GAAP, see Liquidity and Capital Resources.

Comparability of ~~net operating margin and~~our Financial Results

During the ~~underlying methodology in excluding certain charges is not necessarily an indication~~normal course of business, we amend or modify our contractual agreements with customers. These amendments or modifications require the ~~results~~agreements to be reassessed under ASU No. 2016-02, Leases (“ASC 842”), which can impact the classification of ~~operations expected in~~revenues or costs associated with the ~~future, or that we will not, in fact, incur such charges in future periods.~~

~~In evaluating our financial performance, management utilizes~~agreement. These reassessments may impact the segment performance measures, segment revenues and segment operating income, including total segment operating income. The use of these measures allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. See Note 9 of the Notes to Consolidated Financial Statements for the reconciliations of these segment measures, including total segment operating income, to their respective most directly comparable GAAP measures.

~~COMPARABILITY OF OUR FINANCIAL RESULTS~~

~~Our acquisitions have impacted~~ comparability of our financial ~~results (see Note 3~~results.

Table of ~~the Notes to Consolidated Financial Statements)~~.

Contents

Results of Operations

~~RESULTS OF OPERATIONS~~

The following ~~table~~tables and discussion ~~is a summary of~~summarize our results of operations, ~~for the three and nine months ended September 30, 2017 and 2016,~~ including a reconciliation of Adjusted EBITDA and DCF from ~~net~~Net income and ~~net~~Net cash provided by operating activities, to the most directly comparable GAAP financial measures. ~~Prior period~~This discussion should be read in conjunction with Item 1. Financial Statements and is intended to provide investors with a reasonable basis for assessing our historical operations, but should not serve as the only criteria for predicting our future performance.


	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2023		2022		Variance		2023		2022		Variance
Revenues and other income:
Total revenues and other income(1)	$	2,912	$	3,401	$	(489)	$	8,315	$	8,951	$	(636)
Costs and expenses:
Cost of revenues (excludes items below)	367		371		(4)		1,023		981		42
Purchased product costs	474		540		(66)		1,234		1,670		(436)
Rental cost of sales	20		22		(2)		60		101		(41)
Rental cost of sales - related parties	8		10		(2)		24		44		(20)
Purchases - related parties	442		364		78		1,160		1,034		126
Depreciation and amortization	301		302		(1)		907		925		(18)
General and administrative expenses	102		88		14		280		248		32
Other taxes	44		30		14		102		97		5
Total costs and expenses	1,758		1,727		31		4,790		5,100		(310)
Income from operations	1,154		1,674		(520)		3,525		3,851		(326)
Related-party interest and other financial costs	—		—		—		—		5		(5)
Interest expense, net of amounts capitalized	223		217		6		673		627		46
Other financial costs, net	2		19		(17)		28		59		(31)
Income before income taxes	929		1,438		(509)		2,824		3,160		(336)
Provision for income taxes	1		1		—		2		6		(4)
Net income	928		1,437		(509)		2,822		3,154		(332)
Less: Net income attributable to noncontrolling interests	10		9		1		28		26		2
Net income attributable to MPLX LP	918		1,428		(510)		2,794		3,128		(334)

Adjusted EBITDA attributable to MPLX LP(2)	1,596		1,471		125		4,646		4,321		325
DCF attributable to MPLX(2)	$	1,373	$	1,264	$	109	$	3,956	$	3,711	$	245

(1) The three and nine months ended September 30, 2022 include a $509 million non-cash gain on a lease reclassification. See Note 14 in the unaudited consolidated financial ~~information has been retrospectively adjusted~~statements for additional information.

(2) Non-GAAP measure. See reconciliation below to the ~~acquisition of HST, WHC and MPLXT.~~most directly comparable GAAP measures.

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 Variance 2017 2016 Variance
Total revenues and other income $ 980
$ 838
$ 142
$ 2,782
$ 2,181
$ 601
Costs and expenses:
Cost of revenues (excludes items below) 129
122
7
381
329
52
Purchased product costs 170
117
53
441
310
131
Rental cost of sales 19
13
6
44
42
2
Rental cost of sales - related parties —
—
—
1
1
—
Purchases - related parties 114
109
5
330
286
44
Depreciation and amortization 164
151
13
515
438
77
Impairment expense —
—
—
—
130
(130 )
General and administrative expenses 59
56
3
174
172
2
Other taxes 14
12
2
40
37
3
Total costs and expenses 669
580
89
1,926
1,745
181
Income from operations 311
258
53
856
436
420
Related party interest and other financial costs 1
—
1
1
1
—
Interest expense, net of amounts capitalized 77
51
26
217
158
59
Other financial costs 15
13
2
40
37
3
Income before income taxes 218
194
24
598
240
358
Provision (benefit) for income taxes 1
—
1
3
(12 ) 15
Net income 217
194
23
595
252
343
Less: Net income attributable to noncontrolling interests 1
2
(1 ) 3
3
—
Less: Net income attributable to Predecessor —
51
(51 ) 36
149
(113 )
Net income attributable to MPLX LP $ 216
$ 141
$ 75
$ 556
$ 100
$ 456

Adjusted EBITDA attributable to MPLX LP⁽¹⁾
$ 538
$ 375
$ 163
$ 1,435
$ 1,028
$ 407
DCF⁽¹⁾
442
301
141
1,183
822
361
DCF attributable to GP and LP unitholders⁽¹⁾
426
285
141
1,134
797
337


~~(1)~~	~~Non-GAAP financial measure. See the following tables for reconciliations to the most directly comparable GAAP measures.~~

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	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2023		2022		Variance		2023		2022		Variance
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income:
Net income	$	928	$	1,437	$	(509)	$	2,822	$	3,154	$	(332)
Provision for income taxes	1		1		—		2		6		(4)
Interest and other financial costs	225		236		(11)		701		691		10
Income from operations	1,154		1,674		(520)		3,525		3,851		(326)
Depreciation and amortization	301		302		(1)		907		925		(18)
Income from equity method investments	(159)		(125)		(34)		(438)		(335)		(103)
Distributions/adjustments related to equity method investments	208		166		42		551		450		101
Gain on sales-type leases	—		(509)		509		—		(509)		509
Garyville Incident response costs	63		—		63		63		—		63
Other(1)	40		(27)		67		69		(32)		101
Adjusted EBITDA	1,607		1,481		126		4,677		4,350		327
Adjusted EBITDA attributable to noncontrolling interests	(11)		(10)		(1)		(31)		(29)		(2)
Adjusted EBITDA attributable to MPLX LP	1,596		1,471		125		4,646		4,321		325
Deferred revenue impacts	25		39		(14)		65		87		(22)
Sales-type lease payments, net of income	3		3		—		9		13		(4)
Net interest and other financial costs(2)	(212)		(216)		4		(650)		(635)		(15)
Maintenance capital expenditures, net of reimbursements	(28)		(40)		12		(93)		(93)		—
Equity method investment maintenance capital expenditures paid out	(4)		(4)		—		(11)		(10)		(1)
Other	(7)		11		(18)		(10)		28		(38)
DCF attributable to MPLX LP	1,373		1,264		109		3,956		3,711		245
Preferred unit distributions	(25)		(33)		8		(76)		(96)		20
DCF attributable to GP and LP unitholders	$	1,348	$	1,231	$	117	$	3,880	$	3,615	$	265

(1) Includes unrealized derivative gain/(loss), non-cash equity-based compensation and other miscellaneous items.

(2) Excludes gain/loss on extinguishment of debt and amortization of deferred financing costs.

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 Variance 2017 2016 Variance
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income:
Net income $ 217
$ 194
$ 23
$ 595
$ 252
$ 343
Depreciation and amortization 164
151
13
515
438
77
Provision (benefit) for income taxes 1
—
1
3
(12 ) 15
Amortization of deferred financing costs 13
11
2
38
34
4
Non-cash equity-based compensation 4
3
1
10
9
1
Impairment expense —
—
—
—
130
(130 )
Net interest and other financial costs 80
53
27
220
162
58
(Income) loss from equity method investments (23 ) (6 ) (17 ) (29 ) 72
(101 )
Distributions from unconsolidated subsidiaries 70
33
37
136
111
25
Distributions of cash received from Joint-Interest Acquisition entities to MPC (13 ) —
(13 ) (13 ) —
(13 )
Other adjustments to equity method investment distributions 8
—
8
8
—
8
Unrealized derivative losses (gains)⁽¹⁾
17
2
15
(2 ) 23
(25 )
Acquisition costs 2
—
2
6
(1 ) 7
Adjusted EBITDA 540
441
99
1,487
1,218
269
Adjusted EBITDA attributable to noncontrolling interests (2 ) (2 ) —
(5 ) (3 ) (2 )
Adjusted EBITDA attributable to Predecessor⁽²⁾
—
(64 ) 64
(47 ) (187 ) 140
Adjusted EBITDA attributable to MPLX LP 538
375
163
1,435
1,028
407
Deferred revenue impacts 8
1
7
25
8
17
Net interest and other financial costs (80 ) (53 ) (27 ) (220 ) (162 ) (58 )
Maintenance capital expenditures (24 ) (25 ) 1
(59 ) (58 ) (1 )
Other —
(2 ) 2
—
(2 ) 2
Portion of DCF adjustments attributable to Predecessor⁽²⁾
—
5
(5 ) 2
8
(6 )
DCF 442
301
141
1,183
822
361
Preferred unit distributions (16 ) (16 ) —
(49 ) (25 ) (24 )
DCF attributable to GP and LP unitholders $ 426
$ 285
$ 141
$ 1,134
$ 797
$ 337

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	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2023		2022		Variance		2023		2022		Variance
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net cash provided by operating activities:
Net cash provided by operating activities	$	1,244	$	1,039	$	205	$	3,908	$	3,651	$	257
Changes in working capital items	56		208		(152)		(56)		60		(116)
All other, net	(9)		(15)		6		(12)		(51)		39
Loss on extinguishment of debt	—		1		(1)		9		1		8
Net interest and other financial costs(1)	212		216		(4)		650		635		15
Other adjustments to equity method investment distributions	13		19		(6)		25		45		(20)
Garyville Incident response costs	63		—		63		63		—		63
Other	28		13		15		90		9		81
Adjusted EBITDA	1,607		1,481		126		4,677		4,350		327
Adjusted EBITDA attributable to noncontrolling interests	(11)		(10)		(1)		(31)		(29)		(2)
Adjusted EBITDA attributable to MPLX LP	1,596		1,471		125		4,646		4,321		325
Deferred revenue impacts	25		39		(14)		65		87		(22)
Sales-type lease payments, net of income	3		3		—		9		13		(4)
Net interest and other financial costs(1)	(212)		(216)		4		(650)		(635)		(15)
Maintenance capital expenditures, net of reimbursements	(28)		(40)		12		(93)		(93)		—
Equity method investment maintenance capital expenditures paid out	(4)		(4)		—		(11)		(10)		(1)
Other	(7)		11		(18)		(10)		28		(38)
DCF attributable to MPLX LP	1,373		1,264		109		3,956		3,711		245
Preferred unit distributions	(25)		(33)		8		(76)		(96)		20
DCF attributable to GP and LP unitholders	$	1,348	$	1,231	$	117	$	3,880	$	3,615	$	265

(1) Excludes gain/loss on extinguishment of debt and amortization of deferred financing costs.

Nine Months Ended September 30,
(In millions) 2017 2016 Variance
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net cash provided by operating activities:
Net cash provided by operating activities $ 1,338
$ 975
$ 363
Changes in working capital items (41 ) 59
(100 )
All other, net (43 ) (18 ) (25 )
Non-cash equity-based compensation 10
9
1
Net gain on disposal of assets 1
1
—
Net interest and other financial costs 220
162
58
Current income taxes 1
4
(3 )
Asset retirement expenditures 2
4
(2 )
Unrealized derivative (gains) losses⁽¹⁾
(2 ) 23
(25 )
Acquisition costs 6
(1 ) 7
Distributions of cash received from Joint-Interest Acquisition entities to MPC (13 ) —
(13 )
Other adjustments to equity method investment distributions 8
—
8
Adjusted EBITDA 1,487
1,218
269
Adjusted EBITDA attributable to noncontrolling interests (5 ) (3 ) (2 )
Adjusted EBITDA attributable to Predecessor⁽²⁾
(47 ) (187 ) 140
Adjusted EBITDA attributable to MPLX LP 1,435
1,028
407
Deferred revenue impacts 25
8
17
Net interest and other financial costs (220 ) (162 ) (58 )
Maintenance capital expenditures (59 ) (58 ) (1 )
Other —
(2 ) 2
Portion of DCF adjustments attributable to Predecessor⁽²⁾
2
8
(6 )
DCF 1,183
822
361
Preferred unit distributions (49 ) (25 ) (24 )
DCF attributable to GP and LP unitholders $ 1,134
$ 797
$ 337

~~(1)~~


~~(2)~~	~~The Adjusted EBITDA and DCF adjustments related to Predecessor are excluded from Adjusted EBITDA attributable to MPLX LP and DCF prior to the acquisition dates.~~

Three months ended September 30, ~~2017~~2023 compared to three months ended September 30, ~~2016~~2022

Total revenues and other income ~~increased $142~~decreased $489 million in the third quarter of ~~2017~~2023 compared to the same period of ~~2016. This variance~~2022. The decrease was ~~due mainly to increased pricing~~driven by a contract modification that resulted in a non-cash gain on ~~product sales~~sales-type lease of ~~approximately $54 million, offset by an increased unrealized derivative loss of $10 million, higher revenues from volume growth of $49 million in the Marcellus and the Southwest areas,~~higher crude and product transportation volumes of $14 million, a $19 million increase from the acquisition of the Ozark pipeline, a $17 million increase from our equity method investments, mainly due to the acquisition of an equity interest in the Bakken Pipeline system, the addition of the Sherwood Midstream joint venture during 2017 and increased dry gas gathering volumes for certain of our equity method investments.

~~Cost of revenues increased $7~~$509 million in the third quarter of ~~2017~~2022. In addition, product sales revenue decreased as a result of lower NGL prices during the third quarter of 2023 as compared to the same period of ~~2016. This variance~~2022. The decrease was partially offset by rate escalations and higher throughput across the business and a $34 million increase in income from equity method investments primarily due to ~~the acquisition of the Ozark pipeline.~~higher throughput.

Purchased product costs ~~increased $53~~decreased $66 million in the third quarter of ~~2017~~2023 compared to the same period of ~~2016.~~2022. This ~~variance~~ was primarily due to lower NGL prices of $276 million, partially offset by higher NGL ~~and gas prices~~volumes of ~~$36~~$157 million and ~~increased volumes~~a change of ~~$10~~$53 million ~~primarily~~due to changes in the ~~Southwest area, as well as~~fair value of an ~~increase~~embedded derivative in ~~the unrealized loss of $6 million, of which~~ a ~~majority is~~natural gas purchase commitment.

Purchases - related ~~to our Natural Gas Embedded Derivative.~~

~~Depreciation and amortization expense~~parties increased ~~$13~~$78 million in the third quarter of ~~2017~~2023 compared to the same period of ~~2016.~~2022. This ~~variance~~ was primarily due to ~~additions to in-service property, plant~~Garyville Incident response costs of $63 million and ~~equipment as well as approximately $2 million~~increased employee costs from MPC.

Interest expense, net of ~~accelerated depreciation related to adjustments of certain assets’ useful life.~~

~~Net interest expense and other financial costs~~amounts capitalized increased ~~$28~~$6 million in the third quarter of ~~2017~~2023 compared to the same period of ~~2016. The increase is mainly~~2022. This was primarily due to refinancing maturing debt with fixed rate debt at higher interest rates in 2022 and 2023 in addition to taking on incremental debt in order to finance the ~~New Senior Notes issued~~redemption of the 6.875 percent Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series B preferred units”) in ~~February 2017.~~the first quarter of 2023. Other financial costs, net also benefited from higher interest earned during the third quarter of 2023. Refer to the Liquidity and Capital Resources section for further information.

Nine months ended September 30, ~~2017~~2023 compared to nine months ended September 30, ~~2016~~2022

Total revenues and other income decreased $636 million in the first ninemonths of 2023 compared to the same period of 2022. The decrease was driven by a contract modification that resulted in a non-cash gain on sales-type lease of $509 million in the third quarter of 2022 in addition to lower product sales revenue as a result of lower NGL prices during the first nine months of

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2023 as compared to the same period of 2022. The decrease was partially offset by rate escalations and higher throughput across the business and a $103 million increase in income from equity method investments primarily due to higher throughput.

Cost of revenues increased ~~$601~~$42 million and rental cost of sales (including related party) decreased $61 million in the first ninemonths of 2023 compared to the same period of 2022. These offsetting variances reflect the modification of a gathering and compression agreement in the third quarter of 2022 (“Third-Party Lease Modification”), which resulted in a change in the presentation of expenses from rental cost of sales to cost of revenues.

Purchased product costs decreased $436 million in the first nine months of ~~2017~~2023 compared to the same period of ~~2016.~~2022. This ~~variance~~ was primarily due ~~mainly~~ to ~~the inclusion~~lower NGL prices of ~~$103~~$826 million, partially offset by higher volumes of ~~revenue generated by MPLXT~~$329 million and ~~its subsidiaries since it was not formed as~~ a ~~business until April 1, 2016~~, ~~increased pricing on product sales~~change of ~~approximately $177~~$61 million ~~as well as higher revenues from volume growth of $146 million~~due to changes in the ~~Marcellus and the Southwest areas~~, ~~higher crude and product transportation volumes~~fair value of ~~$28 million~~, ~~$45 million from the acquisition of the Ozark pipelineand~~an embedded derivative in a ~~$12 million increase from our equity method investments. The nine months ended September 30, 2016 also included an impairment expense of $89 million~~natural gas purchase commitment.

Purchases - related ~~to our investment in Ohio Condensate as referenced in our Annual Report on Form 10-K for the year ended December 31, 2016, as updated by our Current Report on Form 8-K filed on May 1, 2017.~~

~~Cost of revenues~~parties increased ~~$52~~$126 million in the first nine months of ~~2017~~2023 compared to the same period of ~~2016.~~2022. This ~~variance~~ was primarily due to ~~$20~~Garyville Incident response costs of $63 million, ~~from~~higher volumes and pricing on associated related-party purchased product costs, and higher transportation costs.

Depreciation and amortization decreased $18 million in the ~~inclusion~~first ninemonths of ~~MPLXT~~, 2023 compared to the same period of 2022. This was primarily due to lower depreciation as ~~well as $20 million from the acquisition~~a result of the ~~Ozark pipeline~~derecognition of fixed assets in connection with the Third-Party Lease Modification in the third quarter of 2022. This decrease was partially offset by depreciation on new assets placed in service after the third quarter of 2022.

General and ~~an increase~~administrative expenses increased $32 million in ~~expenses related~~the first ninemonths of 2023 compared to the ~~timing~~same period of ~~projects.~~2022 due to increased costs from MPC, primarily higher employee costs, and other miscellaneous expenses.

~~Purchased product costs~~Interest expense, net of amounts capitalized increased ~~$131~~$46 million in the first nine months of ~~2017~~2023 compared to the same period of ~~2016.~~2022. This ~~variance~~ was primarily due to refinancing debt with fixed rate debt at higher ~~NGL~~interest rates in 2022 and ~~gas prices and purchase volumes~~2023 in addition to taking on incremental debt in order to finance the ~~Southwest area, offset by a $13 million unrealized gain on our Natural Gas Embedded Derivative.~~

~~Purchases-related parties increased $44 million~~redemption of the Series B preferred units in the first ~~nine months~~quarter of ~~2017 compared~~2023. Other financial costs, net also benefited from higher interest earned during 2023. Refer to the ~~same period of 2016. The increase was primarily due to the inclusion of approximately $23 million related party purchases of MPLXT as well as general increases in employee costs due to headcount.~~Liquidity and Capital Resources section for further information.

Depreciation and amortization expense increased $77 million in the first nine months of 2017 compared to the same period of 2016. This variance was primarily due to accelerated depreciation expense of approximately $35 million incurred on the decommissioning of the Houston 1 facility in the Marcellus area and other various assets, approximately $10 million of additional depreciation due to the inclusion of MPLXT, as well additions to in-service property, plant and equipment during the fourth quarter of 2016 and the first nine months of 2017.

Impairment expense decreased $130 million in the first nine months of 2017 compared to the same period of 2016. This variance was due to a non-cash impairment to goodwill in two reporting units in the G&P segment during the first six months of 2016.

Net interest expense and other financial costs increased $62 million in the first nine months of 2017 compared to the same period of 2016. The increase is primarily due to the New Senior Notes issued in February 2017.

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Segment Results

~~SEGMENT RESULTS~~

We classify our business in the following reportable segments: L&S and G&P. We evaluate the performance of our segments using Segment ~~operating income~~Adjusted EBITDA. Segment Adjusted EBITDA represents ~~income from operations~~Adjusted EBITDA attributable to the reportable segments. ~~We have investments~~Amounts included in ~~entities that we operate that are accounted for using~~net income and excluded from Segment Adjusted EBITDA include: (i) depreciation and amortization; (ii) interest and other financial costs; (iii) income/(loss) from equity method ~~investment accounting standards. However, we view financial information~~investments; (iv) distributions and adjustments related to equity method investments; (v) gain on sales-type leases; (vi) impairment expense; (vii) noncontrolling interests; and (viii) other adjustments, as if those investments were consolidated. Corporate general and administrative expenses, unrealized derivative (losses) gains, property, plant and equipment impairment, goodwill impairment and depreciation and amortizationapplicable. These items are either: (i) believed to be non-recurring in nature; (ii) not believed to be allocable or controlled by the segment; or (iii) are not ~~allocated~~tied to the reportable segments. Management does not consider these items allocable to or controllable by any individual segment and, therefore, excludes these items when evaluating segment performance. Segment results are also adjusted to excludeoperational performance of the portion of income from operations attributable to the noncontrolling interests related to partially owned entities that are either consolidated or accounted for as equity method investments. Segment operating income attributable to MPLX LP excludes the operating income related to the HSM Predecessor prior to the March 31, 2016 acquisition and the HST, WHC and MPLXT Predecessor prior to the March 1, 2017 acquisition.segment.

The tables below present information about ~~segment operating income~~Segment Adjusted EBITDA for the reported ~~segments.~~

~~L&S Segment~~

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 Variance 2017 2016 Variance
Revenues and other income:
Segment revenues $ 378
$ 339
$ 39
$ 1,095
$ 901
$ 194
Segment other income 11
12
(1 ) 35
42
(7 )
Total segment revenues and other income 389
351
38
1,130
943
187
Costs and expenses:
Segment cost of revenues 176
153
23
500
392
108
Segment operating income before portion attributable to noncontrolling interests and Predecessor 213
198
15
630
551
79
Segment portion attributable to noncontrolling interests and Predecessor —
74
(74 ) 53
216
(163 )
Segment operating income attributable to MPLX LP $ 213
$ 124
$ 89
$ 577
$ 335
$ 242

~~Three months ended September 30, 2017 compared to three months ended September 30, 2016~~

~~In the third quarter of 2017 compared to the same period of 2016, segment revenue increased primarily due to a $14 million increase from higher crude and product transportation volumes~~, ~~a $19 million increase from the acquisition of the Ozark pipeline,~~a $4 million increase from the annual increase in fees and a $4 million increase from additional barges, partially offset by a $2 million decrease in the recognition of revenue related to volume deficiency payments.

~~In the third quarter of 2017 compared to the same period of 2016, segment cost of revenues increasedprimarily due to a $12 million increase from the acquisition of the Ozark pipeline, as well as from salaries and compensation due to headcount and other miscellaneous expenses.~~

In the third quarter of 2017 compared to the same period of 2016, the segment portion attributable to noncontrolling interests and Predecessor decreased due to the acquisition of HST, WHC and MPLXT as of March 1, 2017.

~~Nine months ended September 30, 2017 compared to nine months ended September 30, 2016~~

In the first nine months of 2017 compared to the same period of 2016, segment revenue increased primarily due to the inclusion of $103 million of revenue generated by MPLXT and its subsidiaries, a $28 million increase from higher crude and product transportation volumes,~~a $45 million increase from the acquisition of the Ozark pipeline~~, ~~a $3 million increase due to the recognition of revenues related to volume deficiency payments,and a $10 million increase from additional barges.~~

In the first nine months of 2017 compared to the same period of 2016, segment cost of revenues increased primarily due to the acquisitions of MPLXT and the Ozark pipeline, increased expenses related to the timing of projects, salaries and compensation due to headcount, and other miscellaneous expenses.

In the first nine months of 2017 compared to the same period of 2016, the segment portion attributable to noncontrolling interests and Predecessor decreased due to the inclusion of HSM for the first three months of 2016 and the acquisition of HST, WHC and MPLXT as of March 1, 2017.

During both the third quarter and first nine months of 2017, MPC did not ship its minimum committed volumes on certain of our pipeline systems. As a result, for the first nine months, MPC was obligated to make a $37 million deficiency payment, of which $11 million was paid in the third quarter of 2017. We record deficiency payments as ~~Deferred revenue-related parties~~ on our Consolidated Balance Sheets. In the third quarter and first nine months of 2017, we recognized revenue of $7 million and $29 million, respectively, related to volume deficiency credits. At September 30, 2017, the cumulative balance of ~~Deferred revenue-related parties~~ on our Consolidated Balance Sheets related to volume deficiencies was $55 million. The following table presents the future expiration dates of the associated deferred revenue credits as of September 30, 2017:

(In millions)
December 31, 2017 $ 8
March 31, 2018 11
June 30, 2018 11
September 30, 2018 10
December 31, 2018 4
March 31, 2019 3
June 30, 2019 4
September 30, 2019 4
Total $ 55

We will recognize revenue for the deficiency payments in future periods at the earlier of when volumes are transported in excess of the minimum quarterly volume commitments, when it becomes impossible to physically transport volumes necessary to utilize the accumulated credits or upon expiration of the make-up period. Deficiency payments are included in the determination of DCF in the period in which a deficiency occurs.

~~G&P Segment~~

~~Our assets include approximately 5.9 bcf/d of gathering capacity, 7.8 bcf/d of natural gas processing capacity and 570 mbpd of fractionation capacity.~~

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 Variance 2017 2016 Variance
Revenues and other income:
Segment revenues $ 669
$ 567
$ 102
$ 1,869
$ 1,595
$ 274
Segment other income 1
1
—
2
1
1
Total segment revenues and other income 670
568
102
1,871
1,596
275
Costs and expenses:
Segment cost of revenues 276
239
37
781
662
119
Segment operating income before portion attributable to noncontrolling interests 394
329
65
1,090
934
156
Segment portion attributable to noncontrolling interests 45
36
9
119
113
6
Segment operating income attributable to MPLX LP $ 349
$ 293
$ 56
$ 971
$ 821
$ 150

~~Three months ended September 30, 2017 compared to three months ended September 30, 2016~~

In the third quarter of 2017 compared to the same period of 2016, segment revenue increased due to increased pricing on product sales of approximately $46 million and increased volumes of $15 million, combined with increased fees of approximately $41 million on higher volumes due to new gathering and processing facilities in the Marcellus, Southwest, and Utica areas, as well as additional fractionation capacity in the Marcellus and Utica areas.

In the third quarter of 2017 compared to the same period of 2016, segment cost of revenues increased primarily due to increased product costs resulting from higher NGL and gas prices of $28 million and increased volumes of $10 million primarily in the Southwest area partially offset by lower maintenance costs and other operating efficiencies.

~~Nine months ended September 30, 2017 compared to nine months ended September 30, 2016~~

In the first nine months of 2017 compared to the same period of 2016, segment revenue increased due to increased pricing on product sales of approximately $144 million and increased volumes of $38 million, combined with increased fees of approximately $92 million on higher volumes due to new processing plants in the Marcellus and Southwest areas and additional fractionation capacity in the Marcellus and Utica areas.

In the first nine months of 2017 compared to the same period of 2016, segment cost of revenues increased due primarily to increased product costs resulting from higher prices of approximately $102 million and higher volumes of $21 million primarily in the Southwest area partially offset by lower facility costs due to lower maintenance costs and other operating efficiencies.

~~Segment Reconciliations~~

The following tables provide reconciliations of segment operating income to our consolidated income from operations, segment revenue to our consolidated total revenues and other income, and segment portion attributable to noncontrolling interests to our consolidated net income attributable to noncontrolling interestssegments for the three and nine months ended September 30, ~~2017~~2023 and ~~2016. Adjustments related~~September 30, 2022.

L&S Segment

Third Quarter L&S Segment Financial Highlights (in millions)


	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2023		2022		Variance		2023		2022		Variance
Service revenue	$	1,130	$	1,038	$	92	$	3,223	$	3,031	$	192
Rental income	216		210		6		638		593		45
Product related revenue	6		4		2		14		15		(1)
Sales-type lease revenue	129		118		11		379		343		36
Income from equity method investments	95		72		23		248		183		65
Other income	15		8		7		47		42		5
Total segment revenues and other income	1,591		1,450		141		4,549		4,207		342
Cost of revenues	158		160		(2)		451		460		(9)
Purchases - related parties	341		265		76		848		762		86
Depreciation and amortization	130		128		2		399		387		12
General and administrative expenses	60		48		12		160		134		26

Other taxes	32		19		13		71		60		11
Total costs and expenses	721		620		101		1,929		1,803		126
Segment income from operations	870		830		40		2,620		2,404		216









Segment Adjusted EBITDA	1,091		969		122		3,139		2,839		300
Capital expenditures	73		80		(7)		251		238		13
Investments in unconsolidated affiliates(1)	$	7	$	12	$	(5)	$	23	$	90	$	(67)

(1) The nine months ended September 30, 2022 includes a contribution of $60 million to ~~unconsolidated affiliates relate~~a joint venture (“Dakota Access”) that owns and operates the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects, collectively referred to as the Bakken Pipeline system or DAPL, to fund our ~~Partnership-operated non-wholly-owned entities that we consolidate for segment purposes.~~ share of a debt repayment by the joint venture.

Table of Contents

Three months ended September 30, 2023 compared to three months ended September 30, 2022

Service revenue increased $92 million in the third quarter of 2023 compared to the same period of 2022. This was primarily driven by higher pipeline tariff rates, increased pipeline throughput, and $15 million from refining logistics fee escalations.

Sales-type lease revenue increased $11 million in the third quarter of 2023 compared to the same period of 2022. This was due to an increase of $5 million from changes in the presentation of revenue between service revenue, rental income and sales-type lease revenue as a result of modifications to agreements with MPC, with the remainder being attributable to fee escalations.

Income ~~(loss)~~ from equity method investments~~relates~~ increased $23 million in the third quarter of 2023 compared to ~~our portion~~the same period of 2022. This was primarily driven by increased throughput on equity method investment pipeline systems.

Purchases - related parties increased $76 million in the third quarter of 2023 compared to the same period of 2022, primarily due to Garyville Incident response costs of $63 million and increased employee costs from MPC.

General and administrative expenses increased $12 million in the first nine months of 2023 compared to the same period of 2022, due to increased costs from MPC, primarily higher employee costs, as well as other miscellaneous increases.

Nine months ended September 30, 2023 compared to nine months ended September 30, 2022

Service revenue increased $192 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to higher pipeline tariff rates and increased pipeline throughput, and $32 million from refining logistics fee escalations. These increases were partially offset by a decrease of $41 million from changes in the presentation of revenue between service revenue, rental income ~~(loss)~~and sales-type lease revenue driven by modifications to agreements with MPC.

Rental income increased $45 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to an increase of $18 million from changes in the presentation of revenue between service revenue, rental income and sales-type lease revenue driven by modifications to agreements with MPC. The remaining increase was primarily due to the escalation of storage fees.

Sales-type lease revenue increased $36 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to an increase of $23 million from changes in the presentation of revenue between service revenue, rental income and sales-type lease revenue as a result of modifications to agreements with MPC, as well as an increase of $12 million from refining logistics due to fee escalations.

Income from equity method investments increased $65 million in the first nine months of 2023 compared to the same period of 2022. This was primarily driven by increased throughput on equity method investment pipeline systems.

Purchases - related parties increased $86 million in the first nine months of 2023 compared to the same period of 2022, primarily due to Garyville Incident response costs of $63 million and increased employee costs from MPC.

General and administrative expenses increased $26 million in the first nine months of 2023 compared to the same period of 2022, due to increased costs from MPC, primarily higher employee costs, as well as other miscellaneous increases.

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L&S Operating Data


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
L&S
Pipeline throughput (mbpd)
Crude oil pipelines	3,911		3,596		3,796		3,551
Product pipelines	1,975		2,169		2,027		2,125
Total pipelines	5,886		5,765		5,823		5,676

Average tariff rates ($ per barrel)(1)
Crude oil pipelines	$	0.99	$	0.93	$	0.95	$	0.91
Product pipelines	0.99		0.80		0.88		0.80
Total pipelines	$	0.99	$	0.88	$	0.93	$	0.86

Terminal throughput (mbpd)	3,228		3,026		3,167		3,023



Marine Assets (number in operation)(2)
Barges	305		296		305		296
Towboats	27		23		27		23

(1) Average tariff rates calculated using pipeline transportation revenues divided by pipeline throughput barrels. Transportation revenues include tariff and other fees, which may vary by region and nature of services provided.

(2) Represents total at end of period.

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G&P Segment

Third Quarter G&P Segment Financial Highlights (in millions)

(1) The 2022 amount includes a $509 million non-cash gain on a lease reclassification. See Note 14 in the unaudited consolidated financial statements for additional information.


	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2023		2022		Variance		2023		2022		Variance
Service revenue	$	549	$	537	$	12	$	1,620	$	1,528	$	92
Rental income	52		66		(14)		155		239		(84)
Product related revenue	598		742		(144)		1,629		2,263		(634)
Sales-type lease revenue	34		28		6		101		28		73
Income from equity method investments	64		53		11		190		152		38
Other income(1)	24		525		(501)		71		534		(463)
Total segment revenues and other income	1,321		1,951		(630)		3,766		4,744		(978)
Cost of revenues	237		243		(6)		656		666		(10)
Purchased product costs	474		540		(66)		1,234		1,670		(436)
Purchases - related parties	101		99		2		312		272		40
Depreciation and amortization	171		174		(3)		508		538		(30)
General and administrative expenses	42		40		2		120		114		6
Other taxes	12		11		1		31		37		(6)
Total costs and expenses	1,037		1,107		(70)		2,861		3,297		(436)

Segment Adjusted EBITDA	505		502		3		1,507		1,482		25
Capital expenditures	151		146		5		417		336		81
Investments in unconsolidated affiliates	$	6	$	30	$	(24)	$	67	$	108	$	(41)

(1) The three and nine months ended September 30, 2022 include a $509 million non-cash gain on a lease reclassification. See Note 14 in the unaudited consolidated financial statements for additional information.

Three months ended September 30, 2023 compared to three months ended September 30, 2022

Service revenue increased $12 million in the third quarter of 2023 compared to the same period of 2022. This was primarily due to higher volumes and higher throughput fee rates in the Marcellus.

Rental income decreased $14 million and sales-type lease revenue increased $6 million in the third quarter of 2023 compared to the same period of 2022. The net decrease was primarily due to a contract modification that decreased the amount of revenue allocated to Rental income in Southern Appalachia beginning in the first quarter of 2023, partially offset by higher volumes and higher throughput fee rates.

Product related revenue decreased $144 million in the third quarter of 2023 compared to the same period of 2022. This was primarily due to lower NGL prices across all regions of $310 million, partially offset by higher volumes in the Southwest of $175 million.

Income from equity method investments increased $11 million in the third quarter of 2023 compared to the same period of 2022. This was primarily due to higher volumes associated with several of our ~~unconsolidated~~ joint ventures of which Partnership-operated joint ventures are consolidated for segment purposes. Other income-related parties consists of operational service fee revenues from our operated unconsolidated affiliates. Unrealized derivative activity is not allocated to segments.in the Marcellus and Utica. Additionally,

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 Variance 2017 2016 Variance
Reconciliation to Income from operations:
L&S segment operating income attributable to MPLX LP $ 213
$ 124
$ 89
$ 577
$ 335
$ 242
G&P segment operating income attributable to MPLX LP 349
293
56
971
821
150
Segment operating income attributable to MPLX LP 562
417
145
1,548
1,156
392
Segment portion attributable to unconsolidated affiliates (47 ) (41 ) (6 ) (125 ) (130 ) 5
Segment portion attributable to Predecessor —
74
(74 ) 53
216
(163 )
Income (loss) from equity method investments 23
6
17
29
(72 ) 101
Other income - related parties 13
11
2
38
29
9
Unrealized derivative (losses) gains⁽¹⁾
(17 ) (2 ) (15 ) 2
(23 ) 25
Depreciation and amortization (164 ) (151 ) (13 ) (515 ) (438 ) (77 )
Impairment expense —
—
—
—
(130 ) 130
General and administrative expenses (59 ) (56 ) (3 ) (174 ) (172 ) (2 )
Income from operations $ 311
$ 258
$ 53
$ 856
$ 436
$ 420

Table of Contents

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 Variance 2017 2016 Variance
Reconciliation to Total revenues and other income:
Total segment revenues and other income $ 1,059
$ 919
$ 140
$ 3,001
$ 2,539
$ 462
Revenue adjustment from unconsolidated affiliates (107 ) (100 ) (7 ) (287 ) (303 ) 16
Income (loss) from equity method investments 23
6
17
29
(72 ) 101
Other income - related parties 13
11
2
38
29
9
Unrealized derivative (losses) gains related to product sales⁽¹⁾
(8 ) 2
(10 ) 1
(12 ) 13
Total revenues and other income $ 980
$ 838
$ 142
$ 2,782
$ 2,181
$ 601

~~(1)~~

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 Variance 2017 2016 Variance
Reconciliation to Net income attributable to noncontrolling interests and Predecessor:
Segment portion attributable to noncontrolling interests and Predecessor $ 45
$ 110
$ (65 ) $ 172
$ 329
$ (157 )
Portion of noncontrolling interests and Predecessor related to items below segment income from operations (21 ) (39 ) 18
(84 ) (157 ) 73
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates (23 ) (18 ) (5 ) (49 ) (20 ) (29 )
Net income attributable to noncontrolling interests and Predecessor $ 1
$ 53
$ (52 ) $ 39
$ 152
$ (113 )

~~OUR G&P CONTRACTS WITH THIRD PARTIES~~

~~We generate the majority of~~ our revenues in the G&P segment from natural gas gathering, transportation and processing; NGL gathering, transportation, fractionation, exchange, marketing and storage; and crude oil gathering and transportation. We enter into a variety of contracts to provide services under the following types of arrangements: fee-based, percent-of-proceeds, percent-of-index and keep-whole. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described below. See Item 1. Business – Our G&P Contracts With Third Parties in our Annual Report on Form 10-K for the year ended December 31, 2016 for further discussion of each of these types of arrangements.

The following table does not give effect to our active commodity risk management program. For further discussion of how we manage commodity price volatility for the portion of our net operating margin that is not fee-based, see Note 13 of the Notes to Consolidated Financial Statements. We manage our business by taking into account the partial offset of short natural gas positions primarilyjoint venture in the Southwest region added processing capacity in the fourth quarter of 2022 driving higher volumes over the prior period.

Other income decreased $501 million in the third quarter of 2023 compared to the same period of 2022 due primarily to a non-cash gain on lease reclassification of $509 million in the third quarter of 2022.

Purchased product costs decreased $66 million in the third quarter of 2023 compared to the same period of 2022. This was primarily due to lower NGL prices in the Southwest and Southern Appalachia of $276 million, partially offset by higher NGL volumes in the Southwest of $157 million and a change of $53 million due to changes in the fair value of an embedded derivative in a natural gas purchase commitment.

Nine months ended September 30, 2023 compared to nine months ended September 30, 2022

Service revenue increased $92 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to higher volumes and higher throughput fee rates in the Marcellus and Rockies.

Rental income decreased $84 million and sales-type lease revenue increased $73 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to changes in the presentation of revenue between rental income and sales-type lease revenue as a result of the Third-Party Lease Modification in the third quarter of 2022. In addition, a contract modification decreased the amount of revenue allocated to Rental income in Southern Appalachia beginning in the first quarter 2023.

Product related revenue decreased $634 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to lower prices across all regions of $958 million, partially offset by higher volumes in the Southwest of $322 million.

Income from equity method investments increased $38 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to higher volumes associated with several of our ~~G&P segment. The calculated percentages for net operating margin for percent-of-proceeds, percent-of-index~~joint ventures in the Marcellus and ~~keep-whole contracts reflect~~Utica. Additionally, our joint venture in the ~~partial~~Southwest region added processing capacity in the fourth quarter of 2022 driving higher volumes over the prior period.

Other income decreased $463 million in the first nine months of 2023 compared to the same period of 2022 due primarily to a non-cash gain on lease reclassification of $509 million in the third quarter of 2022 partially offset by the impact of ~~our~~asset disposals year over year.

Purchased product costs decreased $436 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to lower NGL prices of $826 million in the Southwest and Southern Appalachia, partially offset by higher volumes in the Southwest of $329 million and a change of $61 million due to changes in the fair value of an embedded derivative in a natural gas ~~positions.~~purchase commitment.

Purchases - related parties increased $40 million in the first nine months of 2023 compared to the same period of 2022. The ~~calculated percentages are less than one percent for percent-of-index~~increase is attributable to higher volumes and pricing on associated related-party purchased product costs in the Rockies and higher transportation costs from increased throughput in the Southwest.

Depreciation and amortization decreased $30 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to lower depreciation as a result of the derecognition of fixed assets in connection with the Third-Party Lease Modification in the third quarter of 2022. This decrease was partially offset by depreciation on new assets placed in service after the third quarter of ~~our natural gas positions~~2022.

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G&P Operating Data

(1) Other includes Southern Appalachia, Bakken and ~~therefore, not meaningful to~~Rockies Operations.


	MPLX LP(1)		MPLX LP Operated(2)
	Three Months Ended September 30,		Three Months Ended September 30,
	2023	2022	2023	2022
G&P
Gathering Throughput (MMcf/d)
Marcellus Operations	1,376	1,325	1,376	1,325
Utica Operations	—	—	2,375	2,381
Southwest Operations	1,302	1,362	1,742	1,642
Bakken Operations	160	147	160	147
Rockies Operations	490	452	604	588
Total gathering throughput	3,328	3,286	6,257	6,083

Natural Gas Processed (MMcf/d)
Marcellus Operations	4,187	4,060	5,803	5,535
Utica Operations	—	—	557	518
Southwest Operations	1,405	1,502	1,744	1,666
Southern Appalachian Operations	207	205	207	205
Bakken Operations	159	130	159	130
Rockies Operations	491	462	491	462
Total natural gas processed	6,449	6,359	8,961	8,516

C2 + NGLs Fractionated (mbpd)
Marcellus Operations(3)	546	496	546	496
Utica Operations(3)	—	—	34	30
Southern Appalachian Operations	10	12	10	12
Bakken Operations	20	21	20	21
Rockies Operations	3	3	3	3
Total C2 + NGLs fractionated(4)	579	532	613	562

Table of Contents


	MPLX LP(1)		MPLX LP Operated(2)
	Nine Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
G&P
Gathering Throughput (MMcf/d)
Marcellus Operations	1,353	1,308	1,353	1,308
Utica Operations	—	—	2,387	2,048
Southwest Operations	1,345	1,367	1,775	1,605
Bakken Operations	159	147	159	147
Rockies Operations	463	424	584	556
Total gathering throughput	3,320	3,246	6,258	5,664

Natural Gas Processed (MMcf/d)
Marcellus Operations	4,107	4,021	5,683	5,503
Utica Operations	—	—	533	488
Southwest Operations	1,442	1,446	1,771	1,616
Southern Appalachian Operations	219	220	219	220
Bakken Operations	157	138	157	138
Rockies Operations	472	436	472	436
Total natural gas processed	6,397	6,261	8,835	8,401

C2 + NGLs Fractionated (mbpd)
Marcellus Operations(3)	533	478	533	478
Utica Operations(3)	—	—	31	28
Southern Appalachian Operations	10	11	10	11
Bakken Operations	19	21	19	21
Rockies Operations	3	3	3	3
Total C2 + NGLs fractionated(4)	565	513	596	541


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Pricing Information
Natural Gas NYMEX HH ($ per MMBtu)	$	2.66	$	7.91	$	2.58	$	6.67
C2 + NGL Pricing ($ per gallon)(5)	$	0.68	$	1.01	$	0.69	$	1.11

(1) This column represents operating data for entities that have been consolidated into the ~~table below.~~MPLX financial statements.

(2) This column represents operating data for entities that have been consolidated into the MPLX financial statements as well as operating data for MPLX-operated equity method investments.

~~For~~(3) Entities within the Marcellus and Utica Operations jointly own the Hopedale fractionation complex. Hopedale throughput is included in the Marcellus and Utica Operations and represent each region’s utilization of the complex.

(4) Purity ethane makes up approximately 246 mbpd and 210 mbpd of MPLX LP consolidated total fractionated products for the three months ended September 30, ~~2017, we calculated the following approximate percentages~~2023 and September 30, 2022, respectively, and approximately 240 mbpd and 195 mbpd of ~~our net operating margin from the following types of contracts:~~

Fee-Based
Percent-of-Proceeds⁽¹⁾

Keep-Whole⁽²⁾
L&S 100 % — % — %
G&P⁽³⁾
86 % 12 % 2 %
Total 92 % 7 % 1 %

~~For~~total fractionated products for the nine months ended September 30, ~~2017, we calculated~~2023 and September 30, 2022, respectively. Purity ethane makes up approximately 254 mbpd and 217 mbpd of MPLX LP Operated total fractionated products for the ~~following approximate percentages~~three months ended September 30, 2023 and September 30, 2022, respectively, and approximately 246 mbpd and 200 mbpd of ~~our net operating margin from~~total fractionated products for the ~~following types~~nine months ended September 30, 2023 and September 30, 2022, respectively.

(5) C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of ~~contracts:~~approximately 35 percent ethane, 35 percent propane, six percent Iso-Butane, 12 percent normal butane and 12 percent natural gasoline.

Seasonality

Fee-Based
Percent-of-Proceeds⁽¹⁾

Keep-Whole⁽²⁾
L&S 100 % — % — %
G&P⁽³⁾
87 % 11 % 2 %
Total 93 % 6 % 1 %


~~(1)~~	~~Includes condensate sales and other types of arrangements tied to NGL prices.~~


~~(2)~~	~~Includes condensate sales and other types of arrangements tied to both NGL and natural gas prices.~~


~~(3)~~	~~Includes unconsolidated affiliates (See Note 4 of the Notes to Consolidated Financial Statements).~~

~~The following table presents a reconciliation of net operating margin to income from operations, the most directly comparable GAAP financial measure.~~

Three Months Ended
September 30, Nine Months Ended
September 30,
(In millions) 2017 2016 2017 2016
Reconciliation of net operating margin to income from operations:
Segment revenues $ 1,047
$ 906
$ 2,964
$ 2,496
Purchased product costs (170 ) (117 ) (441 ) (310 )
Total derivative loss related to purchased product costs 11
4
5
16
Other (1 ) —
(5 ) (5 )
Net operating margin 887
793
2,523
2,197
Revenue adjustment from unconsolidated affiliates⁽²⁾
(107 ) (100 ) (287 ) (303 )
Realized derivative loss related to purchased product costs⁽¹⁾
(2 ) (1 ) (6 ) (4 )
Other 2
1
6
4
Unrealized derivative (losses) gains⁽¹⁾
(17 ) (2 ) 2
(23 )
Income (loss) from equity method investments 23
6
29
(72 )
Other income 2
2
5
5
Other income - related parties 22
22
69
67
Cost of revenues (excludes items below) (129 ) (122 ) (381 ) (329 )
Rental cost of sales (19 ) (13 ) (44 ) (42 )
Rental cost of sales - related parties —
—
(1 ) (1 )
Purchases - related parties (114 ) (109 ) (330 ) (286 )
Depreciation and amortization (164 ) (151 ) (515 ) (438 )
Impairment expense —
—
—
(130 )
General and administrative expenses (59 ) (56 ) (174 ) (172 )
Other taxes (14 ) (12 ) (40 ) (37 )
Income from operations $ 311
$ 258
$ 856
$ 436

~~(1)~~


~~(2)~~	These amounts relate to Partnership-operated unconsolidated affiliates. The chief operating decision maker and management include these to evaluate the segment performance as we continue to operate and manage the operations. Therefore, the impact of the revenue is included for segment reporting purposes, but removed for GAAP purposes.

~~SEASONALITY~~

The volume of crude oil and refined products transported ~~on our pipeline systems, at our barge dock~~ and stored atutilizing our ~~storage~~ assets is ~~directly~~ affected by the level of supply and demand for crude oil and refined products in the markets served directly or indirectly by our assets. ~~Many~~The majority of effects of seasonality on the L&S segment’s revenues ~~will be~~are mitigated through the use of ~~our~~ fee-based transportation and storage services agreements with MPC that include minimum volume commitments.

~~Our~~

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In our G&P segment, ~~can be affected by~~we experience minimal impacts from seasonal fluctuations inwhich impact the demand for natural gas and NGLs and the related ~~fluctuations in~~ commodity prices caused by various factors ~~such as changes in transportation and travel patterns and~~including variations in weather patterns from year to year. ~~However, we~~We are able to manage the seasonality ~~impact~~impacts through the execution of our marketing strategy. We have access to up to 50 million gallons of propane storage capacity in the Southern Appalachia region provided by an arrangement with a third party which provides us with flexibility to manage the seasonality impact. Overall, our exposure to the ~~seasonal~~seasonality fluctuations ~~in the commodity markets~~ is ~~declining~~limited due to the nature of our ~~growth in~~ fee-based business.

55Liquidity and Capital Resources

~~OPERATING DATA~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
L&S
Pipeline throughput (mbpd)⁽¹⁾

Crude oil pipelines 2,046
1,775
1,901
1,665
Product pipelines 1,131
992
1,051
989
Total pipelines 3,177
2,767
2,952
2,654

Average tariff rates ($ per barrel)⁽¹⁾⁽²⁾

Crude oil pipelines $ 0.54
$ 0.55
$ 0.57
$ 0.57
Product pipelines 0.75
0.69
0.74
0.67
Total pipelines 0.62
0.60
0.63
0.61

Terminal throughput (mbpd) 1,496
1,517
1,470
1,510

Marine Assets (number in operation)⁽³⁾

Barges 232
217
232
217
Towboats 18
18
18
18

G&P
Gathering Throughput (MMcf/d)
Marcellus Operations 1,005
946
965
922
Utica Operations⁽⁴⁾
1,324
916
1,065
936
Southwest Operations⁽⁵⁾
1,400
1,444
1,385
1,455
Total gathering throughput 3,729
3,306
3,415
3,313

Natural Gas Processed (MMcf/d)
Marcellus Operations 3,986
3,273
3,778
3,166
Utica Operations⁽⁴⁾
1,000
1,050
982
1,068
Southwest Operations 1,331
1,339
1,310
1,209
Southern Appalachian Operations 264
244
266
248
Total natural gas processed 6,581
5,906
6,336
5,691

C2 + NGLs Fractionated (mbpd)
Marcellus Operations⁽⁶⁾
326
274
310
254
Utica Operations⁽⁴⁾⁽⁶⁾
39
41
40
43
Southwest Operations 18
19
19
17
Southern Appalachian Operations⁽⁷⁾
14
14
15
16
Total C2 + NGLs fractionated⁽⁸⁾
397
348
384
330

Pricing Information
Natural Gas NYMEX HH ($ per MMBtu) $ 2.96
$ 2.80
$ 3.05
$ 2.34
C2 + NGL Pricing ($ per gallon)⁽⁹⁾
$ 0.66
$ 0.46
$ 0.62
$ 0.44


~~(1)~~	~~Pipeline throughput and tariff rates as of September 30, 2016 have been retrospectively adjusted to reflect the acquisition of HST.~~


~~(2)~~	~~Average tariff rates calculated using pipeline transportation revenues divided by pipeline throughput barrels.~~


~~(3)~~	~~Represents total at end of period.~~


~~(4)~~	~~Includes unconsolidated equity method investments that are shown consolidated for segment purposes only.~~

~~(5)~~

Includes approximately two MMcf/d related to the unconsolidated equity method investment, Wirth, for the three months ended September 30, 2017, and 230 MMcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the nine months ended September 30, 2017. Includes approximately 307 MMcf/d and 299 MMcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the three and nine months ended September 30, 2016, respectively.

~~(6)~~

Hopedale is jointly owned by Ohio Fractionation and MarkWest Utica EMG. Ohio Fractionation is a subsidiary of MarkWest Liberty Midstream. MarkWest Liberty Midstream and MarkWest Utica EMG are entities that operate in the Marcellus and Utica regions, respectively. The Marcellus Operations includes its portion utilized of the jointly owned Hopedale Fractionation Complex. The Utica Operations includes Utica’s portion utilized of the jointly owned Hopedale Fractionation Complex. Additionally, Sherwood Midstream has the right to fractionation revenue and the obligation to pay expenses related to 20 mbpd of capacity in the Hopedale 3 fractionator.


~~(7)~~	~~Includes NGLs fractionated for the Marcellus Operations and Utica Operations.~~


~~(8)~~	Purity ethane makes up approximately 164 mbpd and 160 mbpd of total fractionated products for the three and nine months ended September 30, 2017, respectively, and approximately 137 mbpd and 125 mbpd of total fractionated products for the three and nine months ended September 30, 2016, respectively.


~~(9)~~	C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of approximately 35 percent ethane, 35 percent propane, six percent Iso-Butane, 12 percent normal butane and 12 percent natural gasoline.

~~LIQUIDITY AND CAPITAL RESOURCES~~

Cash Flows

Our cash and cash equivalents ~~balance was $3~~were $960 million at September 30, ~~2017 compared to $234~~2023 and $238 million at December 31, ~~2016.~~2022. The change in cash and cash equivalents was due to the factors discussed below. Net cash provided by (used in) operating activities, investing activities and financing activities were as follows:


	Nine Months Ended September 30,							Nine Months Ended September 30,
(In millions)	2017			2016			(In millions)	2023		2022
Net cash provided by (used in):							Net cash provided by (used in):
Operating activities	$	1,338		$	975		Operating activities	$	3,908	$	3,651
Investing activities	(1,837		)	(892		)	Investing activities	(727)		(676)
Financing activities	268			82			Financing activities	(2,459)		(2,867)
Total	$	(231	)	$	165		Total	$	722	$	108

Net cash provided by operating activities increased ~~$363~~$257 million in the first nine months of ~~2017~~2023 compared to the same period of 2022, primarily due to improved results from operations and favorable working capital changes during the first nine months of 2016, the majority of which is related to an increase in adjusted EBITDA of $269 million. The favorable change in adjusted EBITDA was driven primarily by higher prices and volumes, the inclusion of MPLXT, since it was not formed as a business until April 1, 2016, and the acquisition of the Ozark pipeline. In addition, there was an increase in distributions received from unconsolidated affiliates of $25 million due2022 compared to the ~~acquisition~~same period of ~~an equity interest in the Bakken Pipeline system and the joint-interest acquisitions.~~2023.

Net cash used in investing activities increased ~~$945~~$51 million in the first nine months of ~~2017~~2023 compared to the ~~first nine months~~same period of ~~2016, primarily~~2022, due to the acquisition of an equity interest in the Bakken Pipeline system for $513 million, investments in other unconsolidated entities of approximately $177 million, $219 million for the acquisition of the Ozark pipeline, $30 million for the buy-out of an equity method investment partner, anhigher capital spending. The increase in cash used for additions to property, plant and equipment related to various capital projects, as well as a net decrease of $23 million in investment loans with MPC. Partially offsetting these items was a return of capital of $24 million from our acquisition of equity interests in Sherwood Midstream and Sherwood Midstream Holdings.

~~Financing activities were a $268 million source of cash~~ in the first nine months of ~~2017 compared~~2023 was partially offset by higher contributions to equity method investments for the first half of 2022, which included a ~~$82~~$60 million ~~source~~contribution to Dakota Access to fund our share of a scheduled debt repayment by the joint venture.

Net cash used in financing activities decreased $408 million in the first nine months of ~~2016.~~2023 compared to the same period of 2022. The ~~source~~decrease was driven by net borrowings in the first half of 2023 as compared to net repayments in the first half of 2022, resulting in a decreased use of cash of $861 million. There were no unit repurchases in the first nine months of ~~2017~~2023 resulting in a $315 million lower use of cash as compared to the same period of 2022. The decrease in the use of cash was primarily due to $2.2 billion of net proceeds from the New Senior Notes, $420 million of proceeds under the bank revolving credit facility, $128 million in contributions from noncontrolling interests and $483 million of net proceeds from sales of units under the ATM Program. ~~These items were~~ partially offset by ~~distributions~~the use of $600 million to ~~MPC of $1.9 billion for the acquisition of HST, WHC, MPLXT and the Joint-~~

~~Interest Acquisition~~, ~~$250 million repayment~~redeem all of the ~~term loan facility,~~outstanding Series B preferred units and by $171 million of higher distributions ~~of $49 million to Preferred unitholders, and increased distributions of $188 million~~paid to unitholders ~~and our general partner due mainly~~during the first nine months of 2023 compared to the ~~increase in units outstanding~~same period of 2022, as ~~well as~~ a result of the 10 percent increase in our base distribution effective for the ~~distribution per limited partner unit.~~third quarter of 2022.

Adjusted Free Cash Flow

The following table provides a reconciliation of Adjusted FCF and Adjusted FCF after distributions from net cash provided by operating activities for the three and nine months ended September 30, 2023 and September 30, 2022.


	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2023		2022			2023		2022
Net cash provided by operating activities(1)	$	1,244	$	1,039		$	3,908	$	3,651
Adjustments to reconcile net cash provided by operating activities to adjusted free cash flow
Net cash used in investing activities	(236)		(265)			(727)		(676)
Contributions from MPC	7		13			20		30

Distributions to noncontrolling interests	(11)		(10)			(30)		(29)
Adjusted free cash flow	1,004		777			3,171		2,976




Distributions paid to common and preferred unitholders	(799)		(755)			(2,419)		(2,248)
Adjusted free cash flow after distributions	$	205	$	22		$	752	$	728

(1) The three months endedSeptember 30, 2023 and September 30, 2022 include working capital builds of $56 million and $208 million, respectively. The nine months ended September 30, 2023 and September 30, 2022 include a working capital draw of $56 million and a working capital build of $60 million, respectively.

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Debt and Liquidity Overview

~~Our outstanding borrowings~~On February 9, 2023, MPLX issued $1.6 billion aggregate principal amount of notes, consisting of $1.1 billion principal amount of 5.00 percent senior notes due 2033 (the “2033 Senior Notes”) and $500 million principal amount of 5.65 percent senior notes due 2053 (the “2053 Senior Notes”). The 2033 Senior Notes were offered at ~~September 30, 2017 and December 31, 2016 consisted of the following:~~

(In millions) September 30, 2017 December 31, 2016
MPLX LP:
Bank revolving credit facility due 2022 $ 420
$ —
Term loan facility due 2019 —
250
5.500% senior notes due February 2023 710
710
4.500% senior notes due July 2023 989
989
4.875% senior notes due December 2024 1,149
1,149
4.000% senior notes due February 2025 500
500
4.875% senior notes due June 2025 1,189
1,189
4.125% senior notes due March 2027 1,250
—
5.200% senior notes due March 2047 1,000
—
Consolidated subsidiaries:
MarkWest - 4.500% - 5.500%, due 2023-2025 63
63
MPL - capital lease obligations due 2020 7
8
Total 7,277
4,858
Unamortized debt issuance costs (27 ) (7 )
Unamortized discount (401 ) (428 )
Amounts due within one year (1 ) (1 )
Total long-term debt due after one year $ 6,848
$ 4,422

~~The increase in debt as of September 30, 2017 compared to year-end 2016 was due~~a price to the public of 99.170 percent of par with interest payable semi-annually in arrears, commencing on September 1, 2023. The 2053 Senior Notes were offered at a price to the public of 99.536 percent of par with interest payable semi-annually in arrears, commencing on September 1, 2023.

On February 15, 2023, MPLX used $600 million of the net proceeds from the offering of the ~~New~~2033 Senior Notes ~~in the first quarter of 2017~~ and from borrowings on the intercompany loan with MPC and the bank revolving credit facility for general partnership purposes including the acquisitions of HST, WHC, MPLXT and the Joint-Interest Acquisition from MPC, the acquisition of our equity interest in MarEn Bakken, the acquisition2053 Senior Notes described above to redeem all of the ~~Ozark pipeline~~outstanding Series B preferred units. On March 13, 2023, MPLX used the remaining proceeds from the offering, and ~~capital expenditures. See Notes 3, 4~~cash on hand, to redeem all of MPLX’s and ~~14 of the Notes to Consolidated Financial Statements for additional information.~~

~~On July 21, 2017, the Partnership entered into a credit agreement to replace its previous $2.0~~MarkWest’s $1.0 billion five-year bank revolving credit facility with a $2.25 billion five-year bank revolving credit facility that expires in July 2022 (“MPLX Credit Agreement 2022”). The financial covenants and the interest rate terms contained in the new credit agreement are substantially the same as those contained in the previous bank revolving credit facility. Additionally, on July 19, 2017, MPLX LP prepaid the entire outstandingaggregate principal amount of ~~its $250 million term loan with cash on hand.~~4.50 percent senior notes due July 2023, at par, plus accrued and unpaid interest.

The MPLX Credit Agreement 2022 includes certain representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for an agreement of that type, and that could, among other things, limit our ability to pay distributions to our unitholders. The financial covenant requires us to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX Credit Agreement 2022) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. As of September 30, 2017, we were in compliance with this financial covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 3.4 to 1.0, as well as other covenants contained in the MPLX Credit Agreement 2022. As disclosed in Note 2 of the Notes to Consolidated Financial Statements, we expect the adoption of the lease accounting standards update to result in the recognition of a significant lease obligation. The MPLX Credit Agreement 2022 contains provisions under which the effects of the new accounting standard are not recognized for purposes of financial covenant calculation violations.

Our intention is to maintain an ~~investment grade~~investment-grade credit profile. As of September 30, ~~2017,~~2023, the credit ratings on our senior unsecured debt were ~~at or above investment grade level~~ as follows:



Rating Agency						Rating
Moody’s						~~Baa3~~Baa2 (stable outlook)
Standard & Poor’s						~~BBB-~~BBB (stable outlook)
Fitch						~~BBB-~~BBB (stable outlook)

The ratings reflect the respective views of the rating ~~agencies.~~agencies and should not be interpreted as a recommendation to buy, sell or hold our securities. Although it is our intention to maintain a credit profile that supports an investment grade rating, there is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. A rating from one rating agency should be evaluated independently of ratings from other rating agencies.

The ~~MPLX Credit Agreement 2022 does~~agreements governing our debt obligations do not contain credit rating triggers that would result in the acceleration of interest, principal or other payments solely in the event that our credit ratings are downgraded. However, any downgrades in the credit ratings of our senior unsecured debt ratings to below investment grade ratings ~~would~~could, among other things, increase the applicable interest rates and other fees payable under the MPLX Credit Agreement ~~2022~~ and may limit our ~~flexibility~~ability to obtain future ~~financing.~~financing, including refinancing existing indebtedness.

Our liquidity totaled ~~$2.1~~$4.5 billion at September 30, ~~2017~~2023 consisting of:


	September 30, 2023
(In millions)	Total Capacity		Outstanding Borrowings		Available Capacity
MPLX Credit Agreement(1)	$	2,000	$	—	$	2,000

MPC Loan Agreement	1,500		—		1,500
Total	$	3,500	$	—	3,500
Cash and cash equivalents					960
Total liquidity					$	4,460

September 30, 2017
(In millions) Total Capacity Outstanding Borrowings
Available
Capacity
MPLX LP - bank revolving credit facility expiring 2022⁽¹⁾
$ 2,250
$ (423 ) $ 1,827
MPC Investment - loan agreement 500
(202 ) 298
Total liquidity $ 2,750
$ (625 ) $ 2,125
Cash and cash equivalents 3
Total liquidity $ 2,128
(1) Outstanding borrowings include less than $1 million in letters of credit outstanding under this facility.


~~(1)~~	~~Outstanding borrowings include $3 million in letters of credit outstanding under this facility.~~

We expect our ongoing sources of liquidity to include cash generated from operations and borrowings under our revolving credit ~~agreements~~facilities and ~~issuances of additional debt and equity securities.~~access to capital markets. We believe that cash generated from these sources will be sufficient to meet our short-term and long-term funding requirements, including working capital requirements, capital expenditure requirements, contractual obligations, ~~repayment of debt maturities~~ and quarterly cash distributions. Our material future obligations include interest on debt, payments of debt principal, purchase obligations including contracts to acquire plant, property and equipment, and our operating leases and service agreements. We may also, from time to time, repurchase our senior notes or preferred units in the open market, in tender offers, in privately negotiated transactions or otherwise in such volumes, at market prices and upon such other terms as we deem appropriate and execute unit repurchases under our unit repurchase program. MPC manages our cash and cash equivalents on our behalf directly with third-party institutions as part of the treasury services that it provides to us under our omnibus agreement. From time to time, we may also consider utilizing other sources of liquidity, including the formation of joint ventures or sales of non-strategic assets.

MPLX’s credit agreement (the “MPLX Credit Agreement”) matures in July 2027 and contains certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for an agreement of this type. The financial covenant requires MPLX to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 during the nine-month period following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. Other

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covenants restrict us and/or certain of our subsidiaries from incurring debt, creating liens on assets and entering into transactions with affiliates. As of September 30, 2023, we were in compliance with this financial covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 3.4 to 1.0, as well as all other covenants contained in the MPLX Credit Agreement.

Equity and Preferred Units Overview

~~The table below summarizes the changes in the number of units outstanding through September 30, 2017:~~Unit Repurchase Program

(In units) Common Class B General Partner Total
Balance at December 31, 2016 357,193,288
3,990,878
7,371,105
368,555,271
Unit-based compensation awards 183,509
—
3,745
187,254
Issuance of units under the ATM Program 13,846,998
—
282,591
14,129,589
Contribution of HST/WHC/MPLXT 12,960,376
—
264,497
13,224,873
Contribution of the Joint-Interest Acquisition 18,511,134
—
377,778
18,888,912
Class B conversion 4,350,057
(3,990,878 ) 7,330
366,509
Balance at September 30, 2017 407,045,362
—
8,307,046
415,352,408

~~For more details on equity activity, see Notes 7 and 8 of the Notes to Consolidated Financial Statements.~~

On ~~July 1, 2017, all~~August 2, 2022, we announced the board authorization for the repurchase of ~~the remaining 3,990,878 Class B units automatically converted into 1.09~~up to $1.0 billion of MPLX LP common units held by the public. The authorization has no expiration date. We may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, accelerated unit repurchases, tender offers or open market solicitations for units, some of which may be effected through Rule 10b5-1 plans. The timing and ~~the right to receive $6.20 per unit in cash. MPC funded this cash payment, which reduced our liability payable to Class B~~amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.

~~unitholders by approximately $25 million on July 1, 2017. As a result of the Class B~~No units conversion on July 1, 2017, MPLX GP contributed less than $1 million in exchange for 7,330 general partner units to maintain its two percent general partner interest. As common units outstanding as of the August 7, 2017 record date, the converted Class B units participated in the second quarter distribution.

The Partnership expects the net proceeds from sales under the ATM Program will be used for general partnership purposes including repayment or refinancing of debt and funding for acquisitions, working capital requirements and capital expenditures. Duringwere repurchased during the nine months ended September 30, ~~2017, the sale of common units under the ATM Program generated net proceeds of approximately $473 million.~~2023. As of September 30, ~~2017, $1.7 billion of common units remain available for issuance through the ATM Program~~2023, we had $846 million remaining under the ~~Distribution Agreement.~~repurchase authorization.

~~MPC agreed to waive two-thirds~~Redemption of the ~~first quarter 2017 distributions~~Series B Preferred Units

On February 15, 2023, MPLX exercised its right to redeem all 600,000 outstanding Series B preferred units. MPLX paid unitholders the Series B preferred unit redemption price of $1,000 per unit. See Note 5 to the unaudited consolidated financial statements for more information.

Distributions on the ~~common~~Series B preferred units ~~issued~~were payable semi-annually in ~~connection with~~arrears on the ~~acquisition of HST, WHC and MPLXT. As a result of this waiver, MPC did not receive general partner distributions~~15th day, or ~~IDRs that would have otherwise accrued on such common units with respect to~~ the first ~~quarter 2017 distributions. The value~~business day thereafter, of February and August of each year up to and including February 15, 2023. In accordance with these ~~waived distributions was $6 million. Additionally, in connection with our acquisition~~terms, MPLX made a final cash distribution of ~~a partial, indirect equity interest in the Bakken Pipeline system~~$21 million to Series B preferred unitholders on February 15, ~~2017, MPC agreed to waive its right to receive incentive distributions of $1.6 million per quarter for twelve consecutive quarters beginning~~2023, in conjunction with the distributions declared in the first quarter of 2017 and paid to MPC in the second quarter of 2017, which was prorated from the acquisition date. Lastly, MPC agreed to waive two-thirds of the third quarter 2017 distributions on the common units issued in connection with the Joint-Interest Acquisition. As a result of this waiver, MPC did not receive the distributions or IDRs that would have otherwise accrued on such common units with respect to the third quarter 2017 distributions. The value of these waived distributions was $10 million.redemption.

Distributions

We intend to pay ~~at least the~~a minimum quarterly distribution to the holders of our common units of $0.2625 per unit, or $1.05 per ~~quarter, which equates~~unit on an annualized basis, to ~~$109~~the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. The amount of distributions paid under our policy and the decision to make any distributions is determined by our general partner, taking into consideration the terms of our partnership agreement. Such minimum distribution would equate to $263 million per quarter, or ~~$436~~$1,051 million per year, based on the number of common ~~and general partner~~ units outstanding at September 30, ~~2017.~~ 2023.

On October ~~25, 2017, we announced the board of directors of our general partner had~~24, 2023, MPLX declared a cash distribution for the third quarter of ~~$0.5875~~2023, totaling $851 million, or $0.850 per ~~unit that~~common unit. This distribution will be paid on November ~~14, 2017~~13, 2023 to common unitholders of record on November 6, 2017. This represents an increase of $0.0250 per unit, or four percent, above the second quarter 2017 distribution of $0.5625 per unit and an increase of 14 percent over the third quarter 2016 distribution. This increase in the distribution is consistent with our intent to maintain an attractive distribution growth profile over an extended period of time.3, 2023. Although our ~~Partnership Agreement~~partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) each quarter, we do not otherwise have a legal obligation to distribute any particular amount per common unit. This rate will also be received by Series A preferred unitholders.

The allocation of total ~~quarterly~~ cash distributions ~~to general and limited partners~~ is as follows for the three and nine months ended September 30, ~~2017~~2023 and ~~2016. Our~~September 30, 2022. MPLX’s distributions are declared subsequent to quarter end; therefore, the following table represents total cash distributions applicable to the period in which the distributions were earned.


	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions, except per unit data)	2023		2022		2023		2022
Distribution declared:
Limited partner units - public	$	301	$	275	$	849	$	789
Limited partner units - MPC	550		502		1,554		1,415




Total LP distribution declared	851		777		2,403		2,204
Series A preferred units	25		23		71		65
Series B preferred units(1)	—		10		5		31
Total distribution declared	$	876	$	810	$	2,479	$	2,300

Quarterly cash distributions declared per limited partner common unit	$	0.850	$	0.775	$	2.400	$	2.185

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
Distribution declared:
Limited partner units - public $ 170
$ 135
$ 481
$ 393
Limited partner units - MPC 54
44
152
114
Limited partner units - GP 8
—
15
—
General partner units - MPC 7
5
18
13
IDRs - MPC 81
49
211
135
Total GP & LP distribution declared 320
233
877
655
Redeemable preferred units 16
16
49
25
Total distribution declared $ 336
$ 249
$ 926
$ 680

Cash distributions declared per limited partner common unit $ 0.5875
$ 0.5150
$ 1.6900
$ 1.5300

~~Our intentions regarding~~(1) The nine months ended September 30, 2023 includes the portion of the $21 million distribution growth profile expressed above include forward-looking statements. Such forward-looking statements are not guarantees of future performance and are subject to risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Factors that could cause actual results to differ materially from those implied in the forward-looking statements include: the adequacy of our capital resources and liquidity, including, but not limitedpaid to the ~~availability of sufficient cash flow~~Series B preferred unitholders on February 15, 2023 that was earned during the period prior to ~~pay distributions and execute our business plan; negative capital market conditions, including an increase of the current yield on common units; the timing and extent of changes in commodity prices~~

redemption.

~~and demand for natural gas, NGLs, crude oil, feedstocks or refined petroleum products; volatility in and/or degradation~~Table of market and industry conditions; completion of midstream capacity by our competitors; disruptions due to equipment interruption or failure, including electrical shortages and power grid failures; the suspension, reduction or termination of MPC’s obligations under our commercial agreements; our ability to successfully implement our growth plan, whether through organic growth or acquisitions; modifications to earnings and distribution objectives; state and federal environmental, economic, health and safety, energy and other policies and regulations; changes to our capital budget; financial stability of our producer customers and MPC; other risk factors inherent to our industry; and the factors set forth under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016. In addition, the forward-looking statements included herein could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed here or in our SEC filings could also have material adverse effects on forward-looking statements.Contents

~~MPC Strategic Actions~~

On January 3, 2017, MPC announced its plans to offer the Partnership the opportunity to acquire assets contributing an estimated $1.4 billion of annual EBITDA. The Partnership's plans for funding the dropdowns include debt and equity in approximately equal proportions, with the equity financing to be funded through transactions with MPC. In conjunction with the completion of the dropdowns, MPC announced its intentions to offer to exchange its IDRs and two percent GP Interest for common units. Following these transactions, we expect to internally fund a greater portion of our future growth from internal cash flows. The first drop of assets contributing approximately $250 million of annual EBITDA took place in the first quarter of 2017 and was financed through cash and equity, as discussed in Note 3 of the Notes to Consolidated Financial Statements. The second drop of assets contributing approximately $138 million of annual EBITDA took place in the third quarter of 2017 and was financed through cash and equity, as discussed in Note 3 of the Notes to Consolidated Financial Statements. The remaining dropdown, which includes refinery logistics assets and fuels distribution services, with projected annual EBITDA of approximately $1.0 billion has been offered to the Partnership and referred to the conflicts committee of the board of directors of our general partner. The transaction is expected to close no later than the end of the first quarter of 2018.

Capital Expenditures

Our operations are capital intensive, requiring investments to expand, upgrade, enhance or maintain existing operations and to meet environmental and operational regulations. Our capital requirements consist of ~~maintenance~~growth capital expenditures and maintenance capital expenditures. Growth capital expenditures are those incurred for acquisitions or capital improvements that we expect will increase our operating capacity for volumes gathered, processed, transported or fractionated, decrease operating expenses within our facilities or increase operating income over the long term. Examples of growth capital ~~expenditures. Examples of~~expenditures include costs to develop or acquire additional pipeline, terminal, processing or storage capacity. In general, growth capital includes costs that are expected to generate additional or new cash flow for MPLX. In contrast, maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. ~~In contrast,~~

MPLX’s initial capital investment plan for 2023 totals $950 million, net of reimbursements, which includes growth capital ~~expenditures are those incurred for acquisitions or~~of $800 million and maintenance capital improvements that we expect will increase our operating capacity to increase volumes gathered, processed, transported or fractionated, decrease operating expenses within our facilities or increase operating income over the long term. Examples of ~~growth~~$150 million. Growth capital expenditures ~~include~~and investments in affiliates during the ~~acquisition of equipment or the construction costs associated with new well connections,~~nine months ended September 30, 2023 were primarily for gas processing plants and ~~the development or acquisition of additional pipeline, processing or storage capacity. In general, growth capital includes costs that are expected to generate additional or new cash flow for us.~~

~~Our capital expenditures are shown~~gathering projects in the ~~table below:~~

Nine Months Ended September 30,
(In millions) 2017 2016
Capital expenditures:
Maintenance $ 59
$ 58
Expansion 1,002
889
Total capital expenditures 1,061
947
Less: Increase in capital accruals 55
—
Asset retirement expenditures 2
4
Additions to property, plant and equipment 1,004
943
Capital expenditures of unconsolidated subsidiaries⁽¹⁾
306
94
Total gross capital expenditures 1,310
1,037
Less: Joint venture partner contributions⁽²⁾
132
45
Total capital expenditures, net 1,178
992
Less: Maintenance capital 60
58
Total growth capital $ 1,118
$ 934


~~(1)~~	~~Includes amounts related to unconsolidated, Partnership-operated subsidiaries.~~


~~(2)~~	~~This represents estimated joint venture partners’ share of growth capital.~~

Our organic growth capital plan range has not been revised for the remainder of 2017. We anticipate finishing the year near below the previously reported range. This range excludes acquisition costs for the dropdowns of HST, WHC, MPLXTMarcellus and ~~the Joint-Interest Acquisition, the acquisition of the Ozark pipeline and the MarEn Bakken investment,~~Permian basins, as ~~discussed in Notes 3 and 4 of the Notes~~well as additions to Consolidated Financial Statements. The range also excludes non-affiliated joint venture members’ share of capital expenditures. The G&P segment capital plan includes investments that are expected to support producer customers and complete certain processing plants currently under construction at the Sherwood Complex. The L&S segment capital plan includes the development of various crude oil and refined petroleum products infrastructure projects, a butane cavern and a tank farm expansion, and an expansion project to increase line capacity on the Ozark pipeline. We also have large organic growth prospects associated with the anticipated growth of MPC’s operations and third-party activity in our ~~areas of operation that we anticipate will provide attractive returns and cash flows.~~brown water marine fleet. We continuously evaluate our capital plan and make changes as conditions warrant.

Our capital expenditures are shown in the table below:


	Nine Months Ended September 30,
(In millions)	2023		2022
Capital expenditures:
Growth capital expenditures	$	555	$	451
Growth capital reimbursements(1)	(119)		(70)
Investments in unconsolidated affiliates	90		198
Return of capital	—		(11)
Capitalized interest	(10)		(6)
Total growth capital expenditures(2)	516		562
Maintenance capital expenditures	113		123
Maintenance capital reimbursements	(20)		(30)
Capitalized interest	(1)		(1)
Total maintenance capital expenditures	92		92

Total growth and maintenance capital expenditures	608		654
Investments in unconsolidated affiliates(3)	(90)		(198)
Return of capital	—		11
Growth and maintenance capital reimbursements(4)	139		100
Increase in capital accruals	(6)		(39)
Capitalized interest	11		7
Additions to property, plant and equipment(3)	$	662	$	535

(1) Growth capital reimbursements include reimbursements from customers and our Sponsor.

(2) Total growth capital expenditures exclude $28 million of acquisitions for the nine months ended September 30, 2022.

(3) Investments in unconsolidated affiliates and additions to property, plant and equipment are shown as separate lines within investing activities in the Consolidated Statements of Cash Flows.

(4) Growth capital reimbursements are included in changes in deferred revenue within operating activities in the Consolidated Statements of Cash Flows. Maintenance capital reimbursements are included in the Contributions from MPC line within financing activities in the Consolidated Statements of Cash Flows.

Contractual Cash Obligations

As of September 30, ~~2017,~~2023, our contractual cash obligations included ~~long-term~~ debt, ~~capital~~finance and operating lease obligations, purchase obligations for services and to acquire property, plant and equipment, and other liabilities. During the nine months ended September 30, ~~2017,~~2023, our ~~long-term~~ debt obligations increased by ~~$4.1 billion~~$600 million due to the ~~new~~issuance of senior notes ~~issued~~ and ~~contracts to acquire property, plant~~use of proceeds described above in Liquidity and ~~equipment increased $317 million largely due to new~~Capital Resources-Debt and ~~growing projects.~~Liquidity Overview. There were no other material changes to ~~these~~our contractual obligations outside the ordinary course of business since December 31, ~~2016.~~2022.

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Off-Balance Sheet Arrangements

~~As of September 30, 2017, we have not entered into any transactions, agreements or other~~Off-balance sheet arrangements comprise those arrangements that ~~would result in off-balance sheet liabilities.~~

~~Forward-looking Statements~~

~~Our opinions concerning~~may potentially impact our liquidity, ~~and~~ capital resources and ~~our ability~~results of operations, even though such arrangements are not recorded as liabilities under GAAP. Our off-balance sheet arrangements are limited to ~~avail ourselves~~guarantees that are described in ~~the future~~Note 15 of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors, including cash provided by operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the globalunaudited consolidated financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and future credit ratings by rating agencies. The discussion of liquidity and capital resources above also contains forward-looking statements regarding expected capital spending. The forward-looking statements about our capital budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include negative capital market conditions, including an increase of the current yield on common units, adversely affecting the Partnership’s ability to meet its distribution growth guidance; the time, costs and ability to obtain regulatory or other approvals and consents and otherwise consummate the strategic initiatives discussed herein and other proposed transactions; the satisfaction or waiver of conditions in the agreements governing the strategic initiatives discussed herein and other proposed transactions; our ability to achieve the strategic and other objectives related to the strategic initiatives and transactions discussed herein, including the dropdown from MPC and the proposed exchange of common units for MPC’s economic interests in the general partner, the joint venture with Antero Midstream, the Ozark pipeline acquisition, and other proposed transactions; adverse changes in laws including with respect to tax and regulatory matters; the inability to agree with respect to the timing of and value attributed to assets identified for dropdown and/or the economic interests in the general partner; the adequacy of the Partnership’s capital resources and liquidity, including, but not limited to, availability of sufficient cash flow to pay distributions, and the ability to successfully execute its business plans and growth strategy; continued/further volatility in and/or degradation of market and industry conditions; changes to the expected construction costs and timing of projects; civil protests and resulting legal/regulatory uncertainty regarding environmental and social issues, including pipeline infrastructure, may prevent or delay the construction and operation of such infrastructure and realization of associated revenues; completion of midstream infrastructure by competitors; disruptions due to equipment interruption or failure, including electrical shortages and power grid failures; the suspension, reduction or termination of MPC's obligations under the Partnership’s commercial agreements; modifications to earnings and distribution growth objectives; the level of support from MPC, including dropdowns, alternative financing arrangements, taking equity units, and other methods of sponsor support, as a result of the capital allocation needs of the enterprise as a whole and its ability to provide support on commercially reasonable terms; compliance with federal and state environmental, economic, health and safety, energy and other policies and regulations and/or enforcement actions initiated thereunder; changes to the Partnership’s capital budget; prices of and demand for natural gas, NGLs, crude oil and refined products; delays in obtaining necessary third-party approvals and governmental permits; changes in labor, material and equipment costs and availability; planned and unplanned outages, the delay of, cancellation of or failure to implement planned capital projects; project overruns, disruptions or interruptions of our operations due to the shortage of skilled labor; unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response; and other operating and economic considerations. These factors, among others, could cause actual results to differ materially from those set forth in the forward-looking statements. For additional information on forward-looking statements and ~~risks that can affect our business, see “Disclosures Regarding Forward-Looking Statements” and Item 1A. Risk Factors~~indemnities as disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2022.

~~TRANSACTIONS WITH RELATED PARTIES~~Although these arrangements serve a variety of our business purposes, we are not dependent on them to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on our liquidity and capital resources.

Transactions with Related Parties

At September 30, ~~2017,~~2023, MPC owned our non-economic general partnership interest and held ~~a two percent GP Interest and a 28.4 percent limited partner interest in MPLX LP.~~

~~Excluding revenues attributable to volumes shipped by MPC under joint tariffs with third parties that are treated as third-party revenues for accounting purposes, MPC accounted for 36 percent and 40~~approximately 65 percent of our ~~total revenues and other income for the third quarter of 2017 and 2016, respectively.~~ outstanding common units.

We provide to MPC with crude oil and product pipeline based on regulated tariff/contracted rates, as well as storage, terminal, fuels distribution, and inland marine transportation services based on ~~regulated tariff rates and storage services and inland marine transportation based on~~ contracted rates.

~~Of our total costs and expenses,~~ We also have agreements with MPC ~~accounted~~under which we receive fees for ~~22 percent and 25 percent~~operating MPC’s retained pipeline assets, providing management services for the ~~third quarter~~marine business, and operating certain of ~~2017 and 2016, respectively.~~MPC’s equity method investments. MPC ~~performed~~provides us with certain services ~~for us~~ related to information technology, engineering, legal, accounting, treasury, human resources and other administrative ~~services.~~services under employee services and omnibus services agreements.

~~We believe that transactions~~The below table shows the percentage of Total revenues and other income as well as Total costs and expenses with ~~related parties were conducted under terms comparable to those with unrelated parties.~~ MPC:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Total revenues and other income(1)	49	%	46	%	50	%	46	%
Total costs and expenses	29	%	24	%	28	%	24	%

(1) 2022 periods exclude gain on sales-type leases.

For further discussion of agreements and activity with MPC and related parties see Item 1. Business in our Annual Report on Form 10-K for the year ended December 31, ~~2016~~2022 and Note ~~5 of~~4 to the ~~Notes to Consolidated Financial Statements~~unaudited consolidated financial statements in this report.

Environmental Matters and Compliance Costs

~~ENVIRONMENTAL MATTERS AND COMPLIANCE COSTS~~

We have incurred and may continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including, but not limited to, the age and location of its operating facilities.

As previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2022, actual expenditures may vary as the number and scope of ~~September 30, 2017, there~~environmental projects are revised as a result of improved technology or changes in regulatory requirements. There have been no ~~significant~~material changes to our environmental matters and compliance costs since our Annual Report on Form 10-K for the year ended December 31, ~~2016, as updated by our Current Report on Form 8-K filed on May 1, 2017.~~2022.

~~CRITICAL ACCOUNTING ESTIMATES~~Critical Accounting Estimates

As of September 30, ~~2017,~~2023, there have been no significant changes to our critical accounting estimates since our Annual Report on Form 10-K for the year ended December 31, ~~2016, as updated by~~2022.

Accounting Standards Not Yet Adopted

We have not identified any recent accounting pronouncements that are expected to have a material impact on our ~~Current Report on Form 8-K filed on May 1, 2017.~~

~~ACCOUNTING STANDARDS NOT YET ADOPTED~~

Asfinancial condition, results of operations or cash flows upon adoption. Accounting standards are discussed in Note 2 of the ~~Notes to Consolidated Financial Statements, certain new~~unaudited consolidated financial ~~accounting pronouncements will be effective for our financial statements in the future.~~statements.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

~~Market risk includes~~We are exposed to market risks related to the ~~risk~~volatility of ~~loss arising from adverse~~commodity prices. We employ various strategies, including the use of commodity derivative instruments, to economically hedge the risks related to these price fluctuations. We are also exposed to market risks related to changes in ~~market rates and prices. We face market risk from commodity price changes and,~~interest rates. As of September 30, 2023, we did not have any open financial derivative instruments to ~~a lesser extent,~~hedge the economic risks related to interest rate ~~changes~~fluctuations; however, we continually monitor the market and ~~non-performance by~~ our ~~customers~~exposure and ~~counterparties.~~may enter into these arrangements in the future.

Commodity Price Risk

The information about commodity price risk for the three and nine months ended September 30, ~~2017~~2023 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2022.

Outstanding Derivative Contracts and Sensitivity Analysis

~~The following tables provide~~See Notes 9 and 10 to the unaudited consolidated financial statements for more information onabout the ~~volume~~fair value measurement of our derivative ~~activity~~instruments, as well as the amounts recorded in our consolidated balance sheets and statements of income. We do not designate any of our commodity derivative instruments as hedges for accounting purposes.

Our open derivative positions ~~related to long liquids price risk~~ at September 30, ~~2017, including~~2023 will expire at various times through 2023. We prepared a sensitivity analysis to estimate our exposure to market risk associated with our derivative instruments. Based on our open net positions at September 30, 2023, a 10 percent change in quoted market prices of our derivative instruments, assuming all other factors remain constant, could change the ~~weighted-average prices (“WAVG”):~~

WTI Crude Swaps Volumes (Bbl/d) WAVG Price
(Per Bbl) Fair Value
(in thousands)
2017 (Oct - Dec) 200
$ 54.25
$ 42

Natural Gas Swaps Volumes (MMBtu/d) WAVG Price
(Per MMBtu) Fair Value
(in thousands)
2017 (Oct - Dec) 1,832
$ 3.03
$ (30 )
2018 2,542
$ 2.78
$ 4

Ethane Swaps Volumes (Gal/d) WAVG Price
(Per Gal) Fair Value
(in thousands)
2017 (Oct - Dec) 54,600
$ 0.27
$ (47 )

Propane Swaps Volumes (Gal/d) WAVG Price
(Per Gal) Fair Value
(in thousands)
2017 (Oct - Dec) 119,932
$ 0.61
$ (3,164 )
2018 16,925
$ 0.64
$ (506 )

IsoButane Swaps Volumes (Gal/d) WAVG Price
(Per Gal) Fair Value
(in thousands)
2017 (Oct - Dec) 10,730
$ 0.81
$ (236 )
2018 1,655
$ 0.80
$ (38 )

Normal Butane Swaps Volumes (Gal/d) WAVG Price
(Per Gal) Fair Value
(in thousands)
2017 (Oct - Dec) 31,622
$ 0.75
$ (823 )
2018 4,595
$ 0.75
$ (120 )

Natural Gasoline Swaps Volumes (Gal/d) WAVG Price
(Per Gal) Fair Value
(in thousands)
2017 (Oct - Dec) 41,827
$ 1.13
$ (346 )
2018 3,089
$ 1.18
$ (20 )

We have a commodity contract with a producer customer in the Southern Appalachian region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. For accounting purposes, these contracts have been aggregated into a single contract and are evaluated together. In February 2011, we executed agreements with the producer customer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022, with the producer customer’s option to extend the agreement for two successive five-year terms through December 31, 2032. The purchase of gas at prices based on the frac spread and the option to extend the agreements have been identified as a single embedded derivative, which is recorded at fair value. The probability of renewal is determined based on extrapolated pricing curves, a review of the overall expected favorability of the contracts based on such pricing curves and assumptions about the counterparty’s potential

~~business strategy decision points that may exist at the time the counterparty would elect whether to renew the contracts. The changes in~~ fair value of ~~this embedded~~our derivative ~~are based on the difference between the contractual~~instruments and index pricing, the probability of the producer customer exercising its option to extend and the estimated favorability of these contracts compared to current market conditions. The changes in fair value are recorded in earnings through ~~Purchased product costs~~ ~~in the Consolidated Statements of Income. As of September 30, 2017, the estimated fair value of this contract was a liability of $52~~Income before income taxes by $1.0 million. This analysis may differ from actual results.

We have a commodity contract that gives us an option to fix a component of the utilities cost to an index price on electricity at a plant location in the Southwest through the fourth quarter of 2018. The contract’s pricing is currently fixed through the fourth quarter of 2017 with the ability to fix the pricing for its remaining year. Changes in the fair value as of the derivative component of this contract were recognized as ~~Cost of Revenues~~ ~~in the Consolidated Statements of Income. As of September 30, 2017, the estimated fair value of this contract was a liability of less than $1 million.~~

Interest Rate Risk and Sensitivity Analysis

Sensitivity analysis of the effect of a hypothetical 100-basis-point change in interest rates on ~~long-term~~outstanding third-party debt, excluding ~~capital~~finance leases, is provided in the following table. Fair value of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.


(In millions)	Fair value as of September 30, 2017⁽¹⁾		Change in Fair Value⁽²⁾		Change in Income Before Income Taxes for the Nine Months Ended September 30, 2017⁽³⁾		(In millions)	Fair Value as of September 30, 2023(1)		Change in Fair Value(2)		Change in Income Before Income Taxes for the Three Months Ended September 30, 2023(3)
Long-term debt
Outstanding debt							Outstanding debt
Fixed-rate	$	7,199	$	575	N/A		Fixed-rate	$	17,922	$	1,363	N/A
Variable-rate	$	420	N/A		$	2
Variable-rate(4)							Variable-rate(4)	$	—	$	—	$	—

(1) Fair value was based on market prices, where available, or current borrowing rates for financings with similar terms and maturities.


~~(1)~~	~~Fair value was based on market prices, where available, or current borrowing rates for financings with similar terms and maturities.~~


~~(2)~~	~~Assumes a 100-basis-point decrease in the weighted average yield-to-maturity at September 30, 2017.~~


~~(3)~~	Assumes a 100-basis-point change in interest rates. The change to net income was based on the weighted average balance of all outstanding variable-rate debt for the nine months ended September 30, 2017.

(2) Assumes a 100-basis-point decrease in the weighted average yield-to-maturity at September 30, 2023.

(3) Assumes a 100-basis-point change in interest rates. The change to income before income taxes was based on the weighted average balance of all outstanding variable-rate debt for the nine months ended September 30, 2023.

(4) MPLX had no outstanding borrowings on the MPLX Credit Agreement as of September 30, 2023.

At September 30, ~~2017,~~2023, our portfolio of ~~long-term~~third‑party debt consisted of fixed-rate instruments and ~~variable-rate instruments~~outstanding borrowings, if any, under ~~our term loan facility.~~the MPLX Credit Agreement. The fair value of our fixed-rate debt is relatively sensitive to interest rate fluctuations. Our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices above carrying value. Interest rate fluctuations generally do not impact the fair value of borrowings under our ~~bank revolving credit or term loan facilities,~~MPLX Credit Agreement, but may affect our results of operations and cash flows. As of September 30, 2017, we did not have any financial derivative instruments to hedge the risks related to interest rate fluctuations; however, we continually monitor the market and our exposure and may enter into these agreements

See Note 9 in the ~~future.~~unaudited consolidated financial statements for additional information on the fair value of our debt.

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules ~~13(a)-15(e)~~13a-15(e) and ~~15(d)-15(e)~~15d-15(e) under the Securities Exchange Act of 1934, as amended) was carried out under the supervision and with the participation of management, including the chief executive officer and chief financial officer of our general partner. Based upon that evaluation, the chief executive officer and chief financial officer of our general partner concluded that the design and operation of these disclosure controls and procedures were effective as of September 30, ~~2017~~,2023, the end of the period covered by this report.

Changes in Internal Control Over Financial Reporting

During the quarter ended September 30, ~~2017,~~2023, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II – Other Information

Item 1. Legal Proceedings

We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. While it is possible that an adverse result in one or more of the lawsuits or proceedings in which we are a defendant could be material to us, based upon current information and our experience as a defendant in other matters, we believe that these lawsuits and proceedings, individually or in the aggregate, will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Item 103 of Regulation S-K promulgated by the SEC requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions, unless we reasonably believe that the matter will result in no monetary sanctions, or in monetary sanctions, exclusive of interest and costs, of less than a specified threshold. We use a threshold of $1 million for this purpose.

Except as described below, there have been no material changes to the legal matters previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2022, or in our Quarterly Report on Form 10-Q for the quarters ended March 31, 2023 and June 30, 2023.

Dakota Access Pipeline

As ~~previously~~ reported in our Annual Report on Form 10-K for the year ended December 31, ~~2016,~~2022, MPLX holds a 9.19 percent indirect interest in ~~July 2015, representatives from~~Dakota Access, which owns and operates the ~~EPA and~~Bakken Pipeline system. In 2020, the United States Department of Justice conducted a raid on a MarkWest Liberty Midstream pipeline launcher/receiver site utilized for pipeline maintenance operations in Washington County, Pennsylvania pursuant to a search warrant issued by a magistrate of the United StatesU.S. District Court for the ~~Western~~ District of ~~Pennsylvania. As part of this initiative,~~Columbia (the “D.D.C.”) ordered the U.S. ~~Attorney’s Office~~Army Corps of Engineers (“Army Corps”), which granted permits and an easement for the ~~Western District of Pennsylvania proceeded~~Bakken Pipeline system, to prepare an environmental impact statement (“EIS”) relating to an easement under Lake Oahe in North Dakota. The D.D.C. later vacated the easement. The Army Corps issued a draft EIS in September 2023 detailing various options for the easement going forward, including denying the easement, approving the easement with ~~an investigation of MarkWest Liberty Midstream’s launcher/receiver, pipeline~~additional measures, rerouting the easement, or approving the easement with no changes. The Army Corps has not selected a preferred alternative, but will make a decision in its final review, after considering input from the public and ~~compressor station operations. In response~~other agencies. The Army Corps has not provided a definitive date as to when a final decision would be issued.

We have entered into a Contingent Equity Contribution Agreement whereby MPLX LP, along with the other joint venture owners in the Bakken Pipeline system, has agreed to make equity contributions to the ~~investigation, MarkWest initiated independent studies which demonstrated~~joint venture upon certain events occurring to allow the entities that ~~there was no risk~~own and operate the Bakken Pipeline system to ~~worker safety and no threat of public harm associated with MarkWest Liberty Midstream’s launcher/receiver operations. These findings~~satisfy their senior note payment obligations. The senior notes were ~~supported by a subsequent inspection and review~~issued to repay amounts owed by the ~~Occupational Safety~~pipeline companies to fund the cost of construction of the Bakken Pipeline system.

If the vacatur of the easement results in a temporary shutdown of the pipeline, MPLX would have to contribute its 9.19 percent pro rata share of funds required to pay interest accruing on the notes and ~~Health Administration. After providing these studies,~~any portion of the principal that matures while the pipeline is shutdown. MPLX also expects to contribute its 9.19 percent pro rata share of any costs to remediate any deficiencies to reinstate the easement and/or return the pipeline into operation. If the vacatur of the easement results in a permanent shutdown of the pipeline, MPLX would have to contribute its 9.19 percent pro rata share of the cost to redeem the bonds (including the one percent redemption premium required pursuant to the indenture governing the notes) and ~~other substantial documentation related to MarkWest Liberty Midstream's pipeline~~any accrued and ~~compressor stations, and arranging site visits and conducting several meetings with~~unpaid interest. As of September 30, 2023, our maximum potential undiscounted payments under the ~~government’s representatives,~~Contingent Equity Contribution Agreement were approximately $170 million.

Edwardsville Incident

As reported in our Annual Report on ~~September 13, 2016, the U.S. Attorney’s Office~~Form 10-K for the ~~Western District of Pennsylvania rendered a declination decision, dropping its criminal investigation and declining to pursue charges~~year ended December 31, 2022, in ~~this matter.~~

~~MarkWest Liberty Midstream continues to discuss with the EPA and~~March 2022, the State of ~~Pennsylvania~~Illinois brought an action in Madison County Circuit Court in Illinois against Marathon Pipe Line LLC (“MPL”), an indirect wholly owned subsidiary of MPLX, asserting various violations and demanding a permanent injunction and civil ~~enforcement allegations associated with permitting or other related regulatory obligations for its launcher/receiver and compressor station facilities~~penalties in ~~the region. In~~ connection with ~~these discussions, MarkWest Liberty Midstream received an initial proposal~~a release of crude oil on the Wood River to Patoka 22" line near Edwardsville, Illinois in March 2022. In September 2023, the U.S. Department of Justice and EPA confirmed they will be pursuing federal enforcement for alleged Clean Water Act violations arising from this incident as well as other pipeline releases. We cannot currently estimate the ~~EPA to settle all~~amount of any civil ~~claims associated with~~penalty or the timing of the resolution of this matter ~~for the combination~~but do not believe any civil penalty will have a material impact on our consolidated results of ~~a proposed~~operations, financial position or cash penalty of approximately $2.4 million and proposed supplemental environmental projects with an estimated cost of approximately $3.6 million. MarkWest Liberty Midstream has submitted a response asserting that this action involves novel issues surrounding primarily minor source emissions from facilities that the agencies themselves considered de minimis and were not the subject of regulation and consequently that the settlement proposal is excessive. In connection with these negotiations, MarkWest Liberty Midstream has received a revised settlement proposal from the EPA which proposes to lower the proposed cash penalty to approximately $1.24 million and the estimated cost of proposed supplemental environmental projects to an estimated cost of approximately $1.6 million. MarkWest Liberty Midstream will continue to negotiate with EPA regarding the amount and scope of the proposed settlement.flows.

Item 1A. Risk Factors

~~We are subject to various risks and uncertainties in~~There have been no material changes from the ~~course of our business. The discussion of such risks and uncertainties may be found under Item 1A. Risk Factors~~risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2022.

Table of Contents

~~Item 2. Unregistered Sales of Equity Securities~~

In connection with the issuance of 14,887 common units upon the vesting of phantom units under the MPLX LP 2012 Incentive Compensation Plan, 359,179 common units as a result of the conversion of Class B units to common units and 1,184,335 common units under the ATM Program, our general partner purchased an aggregate of 31,803 general partner units for $1,059,390.81 in cash during the three months ended September 30, 2017, to maintain its two percent general partner interest in us. The general partner units were issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended.

On September 1, 2017, in connection with the Joint-Interest Acquisition, we issued 377,778 general partner units to our general partner. The number of general partner units issued were calculated by dividing $12,600,000 by 33.3529, the simple average of the ten day trading volume weighted average NYSE price of an MPLX LP common unit for the ten trading days ending at market close on August 31, 2017. The general partner units were issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended.

Item 5. Other Information

~~Amended Restricted Stock Award Agreement~~

~~On October 26, 2017, C. Corwin Bromley entered into an Amended Restricted Stock Award Agreement with MPC (the “Amended Award Agreement”) to provide for~~During the immediate vesting of a restricted stock award upon Mr. Bromley’s retirement effective January 1, 2018, which was announced by MPLX LP (the “Partnership”) on August 4, 2017. Mr. Bromley was a named executive officer in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016.

The foregoing description of the Amended Award Agreement is summary in nature and subject to, and qualified in its entirety by, the full text of the Amended Award Agreement, a copy of which is attached as Exhibit 10.2 to this Quarterly Report on Form 10-Q for the quarterly periodquarter ended September 30, ~~2017 and is incorporated herein by reference.~~

~~MPLX LP Executive Change in Control Severance Benefits Plan~~

Effective October 26, 2017, the board of directors of Marathon Petroleum Corporation (the “Corporation”) and the board of directors of MPLX GP LLC, the general partner (the “General Partner”) of MPLX LP (“the Partnership”), adopted the MPLX LP Executive Change in Control Severance Benefits Plan (the “MPLX Plan”).

~~The purpose of the MPLX Plan is to recognize the contributions of the senior executives who provide services to the Corporation~~2023, no director or the Partnership and to assure the continued provision of services by these senior executives. The MPLX Plan is intended to operate as a companion plan to the Marathon Petroleum Corporation Amended and Restated Executive Change in Control Severance Benefits Plan (the “MPC Plan”). It is intended that the MPLX Plan shall not result in a duplication of benefits in the event a participant would be eligible to receive benefits under both the MPLX Plan and the MPC Plan. The following is a summary of the MPLX Plan:

~~The MPLX Plan applies to certain senior executives who provide services to the Partnership, the Corporation or any of their respective subsidiaries or affiliates.~~

~~A participant is generally entitled to receive benefits under the MPLX Plan if within two years following a Partnership Change in Control~~officer (as defined in Rule 16a-1(f) promulgated under the Exchange Act) of MPLX ~~Plan), the participant’s employment~~adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (as each term is ~~terminated without cause or for good reason, with good reason generally being~~ defined in the MPLX Plan as a reduction in the participant’s roles, responsibilities, pay or benefits or the participant is required to relocate more than 50 miles from his or her current location. However, benefits are not payable if the termination is for cause or due to mandatory retirement, death, disability or resignation (other than for good reason) by the participant.Item 408 of Regulation S-K).

In addition to any earned but unpaid salary, a lump sum cash amount equal to the value of the participant’s unused vacation days and any normal post-termination compensation and benefits under the retirement, insurance and other compensation and benefit plans in which the participant participates, upon a Partnership Change in Control and Qualified Termination (as defined in the MPLX Plan), participants are eligible to receive: (i) a cash payment equal to three times the sum of the participant’s base salary and the highest bonus paid in the three years before the Qualified Termination or, if higher, in the three years before the Partnership Change in Control; (ii) life and health insurance benefits for up to 36 months after termination at the active employee cost; (iii) benefits that are equivalent to the retiree medical and life benefit provided under the MPC Plan; and (iv) a cash payment that is equivalent to the supplemental retirement benefit and supplemental savings benefit provided under the MPC Plan.

Table of Contents

Participants who incur a Qualified Termination or who separate from service with all of the Partnership, the General Partner and any applicable buyer or successor entity within two years after the Partnership Change in Control under circumstances that would have resulted in a Qualified Termination had such separation occurred at the time of the Partnership Change in Control and participants who remain in service with the Corporation (and its affiliates) following the Partnership Change in Control may become eligible for the following benefits: (i) all Partnership equity awards that vest based solely upon the passage of time will be become vested and exercisable; and (ii) all Partnership equity awards that vest based on the attainment of performance goals will become vested as to the entire award with payment as follows (a) with respect to the period prior to the Partnership Change in Control (“Pre-CiC Period”), the award will be determined using actual performance during the Pre-CiC Period; and (b) with respect to the period after the Partnership Change in Control, the award will be determined assuming performance goals were satisfied at target levels. Participants who incur a Qualified Termination and participants who remain in or commence services with the Partnership, General Partner or any applicable buyer or successor entity (or any of their affiliates) following the Partnership Change in Control are eligible for the following benefits: (i) all Corporation equity awards will become vested and exercisable; (ii) the vesting of any Corporation equity awards that otherwise would vest based on the attainment of performance goals shall remain subject to the attainment of applicable performance goals at the end of the regularly scheduled performance period.

The Corporation and the General Partner may at any time amend or terminate the MPLX Plan, provided that, for a period of two years following a Partnership Change in Control, the MPLX Plan may not be amended in a manner adverse to a participant with respect to that Partnership Change in Control. Any amendment or termination shall be set out in an instrument in writing and executed by an appropriate officer.

The foregoing description of the MPLX Plan is summary in nature and subject to, and qualified in its entirety by, the full text of the MPLX Plan, a copy of which is attached as Exhibit 10.3 to this Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017 and is incorporated herein by reference.

Item 6. Exhibits

Incorporated by Reference From

Exhibit
Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed
Herewith

Furnished
Herewith

3.1

Certificate of Limited Partnership of MPLX LP

S-1

3.1

7/2/2012

333-182500

3.2

Amendment to the Certificate of Limited Partnership of MPLX LP

S-1/A

3.2

10/9/2012

333-182500

3.3

Sixth Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of February 1, 2021

8-K

3.1

2/3/2021

001-35714

10.1

MPLX GP LLC Amended and Restated Non-Management Director Compensation Policy and Director Equity Award Terms

31.1

Certification of Chief Executive Officer pursuant to Rule 13a-14 and 15d-14 under the Securities Exchange Act of 1934

31.2

Certification of Chief Financial Officer pursuant to Rule 13a-14 and 15d-14 under the Securities Exchange Act of 1934

32.1

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350

32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350

101.INS

XBRL Instance Document: The instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document.

101.SCH

Inline XBRL Taxonomy Extension Schema Document.

101.CAL

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

Incorporated by Reference
Exhibit
Number
Exhibit Description Form Exhibit Filing Date SEC File No.
Filed
Herewith

Furnished
Herewith
2.1

Membership Interests and Shares Contributions Agreement, dated September 1, 2017, between MPLX LP, MPLX Logistics Holdings LLC, MPLX Holdings Inc., MPLX GP LLC and MPC Investment LLC
8-K 2.1
9/1/2017 001-35714
3.1

Certificate of Limited Partnership of MPLX LP
S-1 3.1
7/2/2012 333-182500
3.2

Amendment to the Certificate of Limited Partnership of MPLX LP
S-1/A 3.2
10/9/2012 333-182500
3.3

Third Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of October 31, 2016
10-Q 3.3
10/31/2016 001-35714
3.4

First Amendment to Third Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of February 23, 2017
10-K 3.4
2/24/2017 001-35714
10.1

Credit Agreement, dated as of July 21, 2017, among MPLX LP, as borrower, Wells Fargo Bank, National Association, as administrative agent, each of Wells Fargo Securities, LLC, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Mizuho Bank, Ltd., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and RBC Capital Markets, as joint lead arrangers and joint bookrunners, JPMorgan Chase Bank, N.A., as syndication agent, each of Bank of America, N.A., Barclays Bank PLC, Citigroup Global Markets Inc., Mizuho Bank, Ltd., The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Royal Bank of Canada, as documentation agents, and the other lenders and issuing banks that are parties thereto.
8-K 10.1
7/27/2017 001-35714
10.2

Amended Restricted Stock Award Agreement
X
10.3

MPLX LP Executive Change in Control Severance Benefits Plan
X
31.1

Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
X
31.2

Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
X

Table of Contents

~~Incorporated by Reference~~

~~Exhibit~~

~~Number~~

~~Exhibit Description~~

~~Form~~

~~Exhibit~~

~~Filing Date~~

~~SEC File No.~~

~~Filed~~

~~Herewith~~

~~Furnished~~

~~Herewith~~

~~32.1~~

~~Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350~~

~~32.2~~

~~Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350~~

~~101.INS~~

~~XBRL Instance Document~~

~~101.SCH~~

~~XBRL Taxonomy Extension Schema~~

~~101.CAL~~

~~XBRL Taxonomy Extension Calculation Linkbase~~

~~101.DEF~~

~~XBRL Taxonomy Extension Definition Linkbase~~

~~101.LAB~~

~~XBRL Taxonomy Extension Label Linkbase~~

~~101.PRE~~

~~XBRL Taxonomy Extension Presentation Linkbase~~

SIGNATURES

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.


		MPLX LP

		~~MPLX LP~~By:

	~~By:~~	MPLX GP LLC
			Its general partner

Date: October ~~30, 2017~~31, 2023		By:	/s/ ~~Paula L. Rosson~~ Kelly D. Wright
			~~Paula L. Rosson~~Kelly D. Wright
			~~Senior~~ Vice President and ~~Chief Accounting Officer~~Controller of MPLX GP LLC ~~(the~~ (the general partner of MPLX LP)



	Page
PART I – FINANCIAL INFORMATION
Item 1.		Financial Statements:
		Consolidated Statements of Income (Unaudited)	3
		Consolidated Statements of Comprehensive Income (Unaudited)	4
		Consolidated Balance Sheets (Unaudited)	45
		Consolidated Statements of Cash Flows (Unaudited)	56
		Consolidated Statements of Equity and Series A Preferred Units (Unaudited)	67
		Notes to Consolidated Financial Statements (Unaudited)	78
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	4325
Item 3.		Quantitative and Qualitative Disclosures about Market Risk	6545
Item 4.		Controls and Procedures	6646

PART II – OTHER INFORMATION
Item 1.		Legal Proceedings	6747
Item 1A.		Risk Factors	6747

Item ~~2. Unregistered Sales of Equity Securities~~5.		Other Information	6848
Item ~~5. Other Information~~6.		Exhibits	6849
		~~Item 6. Exhibits~~Signatures	7050
~~Signatures~~	72



(In millions)	September 30, 2017			December 31, 2016
Assets
Current assets:
Cash and cash equivalents	$	3		$	234
Receivables, net	320			299
Receivables - related parties	152			247
Inventories	64			55
Other current assets	32			33
Total current assets	571			868
Equity method investments	3,997			2,471
Property, plant and equipment, net	11,922			11,408
Intangibles, net	463			492
Goodwill	2,245			2,245
Long-term receivables - related parties	18			11
Other noncurrent assets	22			14
Total assets	$	19,238		$	17,509
Liabilities
Current liabilities:
Accounts payable	$	152		$	140
Accrued liabilities	202			232
Payables - related parties	317			87
Deferred revenue	3			2
Deferred revenue - related parties	42			38
Accrued property, plant and equipment	183			146
Accrued taxes	44			38
Accrued interest payable	64			53
Other current liabilities	41			27
Total current liabilities	1,048			763
Long-term deferred revenue	34			12
Long-term deferred revenue - related parties	40			19
Long-term debt	6,848			4,422
Deferred income taxes	7			6
Deferred credits and other liabilities	175			177
Total liabilities	8,152			5,399
Commitments and contingencies (see Note 17)
Redeemable preferred units	1,000			1,000
Equity
Common unitholders - public (289 million and 271 million units issued and outstanding)	8,457			8,086
Class B unitholders (0 million and 4 million units issued and outstanding)	—			133
Common unitholder - MPC (95 million and 86 million units issued and outstanding)	1,302			1,069
Common unitholder - GP (23 million and 0 units issued and outstanding)	822			—
General partner - MPC (8 million and 7 million units issued and outstanding)	(626		)	1,013
Equity of Predecessor	—			791
Accumulated other comprehensive loss	(14		)	—
Total MPLX LP partners’ capital	9,941			11,092
Noncontrolling interests	145			18
Total equity	10,086			11,110
Total liabilities, preferred units and equity	$	19,238		$	17,509



	Three Months Ended September 30, 2016
(In millions, except per unit data)	MPLX LP (Previously Reported)		HST/WHC		MPLXT		Eliminations⁽¹⁾			MPLX LP (Currently Reported)
Revenues and other income:
Service revenue	$	250	$	—	$	—	$	—		$	250
Service revenue - related parties	153		28		72		—			253
Rental income	77		—		—		—			77
Rental income - related parties	29		13		26		—			68
Product sales	157		—		—		—			157
Product sales - related parties	2		—		—		—			2
Income from equity method investments	6		—		—		—			6
Gain on sale of assets	1		—		—		—			1
Other income	2		—		—		—			2
Other income - related parties	26		—		—		(4		)	22
Total revenues and other income	703		41		98		(4		)	838
Costs and expenses:
Cost of revenues (excludes items below)	90		10		22		—			122
Purchased product costs	117		—		—		—			117
Rental cost of sales	11		2		—		—			13
Rental cost of sales - related parties	—		1		—		(1		)	—
Purchases - related parties	84		4		24		(3		)	109
Depreciation and amortization	138		4		9		—			151
General and administrative expenses	46		2		8		—			56
Other taxes	10		—		2		—			12
Total costs and expenses	496		23		65		(4		)	580
Income from operations	207		18		33		—			258
Interest expense (net of amounts capitalized)	51		—		—		—			51
Other financial costs	13		—		—		—			13
Income before income taxes	143		18		33		—			194
Net income	143		18		33		—			194
Less: Net income attributable to noncontrolling interests	2		—		—		—			2
Less: Net income attributable to Predecessor	—		18		33		—			51
Net income attributable to MPLX LP	141		—		—		—			141
Less: Preferred unit distributions	16		—		—		—			16
Less: General partner’s interest in net income attributable to MPLX LP	51		—		—		—			51
Limited partners’ interest in net income attributable to MPLX LP	$	74	$	—	$	—	$	—		$	74


~~(1)~~	~~Represents intercompany transactions eliminated during the consolidation process, in accordance with GAAP.~~



	Nine Months Ended September 30, 2016
(In millions, except per unit data)	MPLX LP (Previously Reported)			HST/WHC		MPLXT		Eliminations⁽¹⁾			MPLX LP (Currently Reported)
Revenues and other income:
Service revenue	$	712		$	—	$	—	$	—		$	712
Service revenue - related parties	448			82		146		—			676
Rental income	218			—		—		—			218
Rental income - related parties	84			36		52		—			172
Product sales	394			—		—		—			394
Product sales - related parties	8			—		—		—			8
Loss from equity method investments	(72		)	—		—		—			(72		)
Gain on sale of assets	1			—		—		—			1
Other income	5			—		—		—			5
Other income - related parties	78			—		—		(11		)	67
Total revenues and other income	1,876			118		198		(11		)	2,181
Costs and expenses:
Cost of revenues (excludes items below)	263			24		42		—			329
Purchased product costs	310			—		—		—			310
Rental cost of sales	39			3		—		—			42
Rental cost of sales - related parties	—			2		—		(1		)	1
Purchases - related parties	238			13		45		(10		)	286
Depreciation and amortization	407			12		19		—			438
Impairment expense	130			—		—		—			130
General and administrative expenses	147			5		20		—			172
Other taxes	32			2		3		—			37
Total costs and expenses	1,566			61		129		(11		)	1,745
Income from operations	310			57		69		—			436
Related party interest and other financial income	1			—		—		—			1
Interest expense (net of amounts capitalized)	158			—		—		—			158
Other financial costs	37			—		—		—			37
Income before income taxes	114			57		69		—			240
Benefit for income taxes	(12		)	—		—		—			(12		)
Net income	126			57		69		—			252
Less: Net income attributable to noncontrolling interests	3			—		—		—			3
Less: Net income attributable to Predecessor	23			57		69		—			149
Net income attributable to MPLX LP	100			—		—		—			100
Less: Preferred unit distributions	25			—		—		—			25
Less: General partner’s interest in net income attributable to MPLX LP	136			—		—		—			136
Limited partners’ interest in net loss attributable to MPLX LP	$	(61	)	$	—	$	—	$	—		$	(61	)



(In millions)	Three Months Ended September 30, 2017		Seven Months Ended September 30, 2017
Revenues and other income	$	19	$	45
Income from operations	6		17



	Nine Months Ended September 30, 2017
(In millions)	MarkWest Utica EMG		Other VIEs		Non-VIEs		Total
Revenues and other income	$	137	$	49	$	178	$	364
Costs and expenses	72		29		115		216
Income from operations	65		20		63		148
Net income	65		19		28		112
Income from equity method investments⁽¹⁾	6		7		16		29


~~(2)~~	Includes an impairment charge of $89 million for the nine months ended September 30, 2016 related to the Partnership’s investment in Ohio Condensate Company, L.L.C., which does not appear separately in this table.



	September 30, 2017
(In millions)	MarkWest Utica EMG⁽¹⁾		Other VIEs		Non-VIEs		Total
Current assets	$	72	$	47	$	379	$	498
Noncurrent assets	2,092		878		4,614		7,584
Current liabilities	37		55		492		584
Noncurrent liabilities	2		12		562		576


~~(1)~~	MarkWest Utica EMG, L.L.C.’s (“MarkWest Utica EMG”) noncurrent assets include its investment in its subsidiary Ohio Gathering Company, L.L.C. (“Ohio Gathering”), which does not appear elsewhere in this table. The investment was $794 million as of September 30, 2017 and December 31, 2016.


~~(1)~~	~~Balance includes approximately $202 million related to the loan with MPC Investment as discussed above.~~



	Three Months Ended September 30, 2017
(In millions, except per unit data)	General Partner			Limited Partners’ Common Units			Redeemable Preferred Units		Total
Basic and diluted net income attributable to MPLX LP per unit:
Net income attributable to MPLX LP:
Distributions declared (including IDRs)	$	88		$	232		$	16	$	336
Undistributed net loss attributable to MPLX LP	(2		)	(118		)	—		(120		)
Net income attributable to MPLX LP⁽¹⁾	$	86		$	114		$	16	$	216
Weighted average units outstanding:
Basic	8			394			31		433
Diluted	8			395			31		434
Net income attributable to MPLX LP per limited partner unit:
Basic				$	0.29
Diluted				$	0.29


~~(1)~~	~~Allocation of net income (loss) attributable to MPLX LP assumes all earnings for the period had been distributed based on the current period distribution priorities.~~



(In units)	Common	Class B		General Partner	Total
Balance at December 31, 2016	357,193,288	3,990,878		7,371,105	368,555,271
Unit-based compensation awards⁽¹⁾	183,509	—		3,745	187,254
Issuance of units under the ATM Program⁽²⁾	13,846,998	—		282,591	14,129,589
Contribution of HST/WHC/MPLXT⁽³⁾	12,960,376	—		264,497	13,224,873
Contribution of the Joint-Interest Acquisition⁽³⁾	18,511,134	—		377,778	18,888,912
Class B conversion⁽⁴⁾	4,350,057	(3,990,878	)	7,330	366,509
Balance at September 30, 2017	407,045,362	—		8,307,046	415,352,408



	Number of Units		Weighted Average Fair Value
Outstanding at December 31, 2016	1,173,411		$	33.09
Granted	653,721		36.36
Settled	(288,584	)	33.50
Forfeited	(113,107	)	34.59
Outstanding at September 30, 2017	1,425,441		34.39



(In millions)
December 31, 2017	$	8
March 31, 2018	11
June 30, 2018	11
September 30, 2018	10
December 31, 2018	4
March 31, 2019	3
June 30, 2019	4
September 30, 2019	4
Total	$	55



	Fee-Based		Percent-of-Proceeds⁽¹⁾		Keep-Whole⁽²⁾
L&S	100	%	—	%	—	%
G&P⁽³⁾	86	%	12	%	2	%
Total	92	%	7	%	1	%



WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2017 (Oct - Dec)	200	$	54.25	$	42



Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2017 (Oct - Dec)	1,832	$	3.03	$	(30	)
2018	2,542	$	2.78	$	4



Ethane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Oct - Dec)	54,600	$	0.27	$	(47	)



Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Oct - Dec)	119,932	$	0.61	$	(3,164	)
2018	16,925	$	0.64	$	(506	)



IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Oct - Dec)	10,730	$	0.81	$	(236	)
2018	1,655	$	0.80	$	(38	)



Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Oct - Dec)	31,622	$	0.75	$	(823	)
2018	4,595	$	0.75	$	(120	)



Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Oct - Dec)	41,827	$	1.13	$	(346	)
2018	3,089	$	1.18	$	(20	)