2019
ANNUAL REPORT
2017
ANNUAL REPORT
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Cover: Todochi Wells,
terminal manager at MPLX’s
Champaign, Illinois facility
MPLX operations as of Dec. 31, 2019
Table of Contents
Chairman Letter
Financial Highlights
Safety and Environmental Stewardship
Board of Directors
Company Offi cers
Key Financial and Operational Results
Reconciliation Data
1
6
8
10
11
12
13
MPLX Owned and Part-Owned
Light Product Terminals
MPLX Owned Asphalt/Heavy Oil
Terminals
MPC Refi neries
Caverns
MPC/MPLX Pipelines (a)
MPLX Refi ning Logistics Assets
MPLX Gathering System
MPLX Owned Marine Facility
Natural Gas Processing Complex (b)
Note: Illustrative representation of asset map.
(a) Includes MPC/MPLX owned and operated lines,
MPC/MPLX interest lines operated by others and
MPC/MPLX operated lines owned by others.
(b) Includes MPLX owned and operated natural
gas processing complexes
Glossary of Terms
bbl: barrels
bcf/d: billion cubic feet per day
bpd: barrels per day
cf/d: cubic feet per day
EBITDA: earnings before interest, taxes, depreciation
and amortization
GP: general partner
IPO: initial public offering of units
LP: limited partner
MarkWest: MarkWest Energy Partners, L.P., a wholly
owned subsidiary of MPLX LP acquired in December 2015
mbpd: thousand barrels per day
MLP: master limited partnership
mmcf/d: million cubic feet per day
MPC: Marathon Petroleum Corporation
MPL: Marathon Pipe Line LLC
NGL: Natural gas liquids
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MPLX I 2019 ANNUAL REPORT I 1
FROM THE CHAIRMAN
Fellow unitholders,
It’s a pleasure for me to report that MPLX fi nished 2019 with strong operational and fi nancial
results. Our adjusted EBITDA for the year was $5.1 billion, including results of Andeavor Logistics,
which we acquired in July. We generated $4.1 billion of cash from operations and returned
approximately 75%, or nearly $3 billion, to unitholders. Our 2019 pipeline and terminal through-
puts were up over the prior year,
and gathering and processing
volumes increased signifi cantly,
by 10% and 12%, respectively.
Our strategic priorities
We maintained our strategic focus
on capturing the full midstream
value chain as we connect supply
– especially from prime production
regions – to global demand markets.
We worked to enhance cash
fl ow stability through our
investment in long-haul pipelines
and export capabilities, and
continued to pursue value-
creating opportunities with our
sponsor, Marathon Petroleum
Corporation (MPC), which enabled
us to enhance projects through
volume commitments while
providing logistics solutions to
MPC’s nationwide refi ning system.
We maintained our commitment
to fi nancial discipline by issuing
no new equity for growth projects
and targeted mid-teen returns
on our growth investments.
$4,100
$3,035
2018
2019
Distributable cash flow attributable to MPLX (in millions).
Includes results of predecessor.
See reconciliations on Pages 13-15.
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MPLX I 2019 ANNUAL REPORT I 2
FROM THE CHAIRMAN
Achieving our strategic vision in 2019
During 2019, we made excellent progress creating an integrated crude oil and natural gas logistics
system from the Permian to the U.S. Gulf Coast. To serve crude oil producers and markets, in 2019
we established an equity ownership interest in the Wink to Webster pipeline joint venture, which
subsequently joined with another crude oil transportation project. We own an approximate
11% interest in the project. Wink to Webster is fully committed with minimum volume commitments,
and is expected to transport up to 1.5 million bpd of crude oil from the Permian Basin to the Houston
area, including MPC’s Galveston Bay refi nery, by early 2021.
Below left: MPLX
Gathering and Processing’s
Hidalgo complex in
Culberson County, Texas
The Whistler natural gas pipeline is approximately 95% committed with minimum volume commitments,
Below right:
and is expected to transport approximately 2 bcf/d of gas from Waha, Texas, to the Agua Dulce market
Maintenance Mechanic
Chad Hixon at MPLX’s
Royal Oak Compressor
Station in Butler County,
in South Texas by the second half of 2021. Ultimately, we anticipate this project will help provide natural
gas to MPC’s Galveston Bay refi nery. We also continued to study our proposed Belvieu Alternative
Pennsylvania
Natural Gas Liquids (BANGL) pipeline.
creating an
integrated
system
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MPLX I 2019 ANNUAL REPORT I 3
In the fourth quarter we made important progress on the reversal of Capline Pipeline, purging the
mainline to prepare for the next phases of work. We anticipate the reversed Capline will begin
transporting discounted mid-continent and Canadian crude oil from Patoka, Illinois, to St. James,
Louisiana, with light crude service beginning mid-2021. MPC has a 33% ownership interest in Capline,
while MPLX operates the line. Integration with MPC operations is a key benefi t of the Capline
reversal, since MPC’s Garyville, Louisiana, refi nery is directly connected to storage in St. James.
Below left: Maintenance
Mechanic John Koci at
In our Marcellus and Utica natural gas gathering and processing operations, our just-in-time
growth strategy continues to serve us and our producer-customers well. We added two
MPLX’s Royal Oak
processing plants to our Sherwood complex in West Virginia in 2019, bringing its capacity to
Compressor Station in
Butler County,
Pennsylvania
Below right: Lab Tech-
nician Laura Trevino at
MPLX’s Javelina
processing complex in
2.6 bcf/d, the largest plant of its kind in the world. This expansion contributed to a 14% increase
in processed volumes in our Marcellus and Utica operations.
In the Southwest, we added a 200 million cf/d plant, Tornado, in the fourth quarter and continued
construction of our Preakness plant with service expected to begin in the second quarter of 2020.
Corpus Christi, Texas
These facilities will complement our Argo and Hidalgo plants currently in place in the Delaware Basin.
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MPLX I 2019 ANNUAL REPORT I 4
FROM THE CHAIRMAN
Altogether, these facilities are expected to contribute volumes for the planned Whistler pipeline. We
expect to begin operating our Preakness processing plant in the Permian during the second quarter
of 2020, and the Smithburg 1 processing plant in the Marcellus in the third quarter.
In July 2019, MPLX acquired Andeavor Logistics, creating a leading, large-scale, diversifi ed midstream
company anchored by fee-based cash fl ows.
Looking toward the future
As we look forward, we are targeting positive free cash fl ow, after capital investments and distributions,
Below left: Board
in 2021. We expect this to allow funding of our distribution and growth capital programs entirely from
Operator Curtis McDonald
internally generated cash fl ow. Our objective in shifting to a model focused on generating cash fl ow
at MPLX’s Sherwood
gas processing and
beyond the needs of the business is to enable MPLX to focus its capital allocation toward debt
fractionation complex in
reduction or unit repurchases.
Doddridge County,
West Virginia
Below right:
MPLX’s Bluestone gas
processing complex in
Butler County,
Pennsylvania
We also continued to high-grade our capital plan. In 2018, we spent approximately 85% of our growth
capital on the Gathering and Processing (G&P) segment, and in 2019, we allocated our approximately
$2.2 billion of capital spending equally between our G&P and Logistics and Storage (L&S) segments.
As we shift our growth capital investments in the business to the L&S segment, our target in 2020 is to spend
up to 75% of our $1.5 billion investment plan on L&S, focusing on areas of growth, such as the Permian.
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MPLX I 2019 ANNUAL REPORT I 5
This year, we have shared more information on MPLX’s safety and environmental stewardship
performance on Pages 8 and 9 of this report. MPLX’s performance is also captured as part of
two publications released by MPC. I encourage you to read MPC’s current Sustainability Report
and Perspectives on Climate-Related Scenarios, both of which are available on its website,
www.MarathonPetroleum.com, to learn more about MPLX’s performance and contribution in
these important areas.
Fellow unitholders, we are excited about the future of MPLX. Our position in the nation’s best
production regions, our projects to connect these regions to demand centers, and our fi nancial
discipline provide a strong foundation for continued growth and future positive free cash fl ow.
We appreciate your investment in our partnership, and look forward to continuing to share our
success with you.
Sincerely,
Gary R. Heminger
Chairman
Below: Operations Technician
Scott Wright at MPLX’s
light-products terminal in
Jacksonville, Florida
targeting positive free cash
fl ow generation by 2021
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MPLX I 2019 ANNUAL REPORT I 6
FINANCIAL HIGHLIGHTS
FINANCIAL HIGHLIGHTS
In millions, except per unit and ratio data
Net income attributable to MPLX
Adjusted EBITDA attributable to MPLX (including predecessor results)(a)
Net cash provided by operating activities
Distributable cash fl ow (DCF)(b)
Distribution per common unit (c)
Distribution coverage ratio (d)
2017
$794
2,004
1,907
1,628
2.30
1.28x
2018
2019
$1,818
$1,033
(e)
3,810
3,071
3,035
2.53
1.49x
5,104
4,082
4,100
2.69
1.51x
(a) Non-GAAP measure. See reconciliations on Pages 13-15. Includes predecessor adjusted EBITDA adjustments attributable to Andeavor Logistics.
(b) Non-GAAP measure calculated before distributions to preferred unitholders. See reconciliations on Pages 13-15. Includes predecessor adjusted EBITDA and DCF
adjustments attributable to Andeavor Logistics.
(c) Distributions declared by the board of directors of MPLX’s general partner.
(d) DCF attributable to GP and LP unitholders (including DCF attributable to predecessor) divided by total GP and LP distribution declared. For the year ended December
31, 2018, DCF attributable to predecessor for the fourth quarter has been included with no corresponding distribution being declared by MPLX relating to the predecessor,
resulting in a distribution coverage ratio of 1.49x. For the year ended December 31, 2019, DCF attributable to predecessor has been included with no corresponding
distribution being declared by MPLX relating to the predecessor for the fi rst quarter of 2019, resulting in a distribution coverage ratio of 1.51x.
(e) 2019 results include non-cash impairment charges of $1.2 billion, primarily related to goodwill associated with the Andeavor Logistics gathering and processing
businesses acquired by Marathon Petroleum Corporation as part of its combination with Andeavor in October 2018.
ADJUSTED EBITDA ATTRIBUTABLE TO MPLX
In millions
5,104*
3,810*
* Includes predecessor results of
Andeavor Logistics
See reconciliations on Pages 13-15
2,004
2017
2018
2019
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TARGETING POSITIVE FREE CASH FLOW
Disciplined Approach and Long-term Focus
2019
The Path to Increased Cash Flow
2021(a)
EBITDA ~$5.1 B (b)
EBITDA – Continued Growth
DCF ~$4.1 B (b)
DCF – Continued Growth
Distributions
~$3.0 B (c)
Growth Capital
~$2.6 B (d)
Distributions
Growth Capital
~$1.0 B
Debt Required
for a Portion of Growth Capital
Positive Free Cash Flow
Incremental Opportunities
• Leverage Reduction
• Unit Repurchases
(a) Illustrative/targeted; assumes 2019 status quo asset portfolio and business/capital plan
(b) Adjusted EBITDA and distributable cash fl ow include predecessor results. See reconciliations on Pages 13-15.
(c) Preferred unit distributions and common unit distributions declared by the board of directors of MPLX’s general partner,
as well as Andeavor Logistics’ general partner for the fi rst quarter of 2019.
(d) Adjusted growth capital expenditures. See Pages 13-15 for reconciliations.
DISTRIBUTION AND COVERAGE RATIO
2.53
2.69
2.30
1.28x
1.49x
1.51x
MPLX I 2019 ANNUAL REPORT I 7
$5.1
Billion
Adjusted
EBITDA in 2019(g)
$4.1
Billion
Distributable
Cash Flow in 2019(g)
$3
Billion
of Distributions to
Unitholders in 2019(c)
~75%
Distributable
Cash Flow Returned
to Unitholders
in 2019
2017
2018
2019
Distribution coverage ratio (e) Distributions per common unit ($ per unit) (f)
(e) DCF attributable to GP and LP unitholders (including DCF attributable to predecessor) divided by total GP and LP distribution declared. For the year ended December
31, 2018, DCF attributable to predecessor for the fourth quarter has been included with no corresponding distribution being declared by MPLX relating to the predecessor,
resulting in a distribution coverage ratio of 1.49x. For the year ended December 31, 2019, DCF attributable to predecessor has been included with no corresponding
distribution being declared by MPLX relating to the predecessor for the fi rst quarter of 2019, resulting in a distribution coverage ratio of 1.51x.
(f) Distributions declared by the board of directors of MPLX’s general partner.
(g) Non-GAAP measure calculated before distributions to preferred unitholders. See reconciliations on Pages 13-15. Includes adjusted EBITDA and DCF adjustments attributable
to predecessor.
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MPLX I 2019 ANNUAL REPORT I 8
SAFETY AND ENVIRONMENTAL STEWARDSHIP
A corporate culture of safety and sustainability
Protecting our people and the world we all share has been and remains a priority for us.
We aim for an accident-free, incident-free workplace to ensure everyone goes home safely
every day. We are committed to safe and environmentally responsible operations to protect
the health and safety of our employees, contractors, and communities.
Our personal safety standards comply with and often exceed local, state and federal
regulatory requirements. Our employees and contractors are trained on our standards,
and we conduct frequent audits and quality assurance visits to ensure compliance.
Our safety culture is one that empowers everyone to create and maintain a safe and
healthy workplace.
MPLX OSHA RECORDABLE INCIDENT RATE
The Occupational Safety and Health Administration (OSHA) Recordable Incident
Rate measures the number of injuries per 200,000 hours of work.
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
2017
2018
2019
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MPLX I 2019 ANNUAL REPORT I 9
MPLX PROCESS SAFETY EVENT (PSE) RATE
PSEs are unplanned or uncontrolled releases of a material from a process. The PSE rate is the count
of events per 200,000 hours of work. Tier 1 PSEs are the most serious type. MPLX works to continually
reduce its process safety event (PSE) rates, and has programs and processes in place to monitor and
continually improve performance.
0.16
0.14
0.12
0.10
0.08
0.06
0.04
0.02
0
Tier 1
Tier 2
2017
2018
2019
DESIGNATED ENVIRONMENTAL INCIDENTS (DEIs)
DEIs include three categories of environmental incidents: releases to the environment (air, land or
water), environmental permit exceedances and agency enforcement actions. Spills that are less than
one barrel but reported to an agency due to local regulation are also included; spill data from entities
purchased by MPC are included as reported by the acquired company.
30
25
20
15
10
5
0
2017
2018
2019
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MPLX I 2019 ANNUAL REPORT I 10
BOARD OF DIRECTORS
Seated, left to right
Michael J. Hennigan
President and CEO, MPLX GP
LLC. Prior to joining MPLX GP
LLC in 2017, Mr. Hennigan was
president, crude, NGL and
refi ned products of the general
partner of Energy Transfer
Partners L.P. Prior to that, he
served as president and chief
executive offi cer of Sunoco
Logistics Partners L.P. He was
responsible for all operations
and business activities,
including setting the direction,
strategy and vision for the
company.
Dan D. Sandman
Adjunct professor, The Ohio
State University Moritz College
of Law. Mr. Sandman began his
career at Marathon Oil Co. in
1973 and served in various
positions as an attorney before
being appointed general
counsel and secretary in 1986.
In 1993, he was named general
counsel and secretary of USX
Corp. and in 2002, he was
named vice chairman of the
board and chief legal and
administrative offi cer of
United States Steel Corp.,
retiring in 2007.
Standing, left to right Continued
Gary R. Heminger
Chairman, MPLX GP LLC,
and Chairman and CEO, MPC.
Mr. Heminger joined Marathon
Oil Co. in 1975 and held various
leadership positions including
head of Marathon’s down-
stream operations beginning
in 2001. Mr. Heminger was
named president and CEO of
Marathon Petroleum Corp. in
2011 and chairman in 2016.
He was also CEO of MPLX GP
LLC from 2012 until October
2019.
Pamela K.M. Beall
Executive Vice President
and Chief Financial Offi cer,
MPLX GP LLC. Ms. Beall
began her career with
Marathon Oil Co. and
transferred to USX
Corporation. After rejoining
Marathon in 2002, she held
various leadership positions,
most recently executive vice
president, Corporate Planning
and Strategy, MPLX GP LLC.
Standing, left to right
Donald C. Templin
Executive Vice President and Chief
Financial Offi cer, MPC. Mr. Templin was
appointed senior vice president and
chief fi nancial offi cer of MPC in 2011
and vice president and chief fi nancial
offi cer of MPLX GP LLC in 2012. He
was named executive vice president
of MPC and president of MPLX in
2016. He was named president of
MPC in 2017, president of Refi ning,
Marketing and Supply in 2018, and
assumed his current role in 2019.
Prior to joining MPC in 2011, Mr.
Templin was managing partner of
PricewaterhouseCoopers LLP’s audit
practice in Georgia, Alabama and
Tennessee.
John P. Surma
Retired Chairman and
CEO, United States Steel
Corp. Prior to USS, Mr. Surma
held various leadership
positions at Marathon Oil
Co., including senior vice
president of Finance and
Accounting, president of
Speedway SuperAmerica
LLC, and president of
Marathon Ashland
Petroleum LLC.
Christopher A. Helms
President and CEO, U.S. Shale
Management Co. Mr. Helms
previously served in various
leadership positions at
NiSource Inc. and NiSource
Gas Transmission and
Storage. Mr. Helms was
responsible for leading the
company’s interstate gas
transmission, storage and
midstream businesses.
Garry L. Peiffer
Retired President, MPLX GP
LLC, and retired Executive
Vice President, Corporate
Planning and Investor and
Government Relations, MPC.
Mr. Peiffer joined Marathon
Oil Co. in 1974 and held vari-
ous leadership positions with
the company. He was named
executive vice president of
MPC in 2011, and president
of MPLX in 2012.
Frank M. Semple
Retired Chairman,
President and CEO,
MarkWest Energy
Partners, L.P. Mr. Semple
joined MarkWest in 2003 as
president and CEO, and was
elected chairman in 2008. He
completed a 22-year career
with The Williams Cos. and
WilTel Communications
prior to MarkWest.
J. Michael Stice
Dean, Mewbourne College
of Earth & Energy, The
University of Oklahoma.
He is a former director of
MarkWest Energy Partners,
L.P. Mr. Stice’s career includes
leadership roles with Conoco
and ConocoPhillips. He also
was chief executive offi cer
and a director of Chesapeake
Midstream Partners, L.P., later
called Access Midstream.
Michael L. Beatty
Former Chairman, Beatty
& Wozniak, P.C. Mr. Beatty
was a director of MarkWest
Hydrocarbon and was named
a director of MarkWest
Energy Partners, L.P. in 2008.
Prior to these positions, he
was executive vice president,
general counsel and director
of the Coastal Corp., and
chief of staff to Colorado Gov.
Roy Romer.
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COMPANY OFFICERS
MPLX I 2019 ANNUAL REPORT I 11
Standing, left to right
Seated, left to right
Suzanne Gagle
General Counsel
John S. Swearingen
Executive Vice President
Logistics and Storage
Michael J. Hennigan
President and CEO
Gary R. Heminger
Chairman
Pamela K.M. Beall
Executive Vice President and Chief Financial Offi cer
Gregory S. Floerke
Executive Vice President
Gathering and Processing
Raymond L. Brooks
Senior Vice President
Shawn M. Lyon
Vice President
Operations
Timothy J. Aydt
Vice President
Business Development
Molly R. Benson
Vice President, Chief Securities,
Governance and Compliance Offi cer
and Corporate Secretary
C. Kristopher Hagedorn
Vice President and Controller
Rick D. Hessling
Senior Vice President
Brian K. Partee
Senior Vice President
David L. Whikehart
Senior Vice President
Peter Gilgen
Vice President and Treasurer
Kristina A. Kazarian
Vice President
Investor Relations
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MPLX I 2019 ANNUAL REPORT I 12
KEY FINANCIAL AND OPERATIONAL RESULTS
(In millions, except per-unit, throughput and average tariff data)
2017
2018
2019
Revenues and other income
Net income attributable to MPLX LP
Limited partners’ interest in net income attributable to MPLX LP
Adjusted EBITDA attributable to MPLX LP (including predecessor results) (a)
Distributable cash fl ow (DCF) (including predecessor results) (b)
Net income attributable to MPLX LP per limited partner unit:
$ 3,867
$ 7,005
$ 9,041
794
411
2,051
1,673
1,818
1,743
3,810
3,035
1,033
935
5,104
4,100
Common units – basic
Common units – diluted
1.07
1.06
2.29
2.29
1.00
1.00
Weighted average limited partner units outstanding:
Common units – basic
Common units – diluted
Cash and cash equivalents
Total assets
Total long-term debt (c)
Redeemable preferred units
Total equity
Capital expenditures:
Maintenance
Growth
Pipeline throughput (mbpd):
Crude oil pipelines
Product pipelines
Total pipelines
Average tariff rates ($ per bbl):
Crude oil pipelines
Product pipelines
Total pipelines
Gathering, processing and fractionation throughputs:(d)
Total gathering throughputs (mmcf/d)
Natural gas processed (mmcf/d)
C2+ NGLs fractionated (mbpd)
761
761
906
907
$ 77
$ 15
385
388
$ 5
19,500
7,332
1,000
9,973
103
1,381
39,325
18,435
1,004
17,731
175
2,078
1,936
3,121
1,085
3,021
0.56
0.74
0.63
3,608
6,460
394
1,823
4,944
0.67
0.75
0.70
5,519
7,739
478
40,430
20,307
968
16,613
262
2,001
3,228
1,886
5,114
0.94
0.75
0.87
6,094
8,661
534
(a) Non-GAAP measure. See reconciliations on Pages 13-15. Includes adjusted EBITDA adjustments attributable to predecessor.
(b) Non-GAAP measure calculated before distributions to preferred unitholders. See reconciliations on Pages 13-15. Includes adjusted EBITDA and DCF adjustments
attributable to predecessor.
(c) Outstanding intercompany borrowings were $594 million, zero, and $386 million as of Dec. 31, 2019, 2018 and 2017, respectively. Includes current portion of long-term debt.
(d) Includes operating data for entities that have been consolidatewinancial statements as well as operating data for partnership-operated equity method
investments. Also inclusive of predecessor operations beginning October 1, 2018.
74377.indd 14
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RECONCILIATION DATA
MPLX I 2019 ANNUAL REPORT I 13
Reconciliation of adjusted EBITDA attributable to MPLX LP, and DCF attributable to GP and LP unitholders
from net income (loss) (unaudited)
(In millions)
Net income
(Benefi t) provision for income taxes
Amortization of deferred fi nancing costs
Loss on extinguishment of debt
Net interest and other fi nancial costs
Income from operations
Depreciation and amortization
Non-cash equity-based compensation
Impairment expense
Income from equity method investments
Distributions/adjustments related to equity method investments
Unrealized derivative losses (gains)(a)
Acquisition costs
Other
Adjusted EBITDA
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to predecessor(b)
Adjusted EBITDA attributable to MPLX LP
Deferred revenue impacts
Net interest and other fi nancial costs
Maintenance capital expenditures
Maintenance capital expenditures reimbursements
Equity method investment capital expenditures paid out
Other
Portion of DCF adjustments attributable to predecessor(b)
DCF attributable to MPLX LP
Preferred unit distributions(c)
DCF attributable to GP and LP unitholders (excluding predecessor results)
Adjusted EBITDA attributable to predecessor(b)
Portion of DCF adjustments attributable to predecessor(b)
Year Ended Dec. 31
2017
2018
2019
$ 836
$ 2,006
$ 1,462
1
53
––
301
1,191
683
15
––
(78)
231
6
11
––
2,059
(8)
(47)
2,004
33
(301)
(103)
––
(13)
6
2
1,628
(65)
1,563
47
(2)
8
55
46
613
––
42
––
873
2,728
2,377
867
23
—
(247)
458
(5)
4
—
3,828
(18)
(335)
3,475
28
(613)
(175)
8
(31)
8
81
2,781
(85)
2,696
335
(81)
1,254
22
1,197
(290)
562
(1)
14
1
5,136
(32)
(770)
4,334
94
(873)
(262)
53
(28)
12
159
3,489
(122)
3,367
770
(159)
DCF attributable to GP and LP unitholders (including predecessor results)
1,608
2,950
3,978
(a) MPLX makes a distinction between realized and 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.
(b) The adjusted EBITDA and DCF adjustments related to predecessor are excluded from adjusted EBITDA attributable to MPLX LP and DCF
attributable to GP and LP unitholders prior to the acquisition date.
(c) Includes MPLX distributions declared on the Series A and Series B preferred units as well as cash distributions earned by the Series B
preferred (as the Series B preferred units are declared and payable semi-annually) assuming a distribution is declared by the Board of Directors.
Cash distributions declared/to be paid to holders of the Series A and Series B preferred units are not available to common unitholders.
74377.indd 15
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Reconciliations continued on next page.
MPLX I 2019 ANNUAL REPORT I 14
RECONCILIATION DATA
Reconciliation of adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP
unitholders from net cash provided by operating activities (unaudited)
Year Ended Dec. 31
(In millions)
Net cash provided by operating activities
Changes in working capital items
All other, net
Non-cash equity-based compensation
Net gain (loss) on disposal of assets
Current income taxes
Loss on extinguishment of debt
Net interest and other fi nancial costs
Asset retirement expenditures
Unrealized derivative (gains) losses(a)
Acquisition costs
Other adjustments related to equity method investments
Other
Adjusted EBITDA
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to predecessor(b)
Adjusted EBITDA attributable to MPLX LP
Deferred revenue impacts
Net interest and other fi nancial costs
Maintenance capital expenditures
Maintenance capital expenditures reimbursements
Equity method investment capital expenditures paid out
Other
Portion of DCF adjustments attributable to predecessor(b)
DCF attributable to MPLX LP
Preferred unit distributions(c)
DCF attributable to GP and LP unitholders (excluding predecessor results)
Adjusted EBITDA attributable to predecessor(b)
Portion of DCF adjustments attributable to predecessor(b)
2017
$ 1,907
(147)
(28)
15
––
2
––
301
2
6
11
(10)
––
2,059
(8)
(47)
2,004
33
(301)
(103)
––
(13)
6
2
1,628
(65)
1,563
47
(2)
2018
$ 3,071
31
(5)
23
(3)
––
46
613
7
(5)
4
46
––
3,828
(18)
(335)
3,475
28
(613)
(175)
8
(31)
8
81
2,781
(85)
2,696
335
(81)
2019
$ 4,082
108
(9)
22
6
2
––
873
1
(1)
14
37
1
5,136
(32)
(770)
4,334
94
(873)
(262)
53
(28)
12
159
3,489
(122)
3,367
770
(159)
DCF attributable to GP and LP unitholders (including predecessor results)
1,608
2,950
3,978
(a) MPLX makes a distinction between realized and 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.
(b) The adjusted EBITDA and DCF adjustments related to predecessor are excluded from adjusted EBITDA attributable to MPLX
LP and DCF attributable to GP and LP unitholders prior to the acquisition date.
(c) Includes MPLX distributions declared on the Series A and Series B preferred units as well as cash distributions earned
by the Series B preferred (as the Series B preferred units are declared and payable semi-annually) assuming a distribution is
declared by the Board of Directors. Cash distributions declared/to be paid to holders of the Series A and Series B preferred
units are not available to common unitholders.
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MPLX I 2019 ANNUAL REPORT I 15
RECONCILIATION DATA
Reconciliation to MPLX growth capital expenditures
Year Ended Dec. 31
(In millions)
Capital expenditures (a)
Maintenance
Maintenance Reimbursements
Growth
Growth reimbursements
Total capital expenditures
Less: Increase (decrease) in capital accruals
Asset retirement expenditures
Additions to property, plant and equipment, net (b)
Investments in unconsolidated affi liates
Acquisitions
Total capital expenditures and acquisitions
Less: Maintenance capital expenditures (including reimbursements)
Acquisitions
Total growth capital expenditures (c)
2017
2018
2019
$ 103
$ 175
$ 262
––
1,381
––
1,484
71
2
1,411
761
249
2,421
103
249
2,069
(8)
2,078
(16)
2,229
135
7
2,087
341
451
2,879
167
451
2,261
(53)
2,001
(21)
2,189
(146)
1
2,334
713
(6)
3,041
209
(6)
2,838
(a) Includes capital expenditures of the predecessor for all periods presented.
(b) This amount is represented in the Consolidated Statements of Cash Flows as additions to property, plant and equipment after excluding
growth and maintenance reimbursements. Reimbursements are shown as contributions from MPC within the Financing activities section
of the Consolidated Statements of Cash Flows.
(c) Amount excludes contributions from noncontrolling interests of $95 million, $11 million and $129 million for the years ended Dec. 31,
2017, 2018 and 2019, respectively, as refl ected in the fi nancing section of our Consolidated Statements of Cash Flows.
Below: Operations
Technician Terrence
Roberts at MPLX’s
refi ned product
loading dock on the
Cumberland River in
Nashville, Tennessee
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
È
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
‘ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from
to
Commission file number 001-35714
MPLX LP
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
27-0005456
(I.R.S. Employer Identification No.)
200 E. Hardin Street, Findlay, OH 45840-3229
(Address of principal executive offices) (Zip code)
(419) 421-2414
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Units Representing Limited Partnership Interests
Trading Symbol(s)
MPLX
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes È No ‘
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act. Yes ‘ No È
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 È No ‘
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit such files). Yes È 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 È Accelerated filer ‘ Non-accelerated filer ‘
Smaller reporting company ‘ Emerging growth company ‘
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for
complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ‘
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ‘ No È
The aggregate market value of common units held by non-affiliates as of June 28, 2019 was approximately $9.3 billion. This amount
is based on the closing price of the registrant’s common units on the New York Stock Exchange on June 28, 2019. Common units
held by executive officers and directors of the registrant and its affiliates are not included in the computation. The registrant, solely
for the purpose of this required presentation, has deemed its directors and executive officers and those of its affiliates to be affiliates.
MPLX LP had 1,058,415,865 common units outstanding at February 17, 2020.
DOCUMENTS INCORPORATED BY REFERENCE: None
Table of Contents
PART I
Business
Item 1.
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Item 3.
Item 4. Mine Safety Disclosures
Properties
Legal Proceedings
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
Selected Financial Data
Item 6.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Item 8.
Item 9.
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accountant Fees and Services
PART IV
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
Signatures
Page
3
29
56
57
62
63
63
65
69
102
105
173
173
173
173
183
212
214
215
217
243
244
Unless the context otherwise requires, references in this report to “MPLX LP,” “MPLX,” “the Partnership,”
“we,” “our,” “us,” or like terms refer to MPLX LP and its subsidiaries. Additionally, throughout this Annual
Report on Form 10-K, we have used terms in our discussion of the business and operating results that have been
defined in our Glossary of Terms.
The abbreviations, acronyms and industry terminology used in this report are defined as follows:
Glossary of Terms
ARO
ASC
ASU
ATM Program
Barrel (Bbl)
Bcf/d
Btu
Condensate
DCF (a non-GAAP financial measure)
DOT
EBITDA (a non-GAAP financial measure)
EPA
FASB
FERC
GAAP
Gal
Gal/d
IDR
Initial Offering
IRS
Joint-Interest Acquisition
LIBOR
MarkWest Merger
mbbls
mbpd
mcf
MMBtu
MMcf/d
NGL
NYSE
OTC
Partnership Agreement
PHMSA
PPI
Asset retirement obligation
Accounting Standards Codification
Accounting Standards Update
An at-the-market program for the issuance of common units
One stock tank barrel, or 42 United States gallons of liquid volume,
used in reference to crude oil or other liquid hydrocarbons.
One billion cubic feet per day
One British thermal unit, an energy measurement
A natural gas liquid with a low vapor pressure mainly composed of
propane, butane, pentane and heavier hydrocarbon fractions
Distributable Cash Flow
United States Department of Transportation
Earnings Before Interest, Taxes, Depreciation and Amortization
United States Environmental Protection Agency
Financial Accounting Standards Board
Federal Energy Regulatory Commission
Accounting principles generally accepted in the United States of
America
Gallon
Gallons per day
Incentive Distribution Right
Initial public offering on October 31, 2012
Internal Revenue Service
On September 1, 2017, MPLX acquired certain ownership interests in
joint venture entities indirectly held by Marathon Petroleum
Corporation (“MPC”), collectively:
-
Illinois Extension Pipeline Company, L.L.C. (“Illinois
Extension”)
- LOOP LLC (“LOOP”)
- LOCAP LLC (“LOCAP”)
- Explorer Pipeline Company (“Explorer”)
London Interbank Offered Rate
On December 4, 2015, a wholly-owned subsidiary of MPLX merged
with MarkWest Energy Partners, L.P. (“MarkWest”)
Thousands of barrels
Thousand barrels per day
One thousand cubic feet
One million British thermal units, an energy measurement
One million cubic feet per day
Natural gas liquids, such as ethane, propane, butanes and natural
gasoline
New York Stock Exchange
Over-the-Counter
Fifth Amended and Restated Agreement of Limited Partnership of
MPLX LP, dated as of July 30, 2019
Pipeline and Hazardous Materials Safety Administration
Producer Price Index
Predecessor
Collectively:
- The related assets, liabilities and results of operations of Hardin
Street Marine LLC (“HSM”) prior to the date of the acquisition,
March 31, 2016, effective January 1, 2015
- The related assets, liabilities and results of operations of Hardin
Street Transportation LLC (“HST”), Woodhaven Cavern LLC
(“WHC”) and MPLX Terminals LLC (“MPLXT”) prior to the
date of the acquisition, March 1, 2017, effective January 1, 2015
for HST and WHC and April 1, 2016 for MPLXT
- The related assets, liabilities and results of operations of
Andeavor Logistics LP (“ANDX”) prior to the date of the
acquisition, July 30, 2019, effective October 1, 2018.
The gain or loss recognized when a derivative matures or is settled
United States Securities and Exchange Commission
Steam methane reformer, operated by a third party and located at the
Javelina gas processing and fractionation complex in Corpus Christi,
Texas
The gain or loss recognized on a derivative due to changes in fair
value prior to the instrument maturing or settling
United States Coast Guard
Variable interest entity
Realized derivative gains/losses
SEC
SMR
Unrealized derivative gains/losses
USCG
VIE
Disclosures Regarding Forward-Looking Statements
This Annual Report on Form 10-K, particularly Item 1. Business, Item 1A. Risk Factors, Item 3. Legal
Proceedings, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
and Item 7A. Quantitative and Qualitative Disclosures about Market Risk, includes forward-looking statements
that are subject to risks, contingencies or uncertainties. You can identify forward-looking statements by words
such as “anticipate,” “believe,” “commitment,” “could,” “design,” “estimate,” “expect,” “forecast,” “goal,”
“guidance,” “imply,” “intend,” “may,” “objective,” “opportunity,” “outlook,” “plan,” “policy,” “position,”
“potential,” “predict,” “priority,” “project,” “proposition,” “prospective,” “pursue,” “seek,” “should,” “strategy,”
“target,” “will,” “would” or other similar expressions that convey the uncertainty of future events or outcomes.
Forward-looking statements include, among other things, statements regarding:
•
•
•
•
•
future levels of revenues and other income, income from operations, net income attributable to MPLX
LP, earnings per unit, Adjusted EBITDA or DCF (see the Non-GAAP Financial Information section
below for the definitions of Adjusted EBITDA and DCF);
future levels of capital, environmental or maintenance expenditures, general and administrative and other
expenses;
the success or timing of completion of ongoing or anticipated capital or maintenance projects;
the amount and timing of future distributions; and
the anticipated effects of actions of third parties such as competitors, activist investors or 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. 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:
• Marathon Petroleum Corporation’s (“MPC”) ability to achieve its strategic objectives and the effects of
those strategic decisions on us;
•
•
•
•
•
•
•
•
•
•
•
the risk that anticipated opportunities and any other synergies from or anticipated benefits of the
Andeavor Logistics LP (“ANDX”) acquisition may not be fully realized or may take longer to realize
than expected, including whether the transaction will be accretive within the expected timeframe or at all;
disruption from the ANDX acquisition making it more difficult to maintain relationships with customers,
employees or suppliers;
risks relating to any unforeseen liabilities of ANDX;
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 the business, financial condition, results of operations and cash flows;
adverse changes in laws including with respect to tax and regulatory matters;
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; and
the timing and extent of changes in commodity prices and demand for crude oil, refined products,
feedstocks or other hydrocarbon-based products;
volatility in or degradation of market and industry conditions;
1
•
•
•
•
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 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;
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 reliability of processing units and other equipment;
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 or other hydrocarbon-based products;
changes in the cost or availability of third-party vessels, pipelines, railcars and other means of
transportation for crude oil, natural gas, NGLs, feedstocks and refined products;
the price, availability and acceptance of alternative fuels and alternative-fuel vehicles and laws mandating
such 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, including the dropdowns
completed by MPC, or divestitures of assets;
• midstream and refining industry overcapacity or under capacity;
•
•
•
•
accidents or other unscheduled shutdowns affecting our machinery, pipelines, processing, fractionation
and treating facilities or equipment, or those of our suppliers or customers;
acts of war, terrorism or civil unrest that could impair our ability to gather, process, fractionate or
transport crude oil, natural gas, NGLs or refined products;
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 or other hydrocarbon-based products; and
the other factors described in Item 1A. Risk Factors.
We undertake no obligation to update any forward-looking statements except to the extent required by applicable
law.
2
Part I
Item 1. Business
OVERVIEW
We are a diversified, large-cap master limited partnership (“MLP”) formed in 2012 by MPC (as our sponsor) that
owns and operates midstream energy infrastructure and logistics assets, and provides fuels distribution services.
Our assets include a network of crude oil and refined product pipelines; an inland marine business; light-product,
asphalt, heavy oil and marine terminals; storage caverns; refinery tanks, docks, loading racks, and associated
piping; crude oil and natural gas gathering systems and pipelines; as well as natural gas and NGL processing and
fractionation facilities. The operation of these assets are conducted in our Logistics and Storage (“L&S”) and
Gathering and Processing (“G&P”) operating segments. Our assets are positioned throughout the United States as
depicted in the map below. Our L&S segment primarily engages in the transportation, storage, distribution and
marketing of crude oil, asphalt and refined petroleum products. The L&S segment also includes the operation of
our inland marine business, terminals, rail facilities, storage caverns and refining logistics. Our G&P segment
primarily engages in the gathering, processing and transportation of natural gas as well as the gathering,
transportation, fractionation, storage and marketing of NGLs. The assets and operations of our L&S and G&P
segments described above include the assets and operations of ANDX acquired via merger on July 30, 2019. This
acquisition complemented our existing business in addition to expanding our operations to the West Coast. For
more information on these segments, see Our Operating Segments discussion below. The map below and Item 2.
Properties provide information about our assets as of December 31, 2019:
We continue to have a strategic relationship with MPC, which is a large source of our revenues. We have
executed numerous long-term, fee-based agreements with minimum volume commitments with MPC which
provide us with a stable and predictable revenue stream and source of cash flows. This includes agreements
obtained through our acquisition of ANDX, whereby ANDX had similar agreements with MPC. As of
December 31, 2019, MPC owned approximately 63 percent of our outstanding common units. MPC will
continue to be an important source of our revenues and cash flows for the foreseeable future. We also have
long-term relationships with a diverse set of producer customers in many crude oil and natural gas resource
3
plays, including the Permian Basin, Marcellus Shale, Utica Shale, STACK Shale and Bakken Shale, among
others.
The growth of our business has provided us with the financial flexibility to maintain an investment grade credit
profile and fund our organic growth capital plan with operating cash and debt. We have significant opportunities
to develop, expand and participate in projects which complement our existing assets. We continue to evaluate our
non-organic growth opportunities through third-party midstream acquisitions to enhance our existing geographic
footprint or expand our activities into new areas.
2019 RESULTS
The following table summarizes the operating performance for each segment for the year ended December 31,
2019. For further discussion of our segments and a reconciliation to our Consolidated Statements of Income, see
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations as well as Item
8. Financial Statements and Supplementary Data – Note 10.
2019 Segment Results (in millions)
$9,041
$3,689
$5,352
$10,000
$9,000
$8,000
$7,000
$6,000
$5,000
$4,000
$3,000
$2,000
$1,000
$0
-$1,000
$5,104
$1,753
$3,351
$3,712
$1,874
$1,838
$2,377
$2,752
$(375)
Segment
revenues and
other income
Segment cost
of revenues
and purchases
Segment
income from
operations(1)
Segment
Adjusted
EBITDA(2)
L&S
G&P
(1)
(2)
Includes goodwill impairment of $1.2 billion within our G&P operating segment.
Includes segment adjusted EBITDA attributable to predecessor.
2019 ACQUISITIONS, INVESTMENTS AND OTHER HIGHLIGHTS
MPLX completed its acquisition of ANDX (the “Merger”) on July 30, 2019. The historical results of ANDX
have been incorporated into the MPLX results from October 1, 2018, which is the date that MPC acquired
Andeavor (the former sponsor of ANDX). At the effective time of the Merger, each common unit held by
ANDX’s public unitholders was converted into the right to receive 1.135 MPLX common units. ANDX common
units held by certain affiliates of MPC were converted into the right to receive 1.0328 MPLX common units. The
assets of ANDX complement and enhance MPLX’s asset base and further expand MPLX’s existing footprint.
4
In connection with the Merger, MPLX assumed all outstanding ANDX senior notes, which had an aggregate
principal amount of $3.75 billion with interest rates ranging from 3.5 percent to 6.375 percent and maturity dates
ranging from 2019 to 2047. On September 23, 2019, $3.06 billion aggregate principal amount of ANDX’s
outstanding senior notes were exchanged for an aggregate principal amount of $3.06 billion new unsecured
senior notes issued by MPLX in an exchange offer and consent solicitation undertaken by MPLX, leaving
$690 million aggregate principal of outstanding senior notes issued by ANDX, of which $500 million aggregate
principal amount of outstanding ANDX 5.5 percent senior notes due 2019 were paid off at maturity on
October 15, 2019.
During the year, MPLX also: entered into a Term Loan Agreement, which provides for a committed term loan
facility for up to an aggregate of $1.0 billion; issued $2.0 billion aggregate principal amount of floating rate
senior notes in a public offering; increased its borrowing capacity on the MPLX Credit Agreement (as defined
below) to $3.5 billion; and extended the maturity of the MPLX Credit Agreement to July 30, 2024.
MPLX entered into a joint venture agreement (“Wink to Webster Pipeline JV”) related to the Wink-to-Webster
crude oil pipeline, which remains on schedule to be completed in the first half of 2021 and has 100 percent of the
contractible capacity committed with minimum volume commitments. This pipeline is designed to be a 36-inch
diameter pipeline with a capacity of 1.5 million barrels per day originating in the Permian Basin and with
destination points in the Houston market, including MPC’s Galveston Bay refinery.
We also entered into a joint venture agreement related to the design and construction of the Whistler Pipeline.
The Whistler Pipeline is designed to be a 42-inch diameter pipeline, which will transport approximately 2 billion
Bcf/d of natural gas from Waha, Texas, to the Agua Dulce area in South Texas. The majority of available
capacity on the planned pipeline has been committed with minimum volume commitments. The pipeline is
expected to be in service in the third quarter of 2021.
Additionally, we continue to execute on our organic growth plan through terminal and marine fleet expansions,
the expansion of processing and fractionating capacity at numerous plants, as well as having a continued focus on
the optimization of our portfolio of assets, which could include asset divestitures.
RECENT DEVELOPMENTS
On February 21, 2020, MPLX, through a wholly-owned subsidiary, formed a joint venture with Delek US
Energy, Inc. (“Delek”) (the “WWP Project Financing JV”) for the specific purpose of financing a portion of
MPLX’s and Delek’s combined construction costs for the Wink to Webster pipeline system. Both MPLX and
Delek contributed their respective 15 percent ownership interests in the Wink to Webster Pipeline JV to the
WWP Project Financing JV. Also on February 21, 2020, the WWP Project Financing JV, through a wholly-
owned subsidiary, entered into a committed term loan facility with a syndicate of lenders providing for up to
approximately $608 million in term loan borrowings to, among other things, fund future capital calls received
from the Wink to Webster Pipeline JV and pay debt service costs under the term loan facility prior to the
commercial operation date of the Wink to Webster pipeline system. The WWP Project Financing JV pledged the
combined 30 percent interest in the Wink to Webster Pipeline JV contributed to it by MPLX and Delek to secure
its obligations under the term loan facility.
On January 23, 2020, we announced the board of directors of our general partner had declared a distribution of
$0.6875 per common unit that was paid on February 14, 2020 to common unitholders of record on
February 4, 2020.
MPC’s board of directors has formed a special committee to evaluate strategies to enhance shareholder value
through a review of its Midstream business and to analyze, among other things, the strategic fit of assets with
MPC, the ability to realize full valuation credit for midstream earnings and cash flow, balance sheet impacts
including liquidity and credit ratings, transaction tax impacts, separation costs, and overall complexity.
5
BUSINESS STRATEGIES
Our primary business objective is to enhance the generation of stable cash flows through executing the following
strategies:
Capture Full Midstream Value Chain: We intend to develop incremental infrastructure to support growth across
the hydrocarbon value chain. Touch points across the value chain include gathering, processing, fractionation,
and inbound/outbound logistics assets such as long-haul pipelines and export facilities. This diversification and
integration provide multiple sources of stable fee-based revenue while also enhancing opportunities for third-
party revenue capture.
Enhance Cash Flow Stability: We are focused on growing our fee-based services through long-term contracts
which provide through-cycle cash flow stability. Planned investments in long-haul pipelines are expected to
connect supply to demand markets while adding a source of stable cash flow to the company and expanding our
export capabilities will enhance our ability to meet significant growing market needs both domestically and
globally.
Growth in Premier Basins: Our assets are located in some of the premier production areas in the United States.
Our business strategy and investments are focused on connecting supply to global demand markets. We intend to
increase operating cash flow by investing in opportunities that may arise in our areas of operations and increasing
the utilization of our existing facilities. We will evaluate organic growth projects both within our geographic
footprint as well as in new areas that we consider strategic.
Maintain Financial Discipline: We high-grade our portfolio of investment opportunities to ensure efficient
deployment of capital focusing on mid-teen returns. Our goal is to optimize our cost of capital by maintaining an
investment grade credit profile and funding our organic growth capital plan with operating cash and debt. The
company does not intend to issue public equity to fund its organic growth capital needs.
Maintain Safe and Reliable Operations: We believe that providing safe, reliable and efficient services is a key
component in generating stable cash flows. We are committed to maintaining and improving the safety,
reliability and efficiency of our operations. Our intent is to continue promoting high standards for safety and
environmental stewardship.
6
ORGANIZATIONAL STRUCTURE
The following diagram depicts our organizational structure and MPC’s ownership interest in us as of
February 17, 2020.
Marathon Petroleum Corporation
(NYSE: MPC)
and Affiliates (including our General Partner)
666 million Common Units
(63% of common units outstanding)
Public Unitholders
392 million Common
Units (37% of common
units outstanding)
MPLX GP LLC
(our General Partner)
non-economic general partner interest
Series A Preferred
Unitholders
30 million
Preferred Units
MPLX LP
(NYSE: MPLX)
(the Partnership)
Series B Preferred
Unitholders
600,000
Preferred Units
MPLX Operations LLC
Andeavor Logistics LP
MarkWest Energy Partners, L.P.
L&S
Operating
Subsidiaries
L&S and G&P
Operating
Subsidiaries
G&P
Operating
Subsidiaries
We are an MLP with outstanding common units held by MPC and public unitholders as well as two series of preferred
units. Our common units are publicly traded on the NYSE under the symbol “MPLX.” Our Series A preferred units rank
senior to all common units and pari passu with our Series B preferred units with respect to distributions and rights upon
liquidation. The holders of the Series A preferred units are entitled to receive a quarterly distribution equal to the greater
of $0.528125 per unit or the amount of distributions they would have received on an as converted basis. The holders of
the Series B preferred units are entitled to receive a fixed annual distribution equal to $68.75 per unit, per annum,
payable semi-annually in arrears on February 15 and August 15, or the first business day thereafter, up to and including
February 15, 2023. After February 15, 2023, the holders of Series B preferred units are entitled to receive cumulative,
quarterly distributions payable in arrears on the 15th day of February, May, August and November of each year, or the
first business day thereafter, based on a floating annual rate equal to the three-month LIBOR plus 4.652 percent.
INDUSTRY OVERVIEW
As of December 31, 2019, our diversified services in the midstream sector are across the hydrocarbon value
chain. The types of services provided by the midstream sector, broken down by our segments, are as follows:
L&S:
The midstream sector plays a crucial role in the oil and gas industry by providing transportation, storage and
marketing services across the hydrocarbon value chain as depicted below.
7
Crude oil is the primary raw material for transportation fuels and the basis for many products including plastics
and petrochemicals, in addition to heating oil for homes once it is refined and prepared for use. Pipelines bring
advantaged North American crude oil from the upper Great Plains, Louisiana, Texas, Canada and West Coast to
numerous refineries throughout the United States. Terminals provide for the receipt, storage, blending,
additization, handling and redelivery of refined petroleum products via pipeline, rail, marine and over the road
modes of transportation. This network of logistics infrastructure also allows for export opportunities by
connecting supply to global demand markets. The hydrocarbon market is often volatile and the ability to take
advantage of fast-moving market conditions is enhanced by the ability to store crude oil and other hydrocarbon-
based products at tank farms, caverns, and tanks at refineries and terminals. The ability to store both crude and
refined petroleum products provides flexibility and logistics optionality which allows participants within the
industry to take advantage of changing market conditions.
G&P:
The midstream natural gas industry is the link between the exploration for, and production of, natural gas and the
delivery of its hydrocarbon components to end-use markets. The components of this value chain are graphically
depicted and further described below:
• Gathering. The natural gas production process begins with the drilling of wells into gas-bearing rock
formations. At the initial stages of the midstream value chain, a network of pipelines known as gathering
systems directly connect to wellheads in the production area. These gathering systems then transport raw,
or untreated, natural gas to a central location for treating and processing.
• Processing. Natural gas has a widely varying composition depending on the field, formation reservoir or
facility from which it is produced. Processing removes the heavier and more valuable hydrocarbon
components, which are extracted as a mixed NGL stream that includes ethane, propane, butanes and
natural gasoline (also referred to as “y-grade”). Processing aids in allowing the residue gas remaining
after extraction of NGLs to meet the quality specifications for long-haul pipeline transportation and
commercial use.
• Fractionation. Fractionation is the separation of the mixture of extracted NGLs into individual
components for end-use sale. Fractionation systems typically exist either as an integral part of a gas
processing plant or as a central fractionator.
•
Storage, transportation and marketing. Once the raw natural gas has been treated or processed and the
raw NGL mix has been fractionated into individual NGL components, the natural gas is delivered to
downstream transmission pipelines and NGL components are stored, transported and marketed to end-use
markets.
Due to advances in well completion technology and horizontal drilling techniques, unconventional sources,
such as shale and tight sand formations, have become a source of current and expected future natural gas
production. The industry as a whole is characterized by regional competition, based on the proximity of
gathering systems and processing/fractionating plants to producing natural gas wells, or to facilities that
produce natural gas as a byproduct of refining crude oil. Due to the shift in the source of natural gas
production, midstream providers with a significant presence in the shale plays will likely have a competitive
8
advantage. Well-positioned operations allow access to all major NGL markets and provide for the
development of export solutions for producers. This proximity is enhanced by infrastructure build-out and
pipeline projects.
OUR RELATIONSHIP WITH MPC
One of our competitive strengths is our strategic relationship with MPC, which, with its acquisition of Andeavor
effective October 1, 2018, is the largest crude oil refiner in the United States in terms of refining capacity. MPC
owns and operates 16 refineries in the West Coast, Gulf Coast and Mid-Continent regions of the United States
and distributes refined products through transportation, storage, distribution and marketing services provided by
its midstream segment, which primarily consists of MPLX. MPLX, through its fuels distribution services,
distributes refined products under the Marathon brand through an extensive network of retail locations owned or
operated by independent entrepreneurs, and through company owned and operated convenience stores across the
United States, including under the Speedway brand.
MPC retains a significant interest in us through its non-economic ownership of our general partner and holding
approximately 63 percent of the outstanding common units of MPLX as of December 31, 2019. Given MPC’s
significant interest in us, we believe MPC will promote and support the successful execution of our business
strategies.
OUR OPERATING SEGMENTS
We conduct our operations in two segments, which include L&S and G&P. As of December 31, 2019, our assets
and operations in each of these segments are described below.
L&S:
The L&S segment includes transportation, storage and marketing of crude oil, refined products and other
hydrocarbon-based products. These assets consist of a network of wholly and jointly-owned common carrier
crude oil and refined product pipelines and associated storage assets, terminals, storage caverns, tank farm assets
including rail and truck racks, an inland marine business, an export terminal and a fuels distribution business.
Our pipeline network includes over 13,000 miles of pipeline throughout the continental United States and Alaska.
Our storage caverns consist of butane, propane, and liquefied petroleum gas storage with a combined capacity of
4.7 million barrels located in Neal, West Virginia; Woodhaven, Michigan; Robinson, Illinois; and Jal, New
Mexico. Our terminal facilities for the receipt, storage, blending, additization, handling and redelivery of refined
petroleum products are also located throughout the continental United States and Alaska, and have a combined
total shell capacity of approximately 34 million barrels. We also own tank farm assets at certain MPC refineries
in addition to stand-alone tank farms. Our network of terminals and refinery assets also includes rail and truck
loading lanes/racks in addition to barge docks which support the transportation of hydrocarbon products via rail,
over the road or marine. Our marine business owns and operates 23 boats and 286 barges, including third-party
chartered equipment, and includes a Marine Repair Facility (“MRF”), which is a full-service marine shipyard
located on the Ohio River adjacent to MPC’s Catlettsburg, Kentucky refinery. We also have ownership in various
joint-interests, including LOOP LLC, the only U.S. deep-water oil port, located offshore of Louisiana, which is
used to import and export crude oil. Additionally, our fuels distribution business provides MPC with a broad
range of scheduling and marketing services. Our L&S assets are integral to the success of MPC’s operations. We
continue to evaluate projects and opportunities that will further enhance our existing operations and provide
valuable services to MPC and third parties. The following table summarizes projects and expansions that are
expected to be completed in upcoming years.
9
Projects
Mt. Airy Terminal Expansion-construction of second export dock
Mt. Airy Terminal Expansion-incremental refined product storage
Wink to Webster Pipeline-crude oil pipeline
Whistler Pipeline-natural gas pipeline
BANGL Pipeline-NGL pipeline
Gulf Coast C2+ Fractionation-construction of NGL fractionators
Texas City Export Terminal-NGL storage and export facilities
Carson Crude Terminal Expansion-incremental crude storage
New or expanded
capacity
120 mbpd
TBD
1,500 mbpd
2,000 MMcf/d
500 mbpd
450 mbpd
TBD
2,000 mbbls
Expected in-
service of
expansion
capacity
2020
2020
2021
2021
2021
2021-2024
2022
2022
We generate revenue in the L&S segment primarily by charging tariffs for crude gathering, transporting crude
oil, refined products and other hydrocarbon-based products through our pipelines and at our barge docks
delivering to domestic and international destinations, and fees for storing crude oil and refined products at our
storage facilities. Our marine business generates revenue under a fee-for-capacity contract with MPC. Our fuels
distribution business provides services related to the scheduling and marketing of products on behalf of MPC, for
which it generates revenue based on the volume of MPC’s products sold each month while our wholesale
business includes the operations of several bulk petroleum distribution plants and a fleet of refined product
delivery trucks that distribute commercial wholesale petroleum products. We are also the operator of additional
crude oil and refined product pipelines owned by MPC and third parties for which we are paid operating fees. For
the year ended December 31, 2019, approximately 91 percent of L&S segment operating income was generated
from MPC.
G&P:
We operate several natural gas gathering systems with the scope of gathering services that we provide dependent
upon the producers need and the composition of the raw or untreated gas at our producer customers’ wellheads.
For dry gas, we gather and, if necessary, treat the gas and deliver it to downstream transmission systems. For wet
gas that contains heavier and more valuable hydrocarbons, we gather the gas for processing at a processing
complex. Our natural gas processing complexes remove the heavier and more valuable hydrocarbon components
from natural gas. This allows the residue gas remaining after extraction of the NGLs to meet the quality
specifications for long-haul pipeline transportation or commercial use. The capacities of our gathering systems
and processing complexes are supported by long-term, fee-based agreements with certain major producers and a
number of these agreements include acreage dedications. Once natural gas has been processed at a natural gas
processing complex, the heavier and more valuable hydrocarbon components, which have been extracted as a
mixed NGL stream, can be further separated into their component parts through the process of fractionation. Our
NGL fractionation facilities separate the mixture of extracted NGLs into individual purity product components
for end-use sale. Our fractionation facilities for propane and heavier NGLs are also supported by long-term,
fee-based agreements with certain major producers.
As a result of natural gas production, we recover ethane from the natural gas stream for certain producer
customers, which allows them to meet residue gas pipeline quality specifications and downstream pipeline
commitments. Depending on market conditions, producer customers may also benefit from the potential price
uplift received from the sale of their ethane. We have connections to several downstream ethane pipelines from
many of our systems that benefit our customers.
As production in geographic regions and market demand continues to evolve, so do our planned capital
expenditures. The following table summarizes our properties that are expected to be constructed or have planned
expansions in upcoming years. As of December 31, 2019, our gathering and processing assets include
approximately 9.0 Bcf/d of gathering capacity, 11.6 Bcf/d of natural gas processing capacity and 831 mbpd of
fractionation and stabilization capacity. For a summary of our gas processing facilities, fractionation facilities,
natural gas gathering systems, NGL pipelines and natural gas pipelines see Item 2. Properties - Gathering and
Processing.
10
Plant
Processing (MMcf/d):
Smithburg Complex(1)
Western Oklahoma Complex
Preakness Complex
Fractionation (mbpd):
Hopedale Complex
Existing
capacity
New or
expanded
capacity
Expected in-
service of
expansion
capacity
Geographic Region
—
545
—
240
1,200
180
200
TBD Marcellus Operations
Southwest Operations
2020
Southwest Operations
2020
80
2020 Marcellus/ Utica Operations
(1) This is a Sherwood Midstream LLC (“Sherwood Midstream”) investment. The first of six processing plants within this
complex is scheduled to be in-service during 2020 with a processing capacity of 200 MMcf/d. The estimated completion
dates for the five remaining plants are to be determined.
A significant portion of our business comes from a limited number of key customers. For the year ended
December 31, 2019, revenues earned from two customers are significant to the segment, each accounting for
approximately 14 percent of G&P operating revenues and six percent of consolidated operating revenues,
respectively.
The following table summarizes our key producer customers and attributes for each geographic region:
Key Producer Customers
Volume Protection
Antero Resources,(1) Range Resources,
Penn Energy, Southwestern,(1) CNX,
EQT,(1) HG Energy,(1) and others
Ascent, Gulfport, Antero Resources,(1)
Marathon, EQT and others
Diversified Southern Midstream,(1) and
Core Appalachia Midstream
Encana, WSGP Gas Producing LLC,
Chevron USA, BP and others
Whiting Oil and Gas Corporation,(1) Oasis
Petroleum,(1) Equinor Energy(1)
Pinedale Energy Partners,(1) XTO,(1)
EOG(1)
74% of 2019 capacity contains
minimum volume commitments
27% of 2019 capacity contains
minimum volume commitments
24% of 2019 capacity contains
minimum volume commitments
5% of 2019 capacity contains minimum
volume commitments
N/A
39% of 2019 capacity contains
minimum volume commitments
Marcellus Operations(2)
Utica Operations(2)
Southern Appalachian
Operations
Southwest Operations(2)
Bakken Operations(2)
Rockies Operations(2)
(1) We do not provide gathering services for these producer customers.
(2) Region includes some contracts which contain acreage dedications.
For further financial information regarding our segments, see Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data
included in this Annual Report on Form 10-K.
OUR L&S CONTRACTS WITH MPC AND THIRD PARTIES
Transportation Services Agreements, Storage Services Agreements, Terminal Services Agreements and
Fuels Distribution Services Agreement with MPC
Our L&S assets are strategically located within, and integral to, MPC’s operations. We have entered into multiple
transportation, terminal and storage services agreements with MPC. Under these long-term, fee-based agreements,
we provide transportation, terminal and storage services to MPC and, other than under our marine transportation
services agreement, most of these agreements include minimum committed volumes from MPC. MPC has also
committed to provide a fixed fee for 100 percent of available capacity for boats, barges and third-party chartered
equipment under the marine transportation services agreement. We also have two fuels distribution agreements
with MPC under which we provide scheduling and marketing services of MPC’s products.
11
The following table sets forth additional information regarding our transportation, terminal, fuels distribution,
and storage services agreements with MPC:
Agreement
Initiation Date
Term (years)(1)
MPC minimum
commitment(2)
Transportation Services (mbpd):
Crude pipelines
Refined product pipelines
Marine
Trucking Services
Storage Services (mbbls):
Various
Various
January 2015
October 2014
4-15
6-15
6
1-10
1,842
1,910
N/A(3)
50
Caverns
Various
Tank Farms(4)
Various
Terminal Services(5)
Various
Fuels Distribution Services (million gallons) Various
(1) Renewal terms on our agreements include multiple two to five-year terms for transportation services agreements, one to
two additional five-year terms for our terminal services agreements, various renewal terms ranging from zero to 10 years
for our cavern storage services agreements, various renewal terms ranging from one to five years for our tank farm
storage services agreements, two additional five-year terms for our marine transportation services agreement and one
additional five-year term for one of our two Fuels Distribution Services Agreements. These renewals are automatic,
unless terminated by either party.
4,375
125,499
206,272
23,774
10-17
3-10
Various
10
(2) Commitments for our transportation services agreements refer to throughput in thousands of barrels per day and, for
crude oil transportation services agreements, are adjusted for crude viscosities. Commitments for our cavern storage
services agreements refer to thousands of barrels. Commitments for our terminal services agreements refer to quarterly
terminal throughput or stipulated volumes in thousands of barrels. Commitments for the fuels distribution services
agreements refers to millions of gallons per year. Minimum commitments on some agreements are reduced by any third-
party throughput volumes.
(3) MPC has committed to utilize 100 percent of our available capacity of boats and barges.
(4) Volume shown represents total capacity in thousands of barrels (includes refining logistics tanks).
(5) Some terminal services agreements also contain minimum commitments for activities such as blending, additives,
on-loading and off-loading, and storage.
Under transportation services agreements containing minimum volume commitments, if MPC fails to transport
its minimum throughput volumes during any period, then MPC will pay us a deficiency payment equal to the
volume of the deficiency multiplied by the tariff rate then in effect. Under these transportation services
agreements, the amount of any deficiency payment paid by MPC may be applied as a credit for any volumes
transported on the applicable pipeline in excess of MPC’s minimum volume commitment during a limited
number of succeeding periods, after which time any unused credits will expire.
We have crude oil and asphalt trucking transportation services agreements with MPC. Under these trucking
transportation services agreements, we receive a service fee per barrel for gathering barrels and providing
trucking, dispatch, delivery and data services. Under some of our trucking transportation agreements, if MPC
fails to request the minimum volume commitment to be gathered and delivered, then MPC will pay us a
deficiency payment equal to the volume of the deficiency multiplied by the trucking rate then in effect.
Under most of our terminal services agreements, if MPC fails to meet its minimum volume commitment during
any period, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the
contractual fee then in effect. Some of our terminal services agreements contain minimum commitments for
various additional services such as storage and blending.
We have a fuels distribution service agreement with MPC in which MPC pays MPLX a tiered monthly fee
based on the volume of MPC’s products sold by MPLX each month, subject to a maximum annual volume.
MPLX has agreed to use commercially reasonable efforts to sell not less than a minimum quarterly volume of
MPC’s products during each calendar quarter. If MPLX sells less than the minimum quarterly volume of
MPC’s products during any calendar quarter despite its commercially reasonable efforts, MPC will pay MPLX
a deficiency payment equal to the volume deficiency multiplied by the applicable tiered fee. The dollar amount
12
of actual sales volume of MPC’s products that exceeds the minimum quarterly volume (an “Excess Sale”) for a
particular quarter will be applied as a credit, on a first-in-first-out basis, against any future deficiency payment
owed by MPC to MPLX during the four calendar quarters immediately following the calendar quarter in which
the Excess Sale occurs. Additionally, we have a wholesale fuels distribution services agreement as a result of
the Merger, under which we are required to sell and deliver product to MPC, and MPC is required to purchase
and accept delivery of product from us. MPC pays us an amount equal to our product cost at each terminal,
plus applicable taxes and fees, actual transportation cost and a contracted margin. In the event that MPC fails
to purchase the committed volume, MPC pays an agreed upon amount for each gallon below the committed
volume and will receive a credit for excess volumes purchased in subsequent months to the extent that shortfall
payment were made in the prior twelve months. MPC also provides us margin shortfall support for
non-delivered rack sales.
Pipeline Operating Agreements with MPC
We operate various pipelines owned by MPC under operating services agreements. Under these operating
services agreements, we receive an operating fee for operating the assets, which include certain MPC wholly-
owned or partially-owned crude oil, natural gas, and refined product pipelines, and for providing various
operational services with respect to those assets. We are generally reimbursed for all direct and indirect costs
associated with operating the assets and providing such operational services. These agreements vary in length
and automatically renew with most agreements being indexed for inflation.
Pipeline Operating Agreements with Third Parties
We maintain and operate five joint interest pipelines including Andeavor Logistics Rio Pipeline LLC, Capline
Pipeline Company LLC, Centennial Pipeline LLC, Louisville-Lexington Operation and Muskegon Pipeline LLC.
We receive an operating fee for each of these pipelines, which is subject to adjustment for inflation. In addition,
we are reimbursed for specific costs associated with operating each pipeline. The length and renewal terms for
each agreement vary.
Terminal Services Agreements with Third Parties
We have multiple terminal services agreements with third parties under which we provide use of pipelines and
tank storage, and provide services, facilities and other infrastructure related to the receipt, storage, throughput,
blending and delivery of commodities. Some of these agreements are subject to prepaid throughput volumes
under which we agree to handle a certain amount of product throughput each month in exchange for a
predetermined fixed fee, with any excess throughput or ancillary services subject to additional charges. Under the
remaining agreements we receive an agreed upon fee based on actual product throughput following the
completion of services.
Management Services Agreement with MPC
MPLX has a management services agreement with MPC under which it provides management services to assist
MPC in the oversight and management of the marine business. MPLX receives a fixed annual fee for providing
the required management services. This fee is adjusted annually on the anniversary of the contract for inflation
and any changes in the scope of the management services provided. This agreement is set to expire on January 1,
2021 and automatically renews for two additional renewal terms of five years each unless terminated by either
party.
13
Other Agreements with MPC
We have omnibus agreements with MPC that address our payment of a fixed annual fee to MPC for the provision
of executive management services by certain executive officers of our general partner and our reimbursement to
MPC for the provision of certain services to us, as well as MPC’s indemnification of us for certain matters,
including certain environmental, title and tax matters. In addition, we indemnify MPC for certain matters under
these agreements.
We also have various employee services agreements and a secondment agreement under which we reimburse
MPC for the provision of certain operational and management services to us. All of the employees that conduct
our business are directly employed by affiliates of our general partner.
Additionally, we have certain indemnification agreements with MPC under which MPC retains responsibility for
remediation of known environmental liabilities due to the use or operation of the assets prior to our ownership,
and indemnifies us for any losses we incurred arising out of those remediation obligations. The indemnification
for unknown pre-closing remediation liabilities is generally limited to five years.
OUR G&P CONTRACTS WITH MPC AND THIRD PARTIES
The majority of our revenues in the G&P segment are generated from natural gas gathering, transportation and
processing; NGL gathering, transportation, fractionation, exchange, marketing and storage; and crude oil
gathering and transportation. MPLX enters into a variety of contract types including fee-based,
percent-of-proceeds, keep-whole and purchase arrangements in order to generate service revenue and product
sales. See Item 8. Financial Statements and Supplementary Data - Note 2 for a further description of these
different types of arrangements.
In many cases, MPLX provides services under contracts that contain a combination of more than one of the
arrangements described above. The terms of MPLX’s contracts vary based on gas quality conditions, the
competitive environment when the contracts are signed and customer requirements. In addition, minimum
volume commitments may create contract liabilities or deferred credits if current period payments can be used for
future services. Breakage is estimated and recognized into service revenue in instances where it is probable the
customer will not use the credit in future periods.
MPLX’s contract mix and exposure to natural gas and NGL prices may change as a result of changes in producer
preferences, MPLX expansion in regions where some types of contracts are more common and other market
factors, including current market and financial conditions which have increased the risk of volatility in oil,
natural gas and NGL prices. Any change in mix may influence our long-term financial results.
Keep-whole agreement with MPC
MPLX has a keep-whole commodity agreement with MPC under which MPC pays us a processing fee for NGL’s
related to keep-whole agreements and delivers shrink gas to the producers on our behalf. We pay MPC a
marketing fee in exchange for assuming the commodity risk. The pricing structure under this agreement provides
for a base volume subject to a base rate and incremental volumes subject to variable rates, which are calculated
with reference to certain of our costs incurred as processor of the volumes. The pricing for both the base and
incremental volumes are subject to revision each year. This agreement renews automatically on a year-to-year
basis, unless terminated by either party.
14
COMPETITION
Within our L&S segment, our competition primarily comes from independent terminal and pipeline companies,
integrated petroleum companies, refining and marketing companies, distribution companies with marketing and
trading arms and from other wholesale petroleum products distributors. Competition in any particular geographic
area is affected significantly by the volume of products produced by refineries in the area, and in areas where no
refinery is present, by the availability of products and the cost of transportation to the area from other locations.
As a result of our contractual relationship with MPC under our transportation and storage services agreements,
our terminal services agreement, and our physical asset connections to MPC’s refineries and terminals, we
believe that MPC will continue to utilize our assets for transportation, storage, distribution and marketing
services. If MPC’s customers reduced their purchases of refined products from MPC due to increased availability
of less expensive refined product from other suppliers or for other reasons, MPC may only receive or deliver the
minimum volumes through our terminals (or pay the shortfall payment if it does not deliver the minimum
volumes), which could decrease our revenues.
In our G&P segment, we face competition for natural gas gathering and in obtaining natural gas supplies for our
processing and related services; in obtaining unprocessed NGLs for gathering and fractionation; and in marketing
our products and services. Competition for natural gas supplies is based primarily on the location of gas
gathering systems and gas processing plants, operating efficiency and reliability, and the ability to obtain a
satisfactory price for products recovered. Competitive factors affecting our fractionation services include
availability of capacity, proximity to supply and industry marketing centers, and cost efficiency and reliability of
service. Competition for customers to purchase our natural gas and NGLs is based primarily on price, delivery
capabilities, flexibility and maintenance of high-quality customer relationships.
Our competitors include:
•
natural gas midstream providers, of varying financial resources and experience, that gather, transport,
process, fractionate, store and market natural gas and NGLs;
• major integrated oil companies and refineries;
•
•
•
independent exploration and production companies;
interstate and intrastate pipelines; and
other marine and land-based transporters of natural gas and NGLs.
Some of our competitors operate as MLPs or are owned by infrastructure funds and may enjoy a cost of capital
comparable to and, in some cases, lower than ours. Other competitors, such as major oil and gas and pipeline
companies, have capital resources and contracted supplies of natural gas substantially greater than ours. Smaller
local distributors may enjoy a marketing advantage in their immediate service areas.
We believe that our customer focus, demonstrated by our ability to offer an integrated package of services and
our flexibility in considering various types of contractual arrangements, allows us to compete more effectively.
This includes having access to both NGL and natural gas markets to allow for flexibility in our gathering and
processing in addition to having critical connections to a strong sponsor and key market outlets for NGLs and
natural gas. Our strategic gathering and processing agreements with key producers enhances our competitive
position to participate in the further development of our resource plays. The strategic location of our assets,
including those connected to MPC, and the long-term nature of many of our contracts also provide a significant
competitive advantage.
15
INSURANCE
Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also
cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or
environmental damage and business interruption. We are insured under MPC and other third-party insurance
policies. The MPC policies are subject to shared deductibles.
SEASONALITY
The volume of crude oil and refined products transported and stored utilizing our 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 effects of seasonality on the L&S segment’s revenues will be mitigated through the use of our
fee-based transportation and storage services agreements with MPC that include minimum volume commitments.
Our G&P segment can be affected by seasonal fluctuations in the demand for natural gas and NGLs and the
related fluctuations in commodity prices caused by various factors including variations in weather patterns from
year to year. We are able to manage the seasonality impacts through the execution of our marketing strategy and
via our storage capabilities. Overall, our exposure to the seasonality fluctuations is declining due to our growth in
fee-based business.
REGULATORY MATTERS
Our operations are subject to extensive regulations. The failure to comply with applicable laws and regulations or
to obtain, maintain and comply with requisite permits and authorizations can result in substantial penalties and
other costs to MPLX. The regulatory burden on our operations increases our cost of doing business and,
consequently, affects our profitability. However, we do not believe that we are affected in a significantly
different manner by these laws and regulations than are our competitors. The following is a summary of some of
the environmental, health and safety laws and regulations to which our operations are subject.
Pipeline Regulations
Common Carrier Liquids Pipeline Operations.
We have liquids pipelines that are common carriers subject to regulation by various federal, state and local
agencies. FERC regulates interstate transportation on liquids pipelines under the Interstate Commerce Act
(“ICA”), Energy Policy Act of 1992 (“EPAct 1992”) and the rules and regulations promulgated under those laws.
The ICA and its implementing regulations require that tariff rates for interstate pipelines that transport crude oil,
NGLs (including purity ethane) and refined petroleum products (collectively referred to as “petroleum
pipelines”), be just and reasonable and the terms and conditions of service must not be unduly discriminatory or
confer any undue preference upon any shipper.
The ICA requires that interstate petroleum pipeline transportation rates and terms and conditions of service be
filed with the governing agency, which is FERC, and posted publicly. Under the ICA, persons with a substantial
economic interest in a petroleum pipeline’s rate or service may challenge that rate or service before FERC. FERC
is authorized to investigate such challenges and may suspend the effectiveness of a newly filed rate or term or
condition of service for up to seven months. A successful protest to a new rate or term of condition of service
could result in a petroleum pipeline paying refunds, together with interest, for the period that the rate or term or
condition of service was in effect. A successful protest could also result in FERC disallowing the rate or service.
A successful complaint to an existing rate or service could result in a petroleum pipeline paying reparations,
together with interest, for the period beginning two years prior to the date of the filing of the complaint until the
just and reasonable rate or service was established. FERC may also investigate, upon complaint, protest, or on its
own motion, newly proposed rates and terms of service, existing rates and related rules, and may order a pipeline
to change them prospectively or may bar a pipeline from implementing the proposed new or changed rates or
terms of service.
16
EPAct 1992 deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the
ICA. These rates are commonly referred to as “grandfathered rates.” Our rates for interstate transportation
service in effect for the 365-day period ending on the date of the passage of EPAct 1992 were deemed just and
reasonable and therefore are grandfathered. Subsequent changes to those rates are not grandfathered. New rates
have since been established after EPAct 1992 for certain pipelines, and the rates for certain of our refined
products pipelines have subsequently been approved as market-based rates.
EPAct 1992 required FERC to establish a simplified and generally applicable ratemaking methodology for
interstate petroleum pipelines. As a result, FERC adopted an indexed rate methodology which, as currently in
effect, allows petroleum pipelines to change their rates within prescribed ceiling levels that are tied to annual
changes in the producer price index-finished goods (“PPI-FG”). FERC’s indexing methodology is subject to
review every five years. During the five-year period commencing July 1, 2016 and ending June 30, 2021,
petroleum pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by the change
in the PPI-FG plus an adder that is currently set at 1.23 percent. The current adder will be in effect until June 30,
2021 or until revised by a formal rulemaking by FERC. The indexing methodology is applicable to existing rates,
including grandfathered rates, with the exclusion of market-based rates and settlement rates (unless permitted
under the settlement). A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do
so, and rate increases made under the index are presumed to be just and reasonable unless a protesting party can
demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess
of the pipeline’s costs. However, FERC is currently evaluating how indexed adjustments to rates can be
challenged as well as how pipelines must demonstrate their annual costs and incomes. Therefore, we cannot
guarantee FERC will not make changes to its current policy regarding challenges in the future. Under the
indexing rate methodology, in any year in which the index is negative, a pipeline must lower the rate ceiling and
file to lower rates if any of the pipelines’ rates would otherwise be above the new rate ceiling, unless the pipeline
makes a filing attesting that all shippers that pay the rate have approved the pipeline not lowering the rate or the
pipeline can demonstrate substantial divergence between the actual costs experienced by the pipeline and the rate
resulting from application of the index.
While petroleum pipelines often use the indexing methodology to change their rates, petroleum pipelines may
elect to support proposed rates by using other methodologies such as cost-of-service ratemaking, market-based
rates and settlement rates. A pipeline can follow a cost-of-service approach when seeking to increase its rates
above the rate ceiling provided that the pipeline can establish that there is a substantial divergence between the
actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can
charge market-based rates if it establishes that it lacks significant market power in the affected markets. In
addition, a pipeline can establish rates under settlement if agreed upon by all current shippers. At various times,
we have used index rates, settlement rates and market-based rates to change the rates for our different FERC-
regulated petroleum pipelines.
FERC issued a policy statement in May 2005 stating that it would permit interstate petroleum pipelines, among
others, to include an income tax allowance in cost-of-service rates to reflect actual or potential tax liability
attributable to a regulated entity’s operating income, regardless of the form of ownership. Under FERC’s 2005
policy, a tax pass-through entity seeking such an income tax allowance must establish that its partners or
members have an actual or potential income tax liability on the regulated entity’s income. FERC’s 2005 income
tax policy was the subject of various appeals by shippers, before FERC and the courts, and United States Court of
Appeals for the District of Columbia Circuit issued a ruling that remanded a case related to pass-through entities
and the income tax allowance back to FERC for further review and consideration. In response, FERC issued a
Revised Policy Statement on the Treatment of Income Taxes on March 15, 2018 indicating, among other things,
that interstate petroleum pipelines held by master limited partnerships would no longer be allowed to recover an
income tax allowance in cost-of-service rates. This particular matter is currently in briefing before the United
States Court of Appeals for the District of Columbia Circuit, and we cannot guarantee that FERC or the courts
will not make changes to the policy in the future.
Intrastate services provided by certain of our liquids pipelines are subject to regulation by state regulatory
authorities. Much of the state regulation is complaint-based, both as to rates and priority of access. Not all state
regulatory bodies allow for changes based on an index method similar to that used by FERC. In those
instances, rates are generally changed only through a rate case process. The state regulators could limit our
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ability to increase our rates or to set rates based on our costs or could order us to reduce our rates and could, if
permitted under state law, require the payment of refunds to shippers.
FERC and state regulatory agencies generally have not investigated rates on their own initiative when those rates
are not the subject of a protest or a complaint by a shipper. MPC has agreed not to contest our tariff rates for the
term of our transportation and storage services agreements with MPC, but we do not have any of these types of
agreements with third parties. FERC or a state commission could investigate our rates on its own initiative or at
the urging of a third party if the third party is either a current shipper or is able to show that it has a substantial
economic interest in our tariff rate level.
If our rate levels were investigated, the inquiry could result in a comparison of our rates to those charged by
others or to an investigation of our costs.
If FERC or a state commission were to determine that our rates were or had become unjust and unreasonable, we
could be ordered to reduce rates prospectively and pay refunds and/or reparations to shippers.
FERC-Regulated Natural Gas Pipelines.
Our natural gas pipeline operations are subject to federal, state and local regulatory authorities. Specifically, we
have FERC gas tariffs on file for MarkWest New Mexico, L.L.C. and MarkWest Pioneer, L.L.C., with respect to
our Hobbs Pipeline and the Arkoma Connector Pipeline. In addition, gas tariffs are on file for Rendezvous
Pipeline Company LLC, which moves gas into Kern River Transmission. Additionally, we have ownership
interests in joint ventures with FERC gas tariffs on file.
Under the Natural Gas Act (“NGA”), FERC has authority to regulate natural gas companies that provide natural
gas pipeline transportation services in interstate commerce. FERC’s authority to regulate those services includes
the rates charged for the services, terms and conditions of service, certification and construction of new facilities,
the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition
and disposition of facilities, the initiation and discontinuation of services and various other matters. Natural gas
companies may not charge rates that have been determined to be unjust and unreasonable, or unduly
discriminatory by FERC. In addition, FERC prohibits FERC-regulated natural gas companies from unduly
preferring, or unduly discriminating against, any person with respect to pipeline rates or terms and conditions of
service or other matters. The rates and terms and conditions for the Hobbs Pipeline and the Arkoma Connector
Pipeline can be found in their respective FERC-approved tariffs and in negotiated rate agreements entered into
under those tariffs. Rendezvous Pipeline Company has authority to charge market-based rates, and its tariffs and
pertinent operational information can be found on its website. Pursuant to FERC’s jurisdiction, existing rates
and/or other tariff provisions may be challenged (e.g., by complaint) and rate increases proposed by the pipeline
or other tariff changes may be challenged (e.g., by protest). We also cannot be assured that FERC will continue
to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules, rights
of access, capacity and other issues that impact natural gas facilities. Any successful complaint or protest related
to our services or facilities could have an adverse impact on our revenues.
Energy Policy Act of 2005.
On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005 (“2005 EPAct”).
Under the 2005 EPAct, FERC may impose civil penalties for violations of statutory and regulatory requirements. The
2005 EPAct also amends the NGA to add an anti-market manipulation provision, which makes it unlawful for any
entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC. FERC
issued Order No. 670 to implement the anti-market manipulation provision of the 2005 EPAct. This order makes it
unlawful for gas pipelines and storage companies that provide interstate services to: (i) directly or indirectly, use or
employ any device, scheme or artifice to defraud in connection with the purchase or sale of natural gas subject to the
jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC; (ii) make
any untrue statement of material fact or omit to make any such statement necessary to make the statements made not
misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market
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manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s enforcement authority.
Standards of Conduct.
FERC has adopted affiliate standards of conduct applicable to interstate natural gas pipelines and certain other
regulated entities, defined as “Transmission Providers.” Under these rules, a Transmission Provider becomes
subject to the standards of conduct if it provides service to affiliates that engage in marketing functions (as
defined in the standards). If a Transmission Provider is subject to the standards of conduct, the Transmission
Provider’s transmission function employees (including the transmission function employees of any of its
affiliates) must function independently from the Transmission Provider’s marketing function employees
(including the marketing function employees of any of its affiliates). The Transmission Provider must also
comply with certain posting and other requirements.
Intrastate Natural Gas Pipeline Regulation.
Some of our intrastate gas pipeline facilities are subject to various state laws and regulations that affect the rates
we charge and terms of service. Although state regulation is typically less onerous than FERC, state regulation
typically requires pipelines to charge just and reasonable rates and to provide service on a non-discriminatory
basis. The rates and service of an intrastate pipeline generally are subject to challenge by complaint.
Additionally, FERC has adopted certain regulations and reporting requirements applicable to intrastate natural
gas pipelines (and Hinshaw natural gas pipelines) that provide certain interstate services subject to FERC’s
jurisdiction. We are subject to such regulations and reporting requirements to the extent that any of our intrastate
pipelines provide, or are found to provide, such interstate services.
Additional proposals and proceedings that might affect the natural gas industry periodically arise before
Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes
to our natural gas operations. We do not believe that we would be affected by any such action materially
differently than other midstream natural gas companies with whom we compete.
Natural Gas Gathering Pipeline Regulation.
Section 1(b) of the NGA exempts natural gas production and gathering from the jurisdiction of FERC. There is,
however, no bright-line test for determining the jurisdictional status of pipeline facilities. Rather, FERC looks at
a number of factors, including length and diameter of pipeline facilities, extension beyond the central point of the
field, geographic configuration, location of compressors and processing plants, location of wells along all or part
of the facility and operating pressure of the facilities. We own a number of facilities that we believe qualify as
production and gathering facilities not subject to FERC jurisdiction. The distinction between FERC-regulated
transmission services and federally unregulated gathering services is the subject of litigation from time to time,
so we cannot provide assurance that FERC will not at some point assert that these facilities are within its
jurisdiction or that such an assertion would not adversely affect our results of operations and revenues. In such a
case, we would possibly be required to file a tariff with FERC, potentially provide a cost justification for the
transportation charge and obtain certificate(s) of public convenience and necessity for the FERC-regulated
pipelines, and comply with additional FERC reporting requirements.
In the states in which we operate, regulation of gathering facilities and intrastate pipeline facilities generally
includes various safety, environmental and, in some circumstances, open access, non-discriminatory take
requirement and complaint-based rate regulation. For example, some of our natural gas gathering facilities are
subject to state ratable take and common purchaser statutes and regulations. Ratable take statutes and regulations
generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to
the gatherer for handling. Similarly, common purchaser statutes and regulations generally require gatherers to
purchase gas without undue discrimination as to source of supply or producer. These statutes are designed to
prohibit discrimination in favor of one producer over another producer or one source of supply over another
source of supply. Although state regulation is typically less onerous than at FERC, these statutes and regulations
have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to
purchase or gather natural gas.
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Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC
has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission
companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Our
gathering operations could be adversely affected should they be subject in the future to the application of state or
federal regulation of rates and services or regulated as a public utility. Our gathering operations also may be or
become subject to safety and operational regulations and permitting requirements relating to the design, siting,
installation, testing, construction, operation, replacement and management of gathering facilities. Additional
rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict
what effect, if any, such changes might have on our operations, but the industry could be required to incur
additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Currently, PHMSA is evaluating possible changes to the scope and applicability of 49 Code of Federal
Regulations (“C.F.R.”) Part 192, which governs construction standards and operation of certain natural gas
gathering pipelines. The changes that have been proposed include, but are not limited to, more stringent
construction standards for remote facilities, as well as additional record-keeping requirements. Depending upon
the nature of the final rule-making, those could have an impact upon MPLX LP operations. We do not anticipate
that we would be impacted by these regulatory initiatives to any greater degree than other similarly situated
competitors.
Natural Gas Processing.
Our natural gas processing operations are not presently subject to FERC or state rate regulation. There can be no
assurance that our processing operations will continue to be exempt from rate regulation in the future. In
addition, although the processing facilities may not be directly related, other laws and regulations may affect the
availability of natural gas for processing, such as state regulation of production rates and maximum daily
production allowances from gas wells, which could impact our processing business.
NGL Pipelines.
We have constructed various NGL product pipelines to transport NGL products, some of which are regulated by
FERC, and we may elect to construct additional such pipelines in the future that may be subject to these same
regulatory requirements. Pipelines providing transportation of NGLs in interstate commerce are subject to the
same regulatory requirements as common carrier petroleum pipelines. See “Common Carrier Liquids Pipeline
Operations” above.
Our NGL pipelines are also subject to safety regulation by the DOT under 49 C.F.R. Part 195 for operators of
hazardous liquid pipelines. In October 2019, PHMSA finalized rulemaking reviewing the scope and applicability
of 49 C.F.R. Part 195, including, among other things, expansion of reporting obligations, additional inspection
requirements, emergency order authority, expansion of integrity management principles and expansion of the use
of leak detection systems. These changes became effective in 2020 and could have an impact upon MPLX LP
and other pipeline operators. Our NGL pipelines and operations may also be or become subject to state public
utility or related jurisdiction which could impose additional safety and operational regulations relating to the
design, siting, installation, testing, construction, operation, replacement and management of NGL gathering
facilities.
Propane Regulation.
National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the
safe handling of propane or comparable regulations, have been adopted as the industry standard in all of the states in
which we operate. In some states these laws are administered by state agencies and in others they are administered on a
municipal level. With respect to the transportation of propane by truck, we are subject to regulations promulgated
under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are
administered by the DOT. We conduct ongoing training programs to help ensure that our operations comply with
applicable regulations. We maintain various permits that are necessary to operate our facilities, some of which may be
material to our propane operations. We believe that the procedures currently in effect at all of our facilities for the
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handling, storage and distribution of propane are consistent with industry standards and comply in all material
respects with applicable laws and regulations.
Marine Transportation.
Our marine transportation business is subject to regulation by the USCG, federal laws, including the Jones Act,
state laws and certain international conventions, as well as numerous environmental regulations. The majority of
our vessels are subject to inspection by the USCG and carry certificates of inspection. The crews employed
aboard the vessels are licensed or certified by the USCG. We are required by various governmental agencies to
obtain licenses, certificates and permits for our vessels.
Our marine transportation business competes principally in markets subject to the Jones Act, a federal cabotage
law that restricts domestic marine transportation in the United States to vessels built and registered in the United
States, and manned and owned by United States citizens. We presently meet all of the requirements of the Jones
Act for our vessels. The loss of Jones Act status could have a significant negative effect on us. The requirements
that our vessels be United States built and manned by United States citizens, the crewing requirements and
material requirements of the USCG, and the application of United States labor and tax laws increases the cost of
United States flag vessels when compared with comparable foreign flag vessels. Our marine transportation
business could be adversely affected if the Jones Act were to be modified so as to permit foreign competition that
is not subject to the same United States government imposed burdens. Since the events of September 11, 2001,
the United States government has taken steps to increase security of United States ports, coastal waters and
inland waterways. We believe that it is unlikely that the current cabotage provisions of the Jones Act would be
modified or eliminated in the foreseeable future.
The Secretary of Homeland Security is vested with the authority and discretion to waive the Jones Act to such
extent and upon such terms as the Secretary may prescribe whenever the Secretary deems that such action is
necessary in the interest of national defense. For example, the Secretary has waived the Jones Act generally or
with respect to the transportation of certain petroleum products for limited periods of time and in limited areas
following the occurrence of certain natural disasters such as hurricanes. Waivers of the Jones Act, whether in
response to natural disasters or otherwise, could result in increased competition from foreign tank vessel
operators, which could negatively impact our marine transportation business.
Pipeline Interconnections.
One or more of our plants include pipeline interconnections to, or incidental gathering pipelines that connect the
plants to, interstate pipelines. These pipeline interconnections are an integral part of our facilities and are not
currently being used, nor can they be used in the future, by any third party due to their origin points at our
proprietary facilities. Therefore, we believe these pipeline interconnections are part of our plant facilities and are
not subject to the jurisdiction of FERC. In the event that FERC were to determine that these pipeline
interconnections were subject to its jurisdiction, we believe the pipelines would qualify for a waiver from most
FERC reporting and filing requirements. In the event that FERC were to determine that the pipeline
interconnections did not qualify for such waivers, we would likely be required to file a tariff with FERC for the
pipeline interconnections, provide a cost justification for their transportation rates and provide service to all
potential shippers without undue discrimination. In such event, we may experience increased operating costs and
reduced revenues.
Security.
Certain of our facilities have been preliminarily classified as subject to the Department of Homeland Security
Chemical Facility Anti-Terrorism Standards. In addition, we have several facilities that are subject to the United
States Coast Guard’s Maritime Transportation Security Act, and a number of other facilities that are subject to
the Transportation Security Administration’s Pipeline Security Guidelines and are designated as “Critical
Facilities.” The Transportation Security Administration Security Guidelines are subject to change without formal
regulatory proposal and review. We have an internal inspection program designed to monitor and ensure
compliance with all of these requirements. We believe that we are in material compliance with all applicable
laws and regulations regarding the security of our facilities.
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ENVIRONMENTAL REGULATION
Our management is responsible for ensuring that our operating organizations maintain environmental compliance
systems that support and foster our compliance with applicable laws and regulations, and for reviewing our
overall environmental performance. We also have a Corporate Emergency Response Team that oversees our
response to any major environmental or other emergency incident involving us or any of our facilities.
We believe it is likely that the scientific and political attention to greenhouse gas emissions, climate change and
climate adaptation will continue, with the potential for further regulations that could affect our operations.
Currently, legislative and regulatory measures to address greenhouse gas emissions are in various phases of
review, discussion or implementation. The cost to comply with these laws and regulations cannot be estimated at
this time, but could be significant. For additional information, see Item 1A. Risk Factors. Additionally, we
continuously strive to improve operational and energy efficiencies through resource and energy conservation
where practicable.
Our operations are subject to numerous laws and regulations relating to the protection of the environment. Such
laws and regulations include, among others, the ICA with respect to liquids pipelines, the Clean Air Act with
respect to air emissions, the Clean Water Act (“CWA”) with respect to water discharges, the Resource
Conservation and Recovery Act (“RCRA”) with respect to solid and hazardous waste treatment, storage and
disposal, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) with
respect to releases and remediation of hazardous substances and the Oil Pollution Act of 1990 (“OPA-90”) with
respect to oil pollution and response. In addition, many states where we operate have similar laws. New laws are
being enacted and regulations are being adopted on a continuing basis, and the costs of compliance with such
new laws and regulations are very difficult to estimate until finalized.
For a discussion of environmental capital expenditures and costs of compliance, see Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations-Environmental Matters and
Compliance Costs.
General
Our processing and fractionation plants, storage facilities, pipelines and associated facilities are subject to
multiple obligations and potential liabilities under a variety of federal, regional, state and local laws and
regulations relating to environmental protection. Such environmental laws and regulations may affect many
aspects of our present and future operations, including for example, requiring the acquisition of permits or other
approvals to conduct regulated activities that may impose burdensome conditions or potentially cause delays,
restricting the manner in which we handle or dispose of our wastes, limiting or prohibiting construction or other
activities in environmentally sensitive areas such as wetlands or areas inhabited by threatened or endangered
species, requiring us to incur capital costs to construct, maintain and/or upgrade processes, equipment and/or
facilities, restricting the locations in which we may construct our compressor stations and other facilities and/or
requiring the relocation of existing stations and facilities, and requiring remedial actions to mitigate any pollution
that might be caused by our operations or attributable to former operations. Spills, releases or other incidents may
occur in connection with our active operations or as a result of events outside of our reasonable control, which
incidents may result in non-compliance with such laws and regulations. Any failure to comply with these legal
requirements may expose us to the assessment of sanctions, including administrative, civil and criminal penalties,
the imposition of remedial or corrective actions and the issuance of orders enjoining or limiting some or all of
our operations.
We believe that our operations and facilities are in substantial compliance with applicable environmental
laws and regulations and the cost of continued compliance with such laws and regulations will not have a
material adverse effect on our results of operations or financial condition. We cannot assure, however, that
existing environmental laws and regulations will not be reinterpreted or revised or that new environmental
laws and regulations will not be adopted or become applicable to us. Generally speaking, the trend in
environmental law is to place more restrictions and limitations on activities that may be perceived to
adversely affect the environment, which may cause significant delays in obtaining permitting approvals for
our facilities, result in the denial of our permitting applications, or cause us to become involved in time
consuming and costly litigation. Thus, there can be no assurance as to the amount or timing of future
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expenditures for compliance with environmental laws and regulations, permits and permitting requirements or
remedial actions pursuant to such laws and regulations, and actual future expenditures may be different from the
amounts we currently anticipate. Revised or additional environmental requirements may result in increased
compliance and mitigation costs or additional operating restrictions, particularly if those costs are not fully
recoverable from our customers, and could have a material adverse effect on our business, financial condition,
results of operations and cash flow. We may not be able to recover some or any of these costs from insurance.
Such revised or additional environmental requirements may also result in substantially increased costs and
material delays in the construction of new facilities or expansion of our existing facilities, which may materially
impact our ability to meet our construction obligations with our producer customers.
Remediation
A comprehensive framework of environmental laws and regulations governs our operations as they relate to the
possible release of hazardous substances or non-hazardous or hazardous wastes into soils, groundwater and
surface water and measures taken to mitigate pollution into the environment. CERCLA, also known as the
“Superfund” law, as well as comparable state laws, impose liability without regard to fault or the legality of the
original conduct on certain classes of persons who are considered to be responsible for the release of a hazardous
substance into the environment. These persons include current and prior owners or operators of a site where a
release occurred and companies that transported or disposed or arranged for the transport or disposal of the
hazardous substances released from the site. Under CERCLA, these persons may be subject to strict joint and
several liability for the costs of removing or remediating hazardous substances that have been released into the
environment and for restoration costs and damages to natural resources. RCRA and similar state laws may also
impose liability for removing or remediating releases of hazardous or non-hazardous wastes from impacted
properties.
We currently own or lease, and have in the past owned or leased, properties that have been used over the years
for natural gas gathering, processing and transportation, for NGL fractionation, for the storage, gathering and
transportation of crude oil, or for the storage and transportation of refined products. During the normal course of
operation, whether by us or prior owners or operators, releases of petroleum hydrocarbons or other
non-hazardous or hazardous wastes have or may have occurred. We could be required to remove or remediate
previously disposed wastes or property contamination, including groundwater contamination, or to perform
remedial operations to prevent future contamination. We do not believe that we have any current material
liability for cleanup costs under such laws or for third-party claims.
Ongoing Remediation and Indemnification from Third Parties
The prior third-party owner or operator of our Cobb, Boldman, Kenova, Kermit and Majorsville facilities, has
been, or is currently involved in, certain investigatory or remedial activities with respect to the real property
underlying these facilities. The third party or, in the case of the Kermit Complex, its successor in interest, has
accepted sole liability and responsibility for, and indemnifies us against those activities or any other
environmental condition related to the real property prior to the effective dates of our lease or purchase of the
real property that are not contributed to by us. In addition, the third party, or in the case of the Kermit Complex,
its successor in interest, has agreed to perform all the required response actions at its expense in a manner that
minimizes interference with our use of the properties. We understand that to date, all required actions have been
or are being performed and, accordingly, we do not believe that the remediation obligation of these properties
will have a material adverse impact on our financial condition or results of operations.
The prior third-party owner and/or operator of certain facilities on the real property on which our rail
facility is constructed near Houston, Pennsylvania has been, or is currently involved in, investigatory or
remedial activities related to acid mine drainage (“AMD”) with respect to the real property underlying these
facilities. These investigatory and remedial obligations arise out of an arrangement entered into between the
Pennsylvania Department of Environmental Protection and the third party, which has accepted liability and
responsibility for, and indemnifies us against, any environmental liabilities associated with the AMD that
are not exacerbated by us in connection with our operations. In addition, the third party has agreed to
perform all of the required response actions at its expense in a manner that minimizes interference with our
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use of the property. We understand that to date, all actions required under these agreements have been or
are being performed and, accordingly, we do not believe that the remediation obligation of these properties
will have a material adverse impact on our financial condition or results of operations.
We are also entitled to indemnification from MPC for certain assets we acquired from MPC. In addition, from
time to time, we have acquired, and we may acquire in the future, facilities from third parties or MPC that
previously have been or currently are the subject of investigatory, remedial or monitoring activities relating to
environmental matters. The terms of each acquisition will vary, and in some cases, we may receive contractual
indemnification from the prior owner or operator for some or all of the liabilities relating to such matters, and in
other cases we may agree to accept some or all of such liabilities. We do not believe that the portion of any such
liabilities that MPLX may bear with respect to any such properties previously acquired by MPLX will have a
material adverse impact on our financial condition or results of operations.
Hazardous and Solid Wastes
We may incur liability under RCRA, and comparable or more stringent state statutes, which impose requirements
relating to the handling and disposal of non-hazardous and hazardous wastes. In the course of our operations, we
generate some amount of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may
be regulated as hazardous wastes. It is possible that some wastes generated by us that are currently classified as
non-hazardous wastes may in the future be designated as hazardous wastes, resulting in the wastes being subject
to more rigorous and costly transportation, storage, treatment and disposal requirements.
Water
We maintain numerous discharge permits as required under the National Pollutant Discharge Elimination System
program of the CWA and have implemented systems to oversee our compliance with these permits. In addition,
we are regulated under OPA-90, which, among other things, requires the owner or operator of a tank vessel or a
facility to maintain an emergency plan to respond to releases of oil or hazardous substances. OPA-90 also
requires the responsible company to pay resulting removal costs and damages and provides for civil penalties and
criminal sanctions for violations of its provisions. We operate tank vessels and facilities from which spills of oil
and hazardous substances could occur. We have implemented emergency oil response plans for all of our
components and facilities covered by OPA-90 and we have established Spill Prevention, Control and
Countermeasures plans for all facilities subject to such requirements.
Additionally, OPA-90 requires that new tank vessels entering or operating in U.S. waters be double-hulled and
that existing tank vessels that are not double-hulled be retrofitted or removed from U.S. service. All barges used
for river transport of our raw materials and refined products meet the double-hulled requirements of OPA-90.
Some coastal states in which we operate have passed state laws similar to OPA-90, but with expanded liability
provisions, that include provisions for cargo owner responsibility as well as ship owner and operator
responsibility.
Construction or maintenance of our plants, compressor stations, pipelines, barge dock and storage facilities may
impact wetlands, which are also regulated under the CWA by the EPA, the United States Army Corps of
Engineers and state water quality agencies. Regulatory requirements governing wetlands (including associated
mitigation projects) may result in the delay of our projects while we obtain necessary permits and may increase
the cost of new projects and maintenance activities. We believe that we are in substantial compliance with the
CWA and analogous state laws. However, there is no assurance that we will not incur material increases in our
operating costs or delays in the construction or expansion of our facilities because of future developments, the
implementation of new laws and regulations, the reinterpretation of existing laws and regulations, or otherwise,
including, for example, increased construction activities, potential inadvertent releases arising from pursuing
borings for pipelines, and earth slips due to heavy rain and/or other causes.
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Air Emissions
The CAA and comparable state laws restrict the emission of air pollutants from many sources, including
processing plants and compressor stations, and also impose various monitoring and reporting requirements.
These laws and any implementing regulations may require us to obtain pre-approval for the construction or
modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain
and strictly comply with stringent air permit requirements, utilize specific equipment or technologies to control
emissions, or aggregate two or more of our facilities into one application for permitting purposes. We believe
that our operations are in substantial compliance with applicable air permitting and control technology
requirements. However, we may be required to incur capital expenditures in the future for installation of air
pollution control equipment and encounter construction or operational delays while applying for, or awaiting the
review, processing and issuance of new or amended permits, and we may be required to modify certain of our
operations which could increase our operating costs.
In 2015, the EPA finalized a revision to the National Ambient Air Quality Standards (“NAAQS”) for ozone. The
EPA lowered the primary ozone NAAQS from 75 ppb to 70 ppb. This revision initiated a multi-year process in
which nonattainment designations will be made based on more recent ozone measurements that includes data
from 2016. On November 6, 2017, the EPA finalized ozone attainment/unclassifiable designations for certain
areas under the new standard. In actions dated April 30, 2018 and July 25, 2018, the EPA finalized nonattainment
designations for certain areas under the lower primary ozone standard. In some areas, these nonattainment
designations could result in increased costs associated with, or result in cancellation or delay of, capital projects
at our or our customers’ facilities. For areas designated nonattainment, states will be required to adopt State
Implementation Plans (“SIPs”) for nonattainment areas. These SIPs may include NOx and/or volatile organic
compound (“VOC”) reductions that could result in increased costs to us or our customers. We cannot predict the
effects of the various SIPs requirements at this time.
Climate Change
As a consequence of an EPA administrative conclusion that emissions of carbon dioxide, methane and other
greenhouse gases (“GHGs”) into the ambient air endangers public health and welfare, the EPA adopted
regulations establishing the Prevention of Significant Deterioration (“PSD”) construction and Title V operating
permit programs for GHG emissions from certain large stationary sources that already are potential major
sources of certain principal, or criteria, pollutant emissions. Although the EPA’s PSD and Title V permit
programs are limited to large stationary sources of criteria pollutant emissions, states may seek to adopt their own
permitting programs under state laws that require permit reviews of large stationary sources emitting only GHGs.
If we were to become subject to Title V and PSD permitting requirements due to non-GHG criteria pollutants, or
if the EPA implemented more stringent permitting requirements relating to GHG emissions without regard to
non-GHG criteria pollutants, or if states adopt their own permitting programs that require permit reviews based
on GHG emissions, we may be required to install “best available control technology,” to the extent such
technology is available, to limit emissions of GHGs from any new or significantly modified facilities that we
may seek to construct in the future. In addition, we may experience substantial delays or possible curtailment of
construction or projects in connection with applying for, obtaining or maintaining preconstruction and operating
permits, we may encounter limitations on the design capacities or size of facilities, and we may incur material
increases in our construction and operating costs. We are monitoring GHG emissions from certain of our
facilities in accordance with current GHG emissions reporting requirements in a manner that we believe is in
substantial compliance with applicable reporting obligations.
Also, Congress has from time to time considered legislation to reduce emissions of GHGs, and it is possible that such
legislation could be enacted in the future. In the absence of federal climate legislation in the United States, a number of
state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and
trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and
surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how
legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such
future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate
emissions control systems, to acquire emission allowances or comply with new regulatory or reporting requirements
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including the imposition of a carbon tax. The EPA’s 2016 New Source Performance Standards (“NSPS”) for the oil
and gas industry are aimed at minimizing fugitive emissions and establishing methane emission standards for new and
modified oil and gas production and natural gas processing and transmission facilities as part of the former
Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels
by 2025. This rule is currently being challenged in court by various affected states, and in September 2019, the EPA
proposed amendments that would rescind the methane emission regulations from the NSPS rule. Any such legislation
or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and natural gas
produced by our exploration and production customers that, in turn, could reduce the demand for our services and thus
adversely affect our cash available for distribution to our unitholders.
Under the National Environmental Policy Act, environmental assessments must be performed for certain
projects, including construction of certain new pipelines. It is uncertain the extent to which an environmental
assessment must consider direct and indirect greenhouse gas emissions from a new project. This uncertainty can
result in delay and increased costs in completing new projects.
Endangered Species Act and Migratory Bird Treaty Act Considerations
The federal Endangered Species Act (“ESA”) and analogous state laws regulate activities that may affect
endangered or threatened species, including their habitats. If protected species are located in areas where we
propose to construct new gathering or transportation pipelines, processing or fractionation facilities, or other
infrastructure, such work could be prohibited or delayed in certain of those locations or during certain times,
when our operations could result in a taking of the species or destroy or adversely modify critical habitat that has
been designated for the species. We also may be obligated to develop plans to avoid potential takings of
protected species and provide mitigation to offset the effects of any unavoidable impacts, the implementation of
which could materially increase our operating and capital costs. Existing laws, regulations, policies and guidance
relating to protected species may also be revised or reinterpreted in a manner that further increases our
construction and mitigation costs or restricts our construction activities. Additionally, construction and
operational activities could result in inadvertent impact to a listed species and could result in alleged takings
under the ESA, exposing MPLX to civil or criminal enforcement actions and fines or penalties. Moreover, as a
result of a settlement approved by the United States District Court for the District of Columbia in September
2011, the United States Fish and Wildlife Service (“FWS”) is required to make a determination on listing
numerous species as endangered or threatened under the ESA by completion of the agency’s 2017 fiscal year.
For example, in April 2015, the FWS published a final rule listing the Northern Long Eared Bat as threatened
under the ESA. In another example, in September 2016, the FWS announced the listing of the Eastern
Massasauga rattlesnake as a threatened species under the ESA. In addition, in January 2017, FWS issued a final
rule listing the rusty patched bumblebee as an endangered species effective in February 2017. All of these
species, along with the other endangered species such as the Indiana Bat and American Burying Beetle, are in
areas in which we operate. The listing of these or other species as threatened or endangered in areas where we
conduct operations or plan to construct pipelines or facilities may cause us to incur increased costs arising from
species protection measures or could result in delays in, or prohibit, the construction of our facilities or limit our
customer’s exploration and production activities, which could have an adverse impact on demand for our
midstream operations.
The Migratory Bird Treaty Act implements various treaties and conventions between the United States and
certain other nations for the protection of migratory birds. In accordance with this law, the taking, killing or
possessing of migratory birds covered under this act is unlawful without authorization. If there is the potential to
adversely affect migratory birds as a result of our operations or construction activities, we may be required to
seek authorization to conduct those operations or construction activities, which may result in specified operating
or construction restrictions on a temporary, seasonal, or permanent basis in affected areas and thus have an
adverse impact on our ability to provide timely gathering, processing or fractionation services to our exploration
and production customers.
Safety Matters
Our assets are subject to increasingly strict safety laws and regulations. The transportation and storage of natural
gas and crude oil and refined products involve a risk that hazardous liquids may be released into the environment,
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potentially causing harm to the public or the environment. In turn, such incidents may result in substantial
expenditures for response actions, significant government penalties, liability to government agencies for natural
resources damages and significant business interruption.
At manned facilities, the workplaces associated with the processing and storage facilities and the pipelines we
operate are subject to oversight pursuant to the federal Occupational Safety and Health Act, as amended
(“OSHA”), as well as comparable state statutes that regulate the protection of the health and safety of workers. In
addition, the OSHA hazard-communication standard requires that we maintain information about hazardous
materials used or produced in operations, and that this information be provided to employees, state and local
government authorities and citizens. We believe that we have conducted our operations in substantial compliance
with OSHA requirements, including general industry standards, record-keeping requirements and monitoring of
occupational exposure to regulated substances.
At manned and unmanned facilities, the EPA’s Risk Management Planning requirements at regulated facilities
are intended to protect the safety of the surrounding public. The application of these regulations can result in
increased compliance expenditures.
In general, we expect industry and regulatory safety standards to become stricter over time, resulting in increased
compliance expenditures. While these expenditures cannot be accurately estimated at this time, we do not expect
such expenditures will have a material adverse effect on our results of operations.
The DOT has adopted safety regulations with respect to the design, construction, operation, maintenance,
inspection and management of our pipeline assets. These regulations contain requirements for the development
and implementation of pipeline integrity management programs, which include the inspection and testing of
pipelines and the correction of anomalies. These regulations also require that pipeline operation and maintenance
personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.
These regulations are discussed more fully below.
PHMSA Regulation
We are subject to regulation by the DOT under the Hazardous Liquid Pipeline Safety Act of 1979, also known as
the HLPSA. The HLPSA delegated to the DOT the authority to develop, prescribe and enforce minimum federal
safety standards for the transportation of hazardous liquids by pipeline. Congress also enacted the Pipeline Safety
Act of 1992, also known as the PSA, which added the environment to the list of statutory factors that must be
considered in establishing safety standards for hazardous liquid pipelines, required regulations be issued to define
the term “gathering line” and establish safety standards for certain “regulated gathering lines,” and mandated that
regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in
High Consequence Areas (“HCAs”), defined as those areas that are unusually sensitive to environmental damage,
that cross a navigable waterway, or that have a high population density. In 1996, Congress enacted the
Accountable Pipeline Safety and Partnership Act, also known as the APSPA, which limited the operator
identification requirement mandate to pipelines that cross a waterway where a substantial likelihood of
commercial navigation exists, required that certain areas where a pipeline rupture would likely cause permanent
or long-term environmental damage be considered in determining whether an area is unusually sensitive to
environmental damage, and mandated that regulations be issued for the qualification and testing of certain
pipeline personnel. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, also known as
the PIPES Act, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission
pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline
control room management. We are also subject to the Pipeline Safety, Regulatory Certainty and Job Creation Act
of 2011, which reauthorized funding for federal pipeline safety programs through 2015, increased penalties for
safety violations, established additional safety requirements for newly constructed pipelines and required studies
of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines.
Additionally, we are subject to the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016,
which required PHMSA to develop underground gas storage standards within two years and provided PHMSA
with significant new authority to issue industry-wide emergency orders if an unsafe condition or practices results
in an imminent hazard.
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The DOT has delegated its authority under these statutes to the PHMSA, which administers compliance with
these statutes and has promulgated comprehensive safety standards and regulations for the transportation of
natural gas by pipeline (49 C.F.R. Part 192), as well as hazardous liquids by pipeline (49 C.F.R. Part 195),
including regulations for the design and construction of new pipelines or those that have been relocated, replaced
or otherwise changed (Subparts C and D of 49 C.F.R., Part 195); pressure testing of new pipelines (Subpart E of
49 C.F.R. Part 195); operation and maintenance of pipelines, including inspecting and reburying pipelines in the
Gulf of Mexico and its inlets, establishing programs for public awareness and damage prevention, managing the
integrity of pipelines in HCAs and managing the operation of pipeline control rooms (Subpart F of 49 C.F.R. Part
195); protecting steel pipelines from the adverse effects of internal and external corrosion (Subpart H of 49
C.F.R. Part 195); and integrity management requirements for pipelines in HCAs (49 C.F.R. 195.452). PHMSA
has undertaken a number of initiatives to reevaluate its pipeline safety regulations. We do not anticipate that we
would be impacted by these regulatory initiatives to any greater degree than other similarly situated competitors.
Notwithstanding the foregoing, PHMSA and one or more state regulators have, in isolated circumstances in the
past, sought to expand the scope of their regulatory inspections to include certain in-plant equipment and
pipelines found within NGL fractionation facilities and associated storage facilities in order to assess compliance
with hazardous liquids pipeline safety requirements. If any of these actions were made broadly enforceable as
part of a rule-making process or codified into law, they could result in additional capital costs, possible
operational delays and increased costs of operation.
Pipeline Control and Monitoring
The majority of our pipelines are operated from central control rooms. These control centers operate with a
SCADA (supervisory control and data acquisition) system equipped with computer systems designed to
continuously monitor operational data. Monitored data includes pressures, temperatures, gravities, flow rates and
alarm conditions. These systems include leak detection monitoring and alarms if pre-established operating
parameters are exceeded. These control centers operate remote pumps, motors and valves associated with the
receipt and delivery of products, and provide for the remote-controlled shutdown of pump stations on the
pipelines. These systems also include fully functional back-up operations maintained and routinely operated
throughout the year to ensure safe and reliable operations.
We monitor the structural integrity of our pipelines through a program of periodic internal assessments using
high resolution internal inspection tools, as well as hydrostatic testing and direct assessment, that conform to
federal standards. We accompany these assessments with a review of the data and repair anomalies, as required,
to ensure the integrity of the pipeline. We then utilize sophisticated risk algorithms and a comprehensive data
integration effort to ensure that the highest risk pipelines receive the highest priority for scheduling subsequent
integrity assessments. We use external coatings and impressed current cathodic protection systems to protect
against external corrosion. We conduct all cathodic protection work in accordance with National Association of
Corrosion Engineers standards. We continually monitor, test and record the effectiveness of these corrosion
inhibiting systems.
Product Quality Standards
Refined products and other hydrocarbon-based products that we transport are generally sold by us or our
customers for consumption by the public. Various federal, state and local agencies have the authority to prescribe
product quality specifications for products. The EPA established sulfur specifications for natural gasoline sold as
certified ethanol denaturant effective January 1, 2017. The EPA has also proposed product quality specifications
for natural gasoline used for blendstock in ethanol flex fuel. The EPA has also established product quality
specifications related to butane blending, which we perform at certain of our light products storage facilities.
Changes in product quality specifications or blending requirements could reduce our throughput volumes, require
us to incur additional handling costs or require capital expenditures. For example, different product specifications
for different markets affect the fungibility of the products in our system and could require the construction of
additional storage. In addition, changes in the product quality of the products we receive on our product pipelines
could reduce or eliminate our ability to blend products.
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Tribal Lands
Various federal agencies, including the EPA and the Department of the Interior, along with certain Native
American tribes, promulgate and enforce regulations pertaining to oil and gas operations on Native American
tribal lands where we operate. These regulations include such matters as lease provisions, drilling and production
requirements, and standards to protect environmental quality and cultural resources. For example, the EPA has
established a preconstruction permitting program for new and modified minor sources throughout Native
American tribal lands, and new and modified major sources in nonattainment areas in those areas. In addition,
each Native American tribe is a sovereign nation having the right to enforce certain laws and regulations and to
grant approvals independent from federal, state and local statutes and regulations. These laws and regulations
may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent
or delay our ability to conduct, our operations on such lands.
EMPLOYEES
We are managed and operated by the board of directors and executive officers of MPLX GP LLC (“MPLX GP”),
our general partner. Our general partner has the sole responsibility for providing the employees and other
personnel necessary to conduct our operations. All of the employees that conduct our business are directly
employed by affiliates of our general partner. Our general partner and its affiliates have approximately 6,200 full-
time employees that provide services to us under our employee services agreements. We believe that our general
partner and its affiliates have a satisfactory relationship with those employees.
AVAILABLE INFORMATION
General information about MPLX LP and our general partner, MPLX GP, including Governance Principles,
Audit Committee Charter, Conflicts Committee Charter and Certificate of Limited Partnership, can be found at
www.mplx.com. In addition, our Code of Business Conduct and Code of Ethics for Senior Financial Officers are
available in this same location.
MPLX LP uses its website, www.mplx.com, as a channel for routine distribution of important information,
including news releases, analyst presentations and financial information. Our Annual Report on Form 10-K,
Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to
those reports, are available free of charge through our website as soon as reasonably practicable after the reports
are filed or furnished with the SEC, or on the SEC’s website at www.sec.gov. These documents are also available
in hard copy, free of charge, by contacting our Investor Relations office. In addition, our website allows investors
and other interested persons to sign up to automatically receive email alerts when we post news releases and
financial information on our website. Information contained on our website is not incorporated into this Annual
Report on Form 10-K or other securities filings.
Item 1A. Risk Factors
You should carefully consider each of the following risks and all the other information contained in this Annual
Report on Form 10-K in evaluating us and our common units. Some of these risks relate principally to our
business, the business and operations of MPC and the industry in which we operate, while others relate
principally to tax matters, ownership of our common units and the securities markets generally.
Our business, financial condition, results of operations or cash flows could be materially and adversely affected
by these risks, and, as a result, the trading price of our common units could decline.
Risks Relating to Our Business
Our substantial debt and other financial obligations could impair our financial condition, results of
operations and cash flow, and our ability to fulfill our debt obligations.
We have significant debt obligations, which totaled $20.7 billion as of December 31, 2019. We may incur
significant debt obligations in the future, including under our loan agreement with MPC. Our existing and
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future indebtedness may impose various restrictions and covenants on us that could have, or the incurrence of
such debt could otherwise result in, material adverse consequences, including:
• We may have difficulties obtaining additional financing for working capital, capital expenditures,
acquisitions, or general business purposes on favorable terms, if at all, or our cost of borrowing may
increase.
• We may be at a competitive disadvantage compared to our competitors who have proportionately less
debt, or we may be more vulnerable to, and have limited flexibility to respond to, competitive pressures
or a downturn in our business or the economy generally.
•
If our operating results are not sufficient to service our indebtedness, we may be required to reduce our
distributions, reduce or delay our business activities, investments or capital expenditures, sell assets or issue
equity, which could materially and adversely affect our financial condition, results of operations, cash flows
and ability to make distributions to unitholders, as well as the trading price of our common units.
• The operating and financial restrictions and covenants in our revolving credit facility and any future
financing agreements could restrict our ability to finance our operations or capital needs or to expand or
pursue our business activities, which may, in turn, limit our ability to make distributions to our
unitholders. Our ability to comply with these covenants may be impaired from time to time if the
fluctuations in our working capital needs are not consistent with the timing for our receipt of funds from
our operations.
•
If we fail to comply with our debt obligations and an event of default occurs, our lenders could declare
the outstanding principal of that debt, together with accrued interest, to be immediately due and payable,
which may trigger defaults under our other debt instruments or other contracts. Our assets may be
insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss
of their investment.
A significant decrease in oil and natural gas production in our areas of operation, whether due to sustained
declines in oil, natural gas and NGL prices, natural declines in well production, or otherwise, may adversely
affect our revenues, financial condition, and cash available for distribution.
A significant portion of our operations is dependent on the continued availability of natural gas and crude oil
production. The production from oil and natural gas reserves and wells owned by our producer customers will
naturally decline over time, which means that our cash flows associated with these wells will also decline over
time. To maintain or increase throughput levels and the utilization rate of our facilities, we must continually
obtain new oil, natural gas, NGL and refined product supplies, which depend in part on the level of successful
drilling activity near our facilities, our ability to compete for volumes from successful new wells and our ability
to expand our system capacity as needed.
We have no control over the level of drilling activity in the areas of our operations, the amount of reserves
associated with the wells or the rate at which production from a well will decline. In addition, we have no control
over producers or their production decisions, which are affected by, among other things, prevailing and projected
energy prices, drilling costs per mcf or barrel, demand for hydrocarbons, operational challenges, access to
downstream markets, the level of reserves, geological considerations, governmental regulations and the
availability and cost of capital. Because of these factors, even if oil or natural gas reserves are known to exist in
areas served by our assets, producers may choose not to develop those reserves. Reductions in exploration or
production activity in our areas of operations could lead to reduced throughput on our pipelines and utilization
rates of our facilities.
Decreases in energy prices can decrease drilling activity, production rates and investments by third parties
in the development of new oil and natural gas reserves. The prices for oil, natural gas and NGLs depend
upon factors beyond our control, including global and local demand, production levels, changes in interstate
pipeline gas quality specifications, imports and exports, seasonality and weather conditions, economic and
political conditions domestically and internationally and governmental regulations. Sustained periods of
low prices could result in producers also significantly curtailing or limiting their oil and gas drilling
operations which could substantially delay the production and delivery of volumes of oil, gas and NGLs to
our facilities and adversely affect our revenues and cash available for distribution. This impact may also be
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exacerbated due to the extent of our commodity-based contracts, which are more directly impacted by
changes in gas and NGL prices than our fee-based contracts due to frac spread exposure and may result in
operating losses when natural gas becomes more expensive on a Btu equivalent basis than NGL products. In
addition, our purchase and resale of gas and NGLs in the ordinary course exposes us to significant risk of
volatility in gas or NGL prices due to the potential difference in the time of the purchases and sales and the
potential difference in the price associated with each transaction, and direct exposure may also occur
naturally as a result of our production processes. The significant volatility in natural gas, NGL and oil
prices could adversely impact our unit price, thereby increasing our distribution yield and cost of capital.
Such impacts could adversely impact our ability to execute our long-term organic growth projects, satisfy
our obligations to our customers, and make distributions to unitholders at intended levels, and may also
result in non-cash impairments of long-lived assets or goodwill or other-than-temporary non-cash
impairments of our equity method investments.
We may not have sufficient cash from operations after the establishment of cash reserves and payment of our
expenses, including cost reimbursements to MPC and its affiliates, to enable us to pay the minimum quarterly
distribution to our unitholders.
We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum
quarterly distribution to our unitholders. The amount of cash we can distribute on our common units depends
principally on the amount of cash we generate from our operations, which may fluctuate from quarter to quarter
based on, among other things:
•
•
•
•
•
•
the fees and tariff rates we charge and the margins we realize for our services and sales;
the prices of, level of production of and demand for oil, natural gas, NGLs and refined products;
the volumes of natural gas, crude oil, NGLs and refined products we gather, process, store, transport and
fractionate;
the level of our operating costs including repairs and maintenance;
the relative prices of NGLs and crude oil, which impact the effectiveness of our hedging program; and
prevailing economic conditions.
In addition, the actual amount of cash available for distribution may depend on other factors, some of which are
beyond our control, including:
•
•
•
•
•
•
•
•
the amount of our operating expenses and general and administrative expenses, including cost
reimbursements to MPC in respect of those expenses;
our debt service requirements and other liabilities;
fluctuations in our working capital needs;
our ability to borrow funds and access capital markets;
restrictions in our joint venture agreements, revolving credit facility or other agreements governing our
debt;
the level and timing of capital expenditures we make, including capital expenditures incurred in
connection with our enhancement projects;
the cost of acquisitions, if any; and
the amount of cash reserves established by our general partner in its discretion.
In an effort to fund a greater portion of our organic growth with retained cash, the amount of cash reserves
established by our general partner may increase in the future, which in turn may further reduce the amount of
cash available for distribution.
Furthermore, the amount of cash we have available for distribution depends primarily on our cash flow and
not solely on profitability, which is affected by non-cash items. As a result, we may make distributions during
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periods when we record net losses and may not make distributions during periods when we record net income.
The number of our outstanding common units has increased significantly, and we have outstanding an
additional class of preferred units as a result of the Merger, which could make it more difficult for us to pay
the current level of quarterly distributions.
We issued approximately 263 million common units in connection with the Merger. Accordingly, the aggregate
dollar amount required to pay the quarterly distribution on all our common units has increased, which could
increase the likelihood that we will not have sufficient funds to pay the current level of quarterly distributions to
all unitholders.
Further, we issued 600,000 new Series B preferred units in the Merger. We must pay distributions that have
accrued on the Series A preferred units and the new Series B preferred units prior to paying any distributions on
our common units. Distributions are payable on the Series A preferred units at a rate of the greater of $0.528125
per quarter per Series A preferred unit or the quarterly distribution that the holder would have received with
respect to common units on an as-converted basis. The requirement to pay distributions on the new Series B
preferred units increases the likelihood that we will not have sufficient funds to pay the current level of
distributions to our common unitholders following the completion of the Merger.
Global economic conditions may have adverse impacts on our business and financial condition.
Changes in economic conditions could adversely affect our financial condition and results of operations. A
number of economic factors, including gross domestic product, consumer interest rates, government spending,
consumer confidence and debt levels, retail trends, inflation, tariffs, trade agreements and foreign currency
exchange rates, may generally affect our business. Recessionary economic cycles, higher unemployment rates,
higher fuel and other energy costs, higher tax rates and global outbreaks of infectious diseases, such as the
coronavirus first detected in Wuhan, China, may adversely affect demand for natural gas, NGLs and crude oil.
Also, any tightening of the capital markets could adversely impact our ability to execute our long-term organic
growth projects and meet our obligations to our customers and limit our ability to raise capital and, therefore,
have an adverse impact on our ability to otherwise take advantage of business opportunities or react to changing
economic and business conditions. These factors could have a material adverse effect on our revenues, income
from operations, cash flows and our quarterly distribution on our common units.
Our investments in joint ventures decrease our ability to manage risk.
We conduct some of our operations through joint ventures in which we share control over certain economic and
business interests with our joint venture partners. Our joint venture partners may have economic, business or
legal interests or goals that are inconsistent with our goals and interests or may be unable to meet their
obligations. Failure by us, or an entity in which we have an interest, to adequately manage the risks associated
with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of
operations of our joint ventures and adversely affect our business, financial condition, results of operations and
cash flows.
Our expansion of existing assets and the construction of new assets will be subject to regulatory,
environmental, political, legal and economic risks that could adversely impact our business, financial
condition, results of operations and cash flows.
One of the ways we intend to grow our business is through the construction of, or additions to, our existing gathering,
transportation, treating, processing, storage and fractionation facilities. We may also grow our business by constructing
new pipelines or expanding existing pipelines by adding horsepower or pump stations or by adding additional pipelines
along existing pipelines. Such construction requires the expenditure of significant amounts of capital, which may
exceed our expectations, and involves numerous regulatory, environmental, political and legal uncertainties, most of
which are beyond are control. Factors beyond our control include delays caused by third-party landowners,
unavailability of materials, labor shortages or disruptions, environmental constraints, financing, accidents, weather and
other factors. Additionally, we are subject to numerous regulatory, environmental, political, legal and inflationary
uncertainties, including societal sentiment regarding the development and use of carbon-based fuels, political pressures
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and the influence of environmental or other special interest groups, as well as stringent and lengthy federal, state and
local permitting, zoning, consent, or authorizations requirements, or new laws, regulations, requirements or
enforcement actions, which may cause us to incur additional capital expenditures, delay, interfere with or impair our
construction activities, including by requiring the redesign of facilities, the acquisition of additional equipment, and
relocations or rerouting of facilities, and subject us to additional expenses or penalties and adversely affect our
operations and cash flows available for distribution to unitholders. The approval process for storage and transportation
projects has become increasingly challenging, due in part to state and local concerns related to pipelines, negative
public perception regarding the oil and gas industry, and concerns regarding greenhouse gas emissions downstream of
pipeline operations. If we undertake these projects, we may not be able to complete them on schedule, or at all, or at
the budgeted cost. We also may be required to incur additional costs and expenses in connection with the design and
installation of our facilities due to their location and the surrounding terrain. We may be required to install additional
facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our
operations to the extent that the facilities are not designed or installed correctly.
For example, certain of our processing, fractionation and pipeline facilities are located in mountainous areas such
as our Utica, Marcellus and southern Appalachian operations, which may require specially designed foundations,
retaining walls and other structures or facilities. If such foundations, retaining walls or other facilities are not
designed or installed correctly, do not perform as intended or fail, we may be required to incur significant capital
expenditures to correct or repair the deficiencies, or may incur significant damage to or loss of facilities, and our
operations may be interrupted as a result of deficiencies or failures. In addition, such deficiencies may cause
damages to the surrounding environment, including slope failures, stream impacts and other natural resource
damages, and we may as a result also be subject to increased operating expenses or environmental penalties and
fines. In addition, certain agreements with our customers contain substantial financial penalties or give the
producer the right to repurchase certain assets and terminate their contracts with us if construction deadlines are
not achieved. Any such penalty or contract termination could have a material adverse effect on our income from
operations and cash available for distribution.
Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For
instance, if we build a new pipeline, the construction may occur over an extended period of time, and we may not
receive any material increases in revenues until after completion of the project, if at all.
We may not always be able to accurately estimate hydrocarbon reserves and expected production volumes;
therefore, volumes we service in the future could be less than we anticipate.
We work closely with our producer customers in an effort to understand hydrocarbon reserves and expected
production volumes. We periodically review or have outside consultants review hydrocarbon reserve information
and expected production data that is publicly available or that is provided to us by our producer customers.
However, we may not be able to accurately estimate hydrocarbon reserves and production volumes expected to
be delivered to us for a variety of reasons, including the unavailability of sufficiently detailed information and
unanticipated changes in producers’ expected drilling schedules. Accordingly, we may not have accurate
estimates of total reserves serviced by our assets, the anticipated life of such reserves or the expected volumes to
be produced from those reserves.
Furthermore, we may have only limited oil, natural gas, NGL or refined product supplies committed to any new facility
prior to its construction. We may construct facilities to capture anticipated future growth in production or satisfy
anticipated market demand which does not materialize, the facilities may not operate as planned or may not be used at
all. In order to attract additional oil, natural gas, NGL or refined product supplies from a customer, we may be required
to order equipment and facilities, obtain rights of way or other land rights or otherwise commence construction activities
for facilities that will be required to serve such customer’s additional supplies prior to executing agreements with the
customer. If such agreements are not executed, we may be unable to recover such costs and expenses. We may also rely
on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be
inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result,
new facilities may not be able to attract enough oil, natural gas, NGLs or refined products to achieve our expected
33
investment return or result in immediate revenue increases, which could adversely affect our operations and cash
available for distribution. Alternatively, oil, natural gas, NGL or refined product supplies committed to facilities under
construction may be delivered prior to completion of such facilities, or we may otherwise have unexpected increase in
volumes that could adversely affect our ability to expand our facilities. In such event, we may be required to temporarily
utilize third-party facilities for such oil, natural gas, NGLs or refined products, which may increase our operating costs
and reduce our cash available for distribution.
We engage in commodity derivative activities to mitigate the impact of commodity price volatility on our cash
flows, but these activities may reduce our earnings, profitability and cash flows. In addition, we may not
accurately predict future commodity price fluctuations, our risk management activities may impair our ability
to benefit from price increases, and additional regulation of commodity derivative activities could adversely
impact our ability to manage these risks.
Our operations expose us to fluctuations in commodity prices. We utilize derivative financial instruments related
to the future price of crude oil, natural gas and certain NGLs with the intent of reducing volatility in our cash
flows due to fluctuations in commodity prices.
The extent of our commodity price exposure is related largely to our contract mix and the effectiveness and scope
of our derivative activities. We have a policy to enter into derivative transactions related to only a portion of the
volume of our expected production or fuel requirements that are subject to commodity price volatility and, as a
result, we expect to continue to have some direct commodity price exposure. Our actual future production or fuel
requirements may be significantly higher or lower than we estimate at the time we enter into derivative
transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity
price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative
financial instruments, we might be forced to settle all or a portion of our derivative transactions without the
benefit of the cash flow from our sale or purchase of the underlying physical commodity, which could result in a
substantial diminution of our liquidity. Alternatively, we may seek to amend the terms of our derivative financial
instruments, including the extension of the settlement date of such instruments. Additionally, because we may
use derivative financial instruments relating to the future price of crude oil to mitigate our exposure to NGL price
risk, the volatility of our future cash flows and net income may increase if there is a change in the pricing
relationship between crude oil and NGLs. As a result of these factors, our risk management activities may not be
as effective as we intend in reducing the downside volatility of our cash flows and, in certain circumstances, may
actually increase the volatility of our cash flows. In addition, our risk management activities are subject to the
risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of
the derivative instruments are imperfect and our risk management policies and procedures are not properly
followed. For further information about our risk management policies and procedures, please read Item 8.
Financial Statements and Supplementary Data – Note 16.
To the extent that we do not manage the commodity price risk relating to a position that is subject to commodity
price risk and commodity prices move adversely, we could suffer losses. Such losses could be substantial and
could adversely affect our operations and cash flows available for distribution. In addition, managing the
commodity risk may actually reduce our opportunity to benefit from increases in the market or spot prices.
As a result of the Dodd-Frank Act, OTC derivatives markets and entities are subject to regulation by the Commodities
Futures Trading Commission (the “CFTC”), the SEC and other regulators. The CFTC has designated certain interest
rate swaps and credit default swaps for mandatory clearing and exchange trading. To the extent we engage in such
transactions that are or become subject to such rules in the future, we will be required to comply or to take steps to
qualify for an exemption to such requirements. Although we believe that we qualify for the end-user exception to the
mandatory clearing requirements for swaps to hedge our commercial risks, the application of the mandatory clearing
and trade execution requirements to other market participants may change the cost and availability of the swaps that
we use for hedging. Additional mandatory clearing requirements could be imposed that may impair our ability to
maintain OTC hedging positions or require us to post collateral. The Dodd-Frank Act and its implementing
regulations, including those not yet finalized, could significantly increase the cost of derivative contracts, materially
alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter,
34
reduce our ability to monetize or restructure our existing derivative contracts, increase the administrative burden and
regulatory risk associated with entering into certain derivative contracts, and increase our exposure to less credit-
worthy counterparties. As a result, if we reduce our use of derivatives, our results of operations may become more
volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund
capital expenditures. Any of these consequences could have a material adverse effect on our income from operations
and cash flows available for distribution.
Due to an increased domestic supply of NGLs, we may be required to find alternative NGL market outlets and
to rely more heavily on the export of NGLs, which may increase our operating costs or reduce the price
received for NGLs and thereby reduce our cash available for distribution.
Due to increased production of natural gas, particularly in shale plays, there is an increased domestic supply of
NGLs, which is currently outpacing, and could continue to outpace, domestic demand. As a result, we and our
producer customers may need to continue to find alternate NGL market outlets and to rely more heavily on the
export of NGLs. Our ability to find alternative NGL market outlets is dependent upon a variety of factors,
including the construction and installation of additional NGL transportation infrastructure necessary to transport
NGLs to other markets. In order to obtain committed transportation capacity, it may be necessary to make
significant minimum volume commitments, with take or pay payments or deficiency fees if the minimum volume
is not delivered. In other instances, we may enter into long-term sales arrangements, and we may incur shortfall
or deficiency fees or be subject to other liabilities, including breach of contract claims, if we do not deliver the
contracted quantity. We market NGLs on behalf of certain of our producer customers, and as a result, we may
make such commitments on behalf of those producer customers. We expect to be able to pass such commitments
through to our producer customers, but if we were unable to do so, our operating costs may increase significantly,
which could have a material adverse effect on our results of operations and our ability to make cash distributions.
Certain of our producer customers have elected, or may from time to time in the future elect, to take in kind and
market their NGLs directly, which may also impact our ability to meet any obligations we may have to deliver
contracted quantities of NGLs or other commitments. Similarly, our ability to export NGLs on a competitive
basis is impacted by various factors, including:
•
•
•
•
•
availability of sufficient railcar, tanker and terminalling facility capacity;
currency fluctuations;
compliance with additional governmental regulations and maritime requirements, including U.S. export
controls and foreign laws, sanctions regulations and the Foreign Corrupt Practices Act;
risks of loss resulting from non-payment or non-performance by international purchasers; and
political and economic disturbances in the countries to which NGLs are being exported.
The above factors could increase our operating costs or adversely affect the price that we and our producer
customers receive for NGLs, which in turn may have a material adverse effect on our volumes, revenues, income
and cash available for distribution.
We depend on third parties for the oil, natural gas and refined products we gather, transport and store, the
natural gas and refinery off-gas we process, and the NGLs we fractionate and stabilize at our facilities, and a
reduction in these quantities could reduce our revenues and cash flow.
A significant portion of our supply of oil, natural gas, refinery off-gas, NGLs and refined products comes from a limited
number of key producers/suppliers, who may be under no obligation to deliver a specific volume to our facilities. If any
of these significant suppliers, or a significant number of smaller producers, were to decrease the supply of oil, natural
gas, refinery off-gas, NGLs or refined products to our systems and facilities for any reason, we could experience
difficulty in replacing those lost volumes. In some cases, the producers or suppliers are responsible for gathering or
delivering oil, natural gas, refinery off-gas, NGLs or refined products to our facilities or we rely on other third parties to
deliver volumes to us on behalf of the producers or suppliers. If such producers, suppliers or other third parties are
unable, or otherwise fail to, deliver the volumes to our facilities, or if our agreements with any of these third parties
terminate or expire such that our facilities are no longer connected to their gathering or transportation systems or
35
the third parties modify the flow of natural gas, refinery off-gas or NGLs on those systems away from our facilities, the
throughput on and utilization of our facilities may be reduced, or we may be required to incur significant capital
expenditures to construct and install gathering pipelines or other facilities to be able to receive such volumes. Because
our operating costs are primarily fixed, a reduction in the volumes delivered to us would result not only in a reduction
of revenues, but also a decline in net income and cash flow.
We may not be able to retain existing customers, or acquire new customers, which would reduce our revenues
and limit our future profitability.
A significant portion of our business comes from a limited number of key customers. The renewal or replacement
of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends
on a number of factors beyond our control, including competition from other gatherers, processors, pipelines and
fractionators, and the price of, and demand for, natural gas, NGLs, crude oil and refined products in the markets
we serve. Our competitors include large oil, natural gas, refining and petrochemical companies, some of which
have greater financial resources, more numerous or greater capacity pipelines, processing and other facilities,
greater access to natural gas, crude oil and NGL supplies than we do or other synergies with existing or new
customers that we cannot provide. Our competitors may also include our joint venture partners, who in some
cases are permitted to compete with us and may have a competitive advantage due to their familiarity with our
business arising from our joint venture arrangements, as well as third parties on whom we rely to deliver natural
gas, NGLs, crude oil and refined products to our facilities, who may have a competitive advantage due to their
ability to modify the flow of natural gas, NGLs, crude oil and refined products on their systems away from our
facilities. Additionally, our customers that gather gas through facilities that are not otherwise dedicated to us may
develop their own processing and fractionation facilities in lieu of using our services.
As a consequence of the increase in competition in the industry, and the volatility of natural gas prices, end-users
and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from
more than one natural gas company and have the ability to change providers at any time. Some of these end-users
also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the
market. Because there are numerous companies of greatly varying size and financial capacity that compete with
us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis
of price. The inability of our management to renew or replace our current contracts as they expire and to respond
appropriately to changing market conditions could affect our profitability.
The fees charged to third parties under our gathering, processing, transmission, transportation, fractionation,
stabilization and storage agreements may not escalate sufficiently to cover increases in costs, or the
agreements may not be renewed or may be suspended in some circumstances.
Our costs may increase at a rate greater than the fees we charge to third parties. Furthermore, third parties may
not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us
may be permanently or temporarily reduced due to certain events, some of which are beyond our control,
including force majeure events wherein the supply of natural gas, NGLs, crude oil or refined products are
curtailed or cut-off due to events outside our control, and in some cases, certain of those agreements may be
terminated in their entirety if the duration of such events exceeds a specified period of time. If the escalation of
fees is insufficient to cover increased costs, or if third parties do not renew or extend their contracts with us, or if
third parties suspend or terminate their contracts with us, our financial results would suffer.
We are exposed to the credit risks of our key customers and derivative counterparties, and any material
non-payment or non-performance by our key customers or derivative counterparties could reduce our ability
to make distributions to our unitholders.
We are subject to risks of loss resulting from non-payment or non-performance by our customers, which risks
may increase during periods of economic uncertainty. Furthermore, some of our customers may be highly
leveraged and subject to their own operating and regulatory risks, which increases the risk that they may
default on their obligations to us. This risk is further heightened during sustained periods of declines of natural
36
gas, NGL and oil prices. With respect to our producer customers who have made acreage dedications to us, we
may be exposed to additional risks to the extent that those customers become bankrupt and the acreage
dedications are challenged and not upheld in bankruptcy. In addition, our risk management activities are
subject to the risks that a counterparty may not perform its obligation under the applicable derivative
instrument, the terms of the derivative instruments are imperfect, and our risk management policies and
procedures are not properly followed. Any such material non-payment or non-performance could reduce our
ability to make distributions to our unitholders.
We are indemnified for certain environmental liabilities arising from properties on which certain of our
facilities are located and our results of operations and our ability to make distributions to our unitholders
could be adversely affected if an indemnifying party fails to perform its indemnification obligations.
Prior third-party owners or operators of certain of our facilities, or such parties’ successors-in-interest, have in
certain circumstances agreed to retain full or partial liability and responsibility for, or to indemnify us against,
any environmental liabilities associated with these facilities to the extent such liabilities arose prior to the
effective date of the agreements pursuant to which such properties were acquired or leased and to the extent not
contributed to by us. Our results of operations and our ability to make cash distributions to our unitholders could
be adversely affected if in the future any of these third parties fail to perform their indemnification obligations. In
addition, from time to time, we have acquired, and may acquire in the future, facilities from third parties which
previously have been or currently are the subject of investigatory, remedial or monitoring activities relating to
environmental matters. In some cases, we may receive indemnification from the prior owner or operator for some
or all of such liabilities, and in other cases we may accept some or all of such liabilities. There is no assurance
that any such third parties will perform any such indemnification obligations, or that the obligations and
liabilities that we may accept in connection with any such acquisition will not be larger than anticipated, and in
such event, our results of operations and cash available for distribution could be adversely affected.
Our operations could be disrupted if we are unable to maintain or obtain real property rights required for our
business.
We do not own all of the land on which our assets are located, but rather obtain the rights to construct and
operate such assets on land owned by third parties and governmental agencies for a specific period of time.
Therefore, we are subject to the possibility of more burdensome terms and increased costs to retain necessary
land use if our leases, rights-of-way or other property rights lapse, terminate or are reduced or it is determined
that we do not have valid leases, rights-of-way or other property rights. Any loss of or reduction in these rights,
including loss or reduction due to legal, governmental or other actions or difficulty renewing leases, right-of-way
agreements or permits on satisfactory terms or at all, could have a material adverse effect on our business, results
of operations, financial condition and ability to make cash distributions to our unitholders.
Certain of our facilities are located on Native American tribal lands and are subject to various federal and
tribal approvals and regulations, which may increase our costs and delay or prevent our efforts to conduct
planned operations.
Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs,
Bureau of Land Management, and the Office of Natural Resources Revenue, along with each Native American
tribe, regulate natural gas and oil operations on Native American tribal lands, including drilling and production
requirements and environmental standards. In addition, each Native American tribe is a sovereign nation having
the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes
and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native
American tribal members and other conditions that apply to operators and contractors conducting operations on
Native American tribal lands. Persons conducting operations on tribal lands are generally subject to the Native
American tribal court system. In addition, if our relationships with any of the relevant Native American tribes
were to deteriorate, we could face significant risks to our ability to continue operations on Native American tribal
lands. One or more of these factors may increase our cost of doing business on Native American tribal lands and
impact the viability of, or prevent or delay our ability to conduct our operations on such lands.
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Many of our assets have been in service for many years and, as a result, our maintenance or repair costs may
increase in the future.
Our pipelines, terminals, fractionator and storage assets are generally long-lived assets, and many of them have
been in service for many years. The age and condition of our assets could result in increased maintenance or
repair expenditures in the future. Any significant increase in these expenditures could adversely affect our results
of operations, financial position or cash flows, as well as our ability to make cash distributions to our unitholders.
We do not insure against all potential losses, and, therefore, our business, financial condition, results of
operations and cash flows could be adversely affected by unexpected liabilities and increased costs.
We maintain insurance coverage in amounts we believe to be prudent against many, but not all, potential
liabilities arising from operating hazards. Uninsured liabilities arising from operating hazards, including but not
limited to, explosions, fires, pipeline releases, cybersecurity breaches or other incidents involving our assets or
operations, could reduce the funds available to us for capital and investment spending and could have a material
adverse effect on our business, financial condition, results of operations and cash flows. Historically, we also
have maintained insurance coverage for physical damage and resulting business interruption to our major
facilities, with significant self-insured retentions. In the future, we may not be able to maintain insurance of the
types and amounts we desire at reasonable rates.
If foreign investment in us or our general partner exceeds certain levels, we could be prohibited from
operating inland river vessels, which could materially and adversely affect our business, financial condition,
results of operations and cash flows.
The Shipping Act of 1916 and Merchant Marine Act of 1920 (collectively, the “Maritime Laws”), generally
require that vessels engaged in U.S. coastwise trade be owned by U.S. citizens. Among other requirements to
establish citizenship, entities that own such vessels must be owned at least 75 percent by U.S. citizens. If we fail
to maintain compliance with the Maritime Laws, we would be prohibited from operating vessels in the U.S.
inland waters. Such a prohibition could materially and adversely affect our business, financial condition, results
of operations and cash flows.
Risks Relating to Strategic Transactions
MPC’s ongoing review of strategic alternatives for its midstream business could materially impact our
strategic direction, business and results of operations.
MPC’s board of directors has formed a special committee to evaluate strategies to enhance shareholder value
through a review of its Midstream business, of which MPLX is the primary component. MPC’s exploration of
strategic alternatives, including any uncertainty created by this process, involves a number of risks: significant
fluctuations in our unit price could occur in response to developments or actions relating to the strategic
review process or market speculation regarding any such developments or actions; we may encounter difficulties
in hiring, retaining and motivating key personnel who provide services to us during this process or as a result of
uncertainties generated by this process or any developments or actions relating to it; we may incur substantial
increases in general and administrative expense associated with increased legal fees and the need to retain and
compensate third-party advisors; and we may experience difficulties in preserving the commercially sensitive
information that may need to be disclosed to third parties during this process or in connection with an assessment
of our strategic alternatives. The strategic review process also requires significant time and attention from
management, which could distract them from other tasks in operating our business. There can be no assurance
that this process will result in the pursuit or consummation of any strategic transaction. The occurrence of any
one or more of the above risks could have a material adverse impact on our business, financial condition, results
of operations and cash flows.
The Merger may not be accretive, and may be dilutive, to our earnings per unit, which may negatively affect
the market price of our common units.
In connection with the completion of the Merger, we issued approximately 263 million common units. Any
dilution of, or delay of any accretion to, our earnings per unit could cause the price of our common units to
decline or increase at a reduced rate.
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We have incurred and will continue to incur significant transaction and Merger-related costs in connection
with the Merger, which may be in excess of those anticipated by us.
We have incurred substantial expenses in connection with the Merger. We expect to continue to incur transaction
fees and costs related to formulating and implementing integration plans, including facilities and systems
consolidation costs. These fees and costs have been, and may continue to be, substantial.
Additional unanticipated costs may be incurred in the integration of the two partnerships’ businesses. The
elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the
businesses, may not be sufficient to allow us to offset integration-related costs over time. These integration costs,
as well as other unanticipated costs and expenses, could have a material adverse effect on our financial condition
and operating results.
We may fail to realize all of the anticipated benefits of the Merger.
The success of the Merger depends, in part, on our ability to realize the anticipated benefits and cost savings
from combining MPLX’s and ANDX’s businesses. The anticipated benefits and cost savings of the Merger may
not be realized fully or at all, or may take longer to realize than expected or could have other adverse effects that
we do not currently foresee. Some of the assumptions that we have made, such as the achievement of operating
synergies and the expansion in opportunities for logistics growth in crude oil production basins and regions, may
not be realized. The integration process may result in the loss of key personnel who provide services to the two
partnerships, the disruption of ongoing businesses or inconsistencies in standards, controls, procedures and
policies. There could be potential unknown liabilities and unforeseen expenses associated with the Merger that
were not discovered in the course of performing due diligence.
The combined partnership recorded goodwill and other intangible assets that could become impaired and
result in material non-cash charges to the results of operations of the combined partnership in the future.
The Merger was accounted for as a reorganization of entities under common control in accordance with
accounting principles generally accepted in the United States. Under a reorganization of entities under common
control, the assets and liabilities of ANDX transferred between entities under common control were recorded by
MPLX based on MPC’s historical cost basis resulting from its preliminary purchase price accounting. We
recorded ANDX’s assets and liabilities at MPC’s basis as of October 1, 2018, the date that common control was
first established.
Effective October 1, 2018, MPC acquired Andeavor, including a controlling interest in ANDX, thus establishing
common control between MPLX, ANDX and their respective general partners. Under MPC’s application of the
acquisition method of accounting, a portion of the total purchase price was allocated to ANDX’s tangible assets
and liabilities and identifiable intangible assets based on their fair values as of October 1, 2018. The excess of the
allocated purchase price over those fair values was recorded as goodwill. MPC’s basis in ANDX’s tangible
assets, liabilities, identifiable intangible assets and goodwill was transferred to MPLX upon completion of the
Merger. As a result of our annual impairment review for goodwill, we determined that a portion of the goodwill
that resulted from the Merger was impaired. The remaining goodwill and intangible assets could become
impaired in the future and result in additional, material non-cash charges to our future results of operations. The
combined partnership’s operating results may be significantly impacted from both the impairment and the
underlying trends in the business that triggered the impairment.
If we are unable to make strategic acquisitions on economically acceptable terms from MPC or third parties,
our ability to implement our business strategy may be impaired.
In addition to organic growth, a component of our business strategy can include the expansion of our operations
through strategic acquisitions. If we are unable to make accretive strategic acquisitions from MPC or third parties
that increase the cash generated from operations per unit, whether due to an inability to identify attractive
acquisition candidates, to negotiate acceptable purchase contracts, or to obtain financing for these acquisitions on
economically acceptable terms, then our ability to successfully implement our business strategy may be impaired.
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Significant acquisitions in the future will involve the integration of new assets or businesses and present
substantial risks that could adversely affect our business, financial conditions, results of operations and cash flows.
Significant future transactions involving the addition of new assets or businesses will present potential risks,
which may include, among others:
•
•
•
•
•
•
•
inaccurate assumptions about future synergies, revenues, capital expenditures and operating costs;
an inability to successfully integrate, or a delay in the successful integration of, assets or businesses we
acquire;
a decrease in our liquidity resulting from using a portion of our available cash or borrowing capacity
under our revolving credit agreement to finance transactions;
a significant increase in our interest expense or financial leverage if we incur additional debt to finance
transactions;
the assumption of unknown environmental and other liabilities, losses or costs for which we are not
indemnified or for which our indemnity is inadequate;
the diversion of management’s attention from other business concerns;
the loss of customers or key employees from the acquired businesses; and
the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset
devaluation or restructuring charges.
Risks Relating to our Industry
Certain of our pipelines may be subject to federal or state rate and service regulation, and the imposition and
cost of compliance with such regulation could adversely affect our operations and cash flows available for
distribution to our unitholders.
Some of our natural gas, crude oil, NGL, and refined product pipelines are, or may in the future be, subject to
siting, public necessity or service regulations by FERC or various state or other regulatory bodies, depending
upon jurisdiction. FERC generally regulates the transportation of natural gas, NGLs, crude oil and refined
products in interstate commerce and FERC’s regulatory authority includes: facilities construction, acquisition,
extension or abandonment of services or facilities (for natural gas pipelines only); rates; operations; accounts and
records; and depreciation and amortization policies. FERC’s action in any of these areas or modifications of its
current regulations can adversely impact our ability to compete for business, the costs we incur in our operations,
the construction of new facilities or our ability to recover the full cost of operating our pipelines. FERC also may
conduct audits of these facilities, and if FERC determines that we are not in compliance with our tariff or
applicable regulations, we may incur additional costs, expenses or penalties. For certain natural gas, NGL, crude
oil and refined product common carrier pipelines, we have FERC tariffs on file and we may have additional
pipelines in the future that may be subject to these requirements. We also own and are constructing pipelines,
including pipelines that carry NGLs between our processing and fractionation facilities, that we believe are either
not subject to FERC’s jurisdiction or would otherwise meet the qualifications for a waiver from many or all of
FERC’s requirements. However, we cannot provide assurance that FERC will not at some point find that some or
all of these pipelines are subject to FERC’s requirements or are otherwise not exempt from certain requirements.
Such a finding could subject us to potentially burdensome and expensive operational, reporting and other
requirements as well as fines, penalties or other sanctions.
Pipelines and operations not subject to regulation by FERC may still be subject to regulation by various state
agencies. The applicable statutes and regulations generally require that our rates and terms and conditions of
service provide no more than a fair return on the aggregate value of the facilities used to render services and that
we offer service to our shippers on a not unduly discriminatory basis. FERC rate cases can involve complex and
expensive proceedings. For more information regarding regulatory matters that could affect our business, please
read Item 1. Business – Regulatory Matters as set forth in this Annual Report on Form 10-K.
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Some of our natural gas, NGL, crude oil and refined product pipelines are subject to FERC’s rate-making
policies that could have an adverse impact on our ability to establish rates that would allow us to recover the
full cost of operating our pipelines including a reasonable return.
A number of our pipelines provide interstate service that is subject to regulation by FERC. FERC prescribes rate
methodologies for developing regulated tariff rates for these natural gas, interstate oil and products pipelines.
FERC’s regulated tariff may not allow us to recover all of our costs of providing services. Changes in FERC’s
approved rate methodologies, or challenges to our application of an approved methodology, could also adversely
affect our rates. Additionally, shippers may protest (and FERC may investigate) the lawfulness of tariff rates.
FERC can require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful and
prescribe new rates prospectively.
Action by FERC could adversely affect our ability to establish reasonable rates that cover operating costs and
allow for a reasonable return. An adverse determination in any future rate proceeding brought by or against us
could have a material adverse effect on our business, financial condition and results of operations.
Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for
acquisitions or other purposes and our ability to make distributions at our intended levels.
Certain of our senior notes, our revolving credit facility and our loan agreement with MPC Investment LLC
(“MPC Investment”) have variable interest rates. As a result, future interest rates on our debt could be higher
than current levels, causing our financing costs to increase accordingly. In addition, we may in the future
refinance outstanding borrowings under our revolving credit facility with fixed-rate indebtedness. Interest rates
payable on fixed-rate indebtedness typically are higher than the short-term variable interest rates that we pay on
borrowings under our revolving credit facility. We also have other fixed-rate indebtedness that we may need or
desire to refinance in the future prior to the applicable stated maturity.
As with other yield-oriented securities, our unit price will be impacted by our cash distributions and the implied
distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities
for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may
affect the yield requirements of investors who invest in our units, and a rising interest rate environment could
have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other
purposes and to make distributions at our intended levels.
Uncertainty relating to the calculation of LIBOR, and other reference rates and their potential discontinuance
may adversely affect interest expense related to our outstanding debt.
National and international regulators and law enforcement agencies have conducted investigations into a number
of rates or indices, which are deemed to be “reference rates.” Actions by such regulators and law enforcement
agencies may result in changes to the manner in which certain reference rates are determined, their
discontinuance, or the establishment of alternative reference rates. In particular, it appears highly likely that
LIBOR will be discontinued or modified by the end of 2021.
At this time, it is not possible to predict the effect that these developments, any discontinuance, modification or
other reforms to LIBOR or any other reference rate, or the establishment of alternative reference rates may, have
on LIBOR, other benchmarks or floating rate indebtedness. Uncertainty as to the nature of such potential
discontinuance, modification, alternative reference rates or other reforms may materially adversely affect the
trading market for securities linked to such benchmarks. Furthermore, the use of alternative reference rates or
other reforms could cause the market value of, the applicable interest rate on and the amount of interest paid on
our floating rate indebtedness to be materially different than expected and could materially adversely impact our
ability to refinance such floating rate indebtedness or raise future indebtedness on a cost effective basis.
Meeting the requirements of evolving environmental or other laws or regulations may result in substantial
capital expenditures and operating costs that could materially and adversely affect our business, financial
condition, results of operations and cash flows.
Various laws and regulations are expected to impose increasingly stringent and costly requirements on our
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operations, which may reduce our cash available for distribution. Laws and regulations expected to become more
stringent relate to the following:
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the emission or discharge of materials into the environment,
solid and hazardous waste management,
the regulatory classification of materials presently used in our business,
pollution prevention,
greenhouse gas emissions,
climate change,
public and employee safety and health,
inherently safer technology, and
facility security.
The specific impact of laws and regulations on us and our competitors may vary depending on a number of
factors, including the age and location of operating facilities and production processes. As a result of these laws
and regulations, we have incurred and will continue to incur substantial capital, operating and maintenance, and
remediation expenditures to modify operations, install pollution control equipment, perform site cleanups or
curtail operations. Such expenditures could materially and adversely affect our business, financial condition,
results of operations and cash flows.
Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could delay or
impede producer’s gas production or result in reduced volumes available for our midstream assets to gather,
process and fractionate. While we do not conduct hydraulic fracturing operations, we do provide gathering,
processing and fractionation services with respect to natural gas and natural gas liquids produced by our
customers as a result of such operations. If federal, state or local laws or regulations that significantly restrict
hydraulic fracturing are adopted, such legal requirements could make it more difficult to complete natural gas
wells in shale formations and increase producers’ costs of compliance.
For more information regarding the environmental, safety and other regulatory matters that could affect our
business, please read Item 1. Business - Regulatory Matters and Item 1. Business - Environmental Regulation,
each as set forth in this Annual Report on Form 10-K.
Climate change and greenhouse gas emission regulation could affect our operations, energy consumption
patterns and regulatory obligations, any of which could affect our results of operations and financial condition.
Currently, multiple legislative and regulatory measures to address greenhouse gas (including carbon dioxide,
methane and nitrous oxides) and other emissions are in various phases of consideration, promulgation or
implementation. These include actions to develop international, federal, regional or statewide programs, which
could require reductions in our greenhouse gas or other emissions, establish a carbon tax and decrease the
demand for refined products. Requiring reductions in these emissions could result in increased costs to (i) operate
and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any
emissions programs, including acquiring emission credits or allotments.
Regional and state climate change and air emissions goals and regulatory programs are complex, subject to
change and considerable uncertainty due to a number of factors including technological feasibility, legal
challenges and potential changes in federal policy. Increasing concerns about climate change and carbon
intensity have also resulted in societal concerns and a number of international and national measures to limit
greenhouse gas emissions. Additional stricter measures and investor pressure can be expected in the future and
any of these changes may have a material adverse impact on our business or financial condition.
International climate change-related efforts, such as the 2015 United Nations Conference on Climate Change,
which led to the creation of the Paris Agreement, may impact the regulatory framework of states whose policies
directly influence our present and future operations. Though the United States has announced its intention to
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withdraw from the Paris Agreement, U.S. climate change strategy and implementation of that strategy through
legislation and regulation may change under future administrations; therefore, the impact to our industry and
operations due to greenhouse gas regulation is unknown at this time.
For more information regarding greenhouse gas and methane emission and regulation, please read Item 1.
Business - Environmental Regulation - Climate Change.
Severe weather events may adversely affect our facilities and ongoing operations.
We have mature systems in place to manage potential acute physical risks, such as floods, hurricane-force winds,
wildfires and snowstorms, and potential chronic physical risks, such as higher ocean levels. If any such events
were to occur, they could have an adverse effect on our assets and operations. Specifically, where appropriate, we
are hardening and modernizing assets against flood and wind damage and ensuring we have resiliency measures
in place, such as storm-specific readiness plans. We have incurred and will continue to incur additional costs to
protect our assets and operations from such physical risks and employ the evolving technologies and processes
available to mitigate such risks. To the extent such severe weather events increase in frequency and severity, we
may be required to modify operations and incur costs that could materially and adversely affect our business,
financial condition, results of operations and cash flows.
We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and
related repairs, and the expansion of pipeline safety laws and regulations could require us to use more
comprehensive and stringent safety controls and subject us to increased capital and operating costs.
The DOT through the PHMSA has adopted regulations requiring pipeline operators to develop integrity
management programs for gas transmission and hazardous liquids pipelines located where a leak or rupture could
do the most harm. The regulations require the following of operators of covered pipelines to:
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perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence
area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.
Over the past several years, PHMSA has published new regulations, and issued notices for additional proposed
regulations, to expand pipeline safety requirements.
In addition, PHMSA and other state regulators have recently expanded the scope of their regulatory inspections
to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated
storage facilities to assess compliance with hazardous liquids pipeline safety requirements, which actions by
PHMSA are currently subject to judicial and administrative challenges by one or more midstream operators. The
adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards to
gas, NGL, crude oil and refined product lines or other facilities, or the expansion of regulatory inspections by
PHMSA and other state regulators described above, could require us to install new or modified safety controls,
pursue added capital projects, make modifications or operational changes, or conduct maintenance programs on
an accelerated basis, all of which could require us to incur increased capital and operational costs or operational
delays that could be significant and have a material adverse effect on our financial position or results of
operations and ability to make distributions to our unitholders.
Some states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and
transmission lines. These regulations have raised operating costs for the industry, and compliance with such laws
and regulations may cause us to incur potentially material capital expenditures associated with the construction,
maintenance, and upgrading of equipment and facilities.
The United States inland waterway infrastructure is aging and planned and unplanned maintenance may
adversely affect our operations.
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Maintenance of the United States inland waterway system is vital to our marine transportation operations. The
system is composed of over 12,000 miles of commercially navigable waterway, supported by approximately 240
locks and dams designed to provide flood control, maintain pool levels of water in certain areas of the country
and facilitate navigation on the inland river system. The United States inland waterway infrastructure is aging,
with more than half of the locks over 50 years old. As a result, due to the age of the locks, planned and unplanned
maintenance may create more frequent outages, resulting in delays and additional operating expenses. Part of the
costs for new construction and major rehabilitation of locks and dams is funded by marine transportation
companies through taxes and the other portion is funded by general federal tax revenues. Failure of the federal
government to adequately fund infrastructure maintenance and improvements in the future would have a negative
impact on our ability to deliver products to our customers on a timely basis. Furthermore, any additional user
taxes that may be imposed in the future to fund infrastructure improvements would increase our operating
expenses.
Interruptions in operations at any of our facilities or those of our customers, including MPC’s refining
operations, may adversely affect our operations and cash flows available for distribution to our unitholders.
Our operations depend upon the infrastructure that we have developed, including processing and fractionation
plants, storage facilities, gathering and transportation facilities, an export terminal, various other means of
transportation and marketing services. Any significant interruption at these facilities or pipelines, or our
customers’ operations, including MPC’s refining operations, or in our ability to gather, transport or store natural
gas, NGLs, crude oil or other refined products to or from these facilities or pipelines for any reason, or to market
or transport the natural gas, crude oil, NGLs or refined products, would adversely affect our operations and cash
flows available for distribution to our unitholders. In some cases, these events may also adversely affect the
pricing received for NGLs, and may reduce the volumes of oil, gas, NGLs and refined products that we receive.
Operations at our or our customers’ facilities, including MPC’s refineries, could be partially or completely shut
down, temporarily or permanently, as the result of circumstances not within our control, such as:
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unscheduled turnarounds or catastrophic events, including damages to pipelines and facilities, related
equipment and surrounding properties caused by earthquakes, tornadoes, hurricanes, floods, fires, severe
weather, explosions and other natural disasters;
restrictions imposed by governmental authorities or court proceedings;
labor difficulties that result in a work stoppage or slowdown;
a disruption in the supply of natural gas, NGLs, crude oil or refined products to our pipelines, barges,
processing and fractionation plants and associated facilities;
disruption in our supply of power, water and other resources necessary to operate our facilities;
a marine accident or spill event could close a portion of the inland waterway system;
damage to our facilities resulting from gas, crude oil, NGLs or refined products that do not comply with
applicable specifications; and
inadequate fractionation, transportation or storage capacity or market access to support production
volumes, including lack of availability of rail cars, barges, trucks and pipeline capacity, or market
constraints, including reduced demand or limited markets for certain NGL products.
Our NGL fractionation, storage and marketing operations in the Marcellus and Utica regions are integrated, and
as a result, it is possible that an interruption of these operations may impact operations in the other regions,
which may exacerbate the impacts of such interruption.
The construction and operation of certain of our facilities in our G&P segment may be impacted by surface or
subsurface mining operations by one or more third parties, which could adversely impact our construction
activities or cause subsidence or other damage to our facilities. In such event, our construction may be prevented
or delayed, or the costs and time increased, or our operations at such facilities may be impaired or interrupted,
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and we may not be able to recover the costs incurred for delays or to relocate or repair our facilities, from such
third parties.
In addition, our marine transportation business is subject to weather conditions on a daily basis. Adverse weather
conditions such as high or low water on the inland waterway systems, fog and ice, tropical storms, hurricanes and
tsunamis on both the inland waterway systems and throughout the United States coastal waters can impair the
operating efficiencies of the marine fleet. Such adverse weather conditions can cause a delay, diversion or
postponement of shipments of products and are beyond our control. In addition, adverse water and weather
conditions can negatively affect a towing vessel’s performance, tow size, loading drafts, fleet efficiency, place
limitations on night passages and dictate horsepower requirements.
We rely on the performance of our information technology systems, and the interruption or failure of any
information technology system, including an interruption or failure due to a cybersecurity breach, could have
an adverse effect on our business, financial condition, results of operations and cash flows.
We are heavily dependent on our information technology systems, including our network infrastructure and cloud
applications, for the safe and effective operation of our business. We rely on such systems to process, transmit
and store electronic information, including financial records and personally identifiable information such as
contractor, customer and investor data, and to manage or support a variety of business processes, including our
pipeline operations, gathering and processing operations, financial transactions, banking and numerous other
processes and transactions. Our systems and infrastructure are subject to damage or interruption from a number
of potential sources including natural disasters, malware, power failures, cyber-attacks and other events. We also
face various other cybersecurity threats from criminal hackers, state-sponsored intrusion, industrial espionage
and contractor malfeasance, including threats to gain unauthorized access to sensitive information or to render
data or systems unusable.
Certain vendors have access to sensitive information, including personally identifiable investor and contractor
data and a breakdown of their technology systems or infrastructure as a result of a cyber-attack or otherwise
could result in unauthorized disclosure of such information.
Our cybersecurity protections, infrastructure protection technologies, disaster recovery plans and employee
training may not be sufficient to defend us against all unauthorized attempts to access our information. We have
been and may in the future be subject to attempts to gain unauthorized access to our computer network and
systems. To date, prior events have not had a material adverse effect on us.
Any cybersecurity incident could result in theft, destruction, loss, misappropriation or release of confidential
financial and other data or intellectual property; give rise to remediation or other expense; expose us to liability
under federal and state laws; reduce our customers’ willingness to do business with us; disrupt the services we
provide to customers; and subject us to litigation and legal liability under federal and state laws. Any of such
results could have an adverse effect on our reputation, business, financial condition, results of operations and
cash flows available for distribution to our unitholders.
Terrorist attacks aimed at our facilities or that impact our customers or the markets we serve could adversely
affect our business.
The U.S. government has issued warnings that energy assets in general, including the nation’s refining, pipeline
and terminal infrastructure, may be future targets of terrorist organizations. The threat of terrorist attacks has
subjected our operations to increased risks. Any future terrorist attack on our facilities, those of our customers
and, in some cases, those of other pipelines, could have a material adverse effect on our business. Similarly, any
future terrorist attacks that severely disrupt the markets we serve could materially and adversely affect our results
of operations, financial position and cash flows.
Risks Relating to the Business and Operations of MPC
MPC accounted for a large portion of our revenues in 2019 and will continue to do so on a go-forward
basis. If MPC changes its business strategy, is unable to satisfy its obligations to us or significantly
reduces the volumes transported through our facilities or stored at our storage assets, our revenues would
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decline and our financial condition, results of operations, cash flows, and ability to make distributions to our
unitholders would be materially and adversely affected.
For the year ended December 31, 2019, excluding revenues attributable to volumes shipped by MPC under joint
tariffs with third parties that were treated as third-party revenues for accounting purposes, MPC accounted for
approximately 56 percent of our operating revenues, including 91 percent of the operating revenues within our
L&S segment, and we believe MPC will continue to account for a large portion of our revenues on a go forward
basis. As we expect to continue to derive a portion of our revenues from MPC for the foreseeable future, any
event that materially and adversely affects MPC’s financial condition, results of operations or cash flows may
adversely affect our ability to sustain or increase distributions to our unitholders. Accordingly, we are indirectly
subject to the operational and business decisions and risks of MPC, which include the following:
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the timing and extent of changes in commodity prices and demand for MPC’s products, and the
availability and costs of crude oil and other refinery feedstocks;
a material decrease in the refining margins at MPC’s refineries;
disruptions due to equipment interruption or failure at MPC’s facilities or at third-party facilities on
which MPC’s business is dependent;
any decision by MPC to temporarily or permanently alter, curtail or shut down operations at one or more
of its refineries or other facilities and reduce or terminate its obligations under our transportation and
storage or refining logistics and fuels distribution agreements;
changes to the routing of volumes shipped by MPC on our crude oil and refined product pipelines or the
ability of MPC to utilize third-party pipeline connections to access our pipelines;
• MPC’s ability to remain in compliance with the terms of its outstanding indebtedness;
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changes in the cost or availability of third-party pipelines, railways, vessels, terminals and other means of
delivering and transporting crude oil, feedstocks, refined products and other hydrocarbon-based products;
state and federal environmental, economic, health and safety, energy and other policies and regulations,
and any changes in those policies and regulations;
environmental incidents and violations and related remediation costs, fines and other liabilities;
operational hazards and other incidents at MPC’s refineries and other facilities, such as explosions and
fires, that result in temporary or permanent shut downs of those refineries and facilities;
changes in crude oil and refined product inventory levels and carrying costs; and
disruptions due to hurricanes, tornadoes or other forces of nature.
We have no control over MPC’s business decisions and operations, and MPC may elect to pursue a business
strategy that does not favor us and our business. In addition, significant stockholders of MPC may attempt to
effect changes at MPC or acquire control of the company, which could impact the pursuit of MPC’s business
strategies. Campaigns by stockholders to effect changes at publicly traded companies are sometimes led by
investors seeking to increase short-term stockholder value through actions such as financial restructuring,
increased debt, special dividends, stock repurchases or sales of assets or the entire company. As a result,
stockholder campaigns at MPC could directly or indirectly adversely affect our results of operations and financial
condition and our ability to sustain or increase distributions to our unitholders.
MPC may suspend, reduce or terminate its obligations under its agreements with us in some circumstances,
which would have a material adverse effect on our financial condition, results of operations, cash flows and
ability to make distributions to our unitholders.
Certain of our transportation, terminal, fuels distribution, marketing and storage services agreements with MPC
include provisions that permit MPC to suspend, reduce or terminate its obligations under the applicable
agreement if certain events occur. These events include a material breach of the applicable agreement by us,
MPC being prevented from transporting its full minimum volume commitment because of capacity constraints
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on our pipelines, certain force majeure events that would prevent us from performing some or all of the required
services under the applicable agreement and MPC’s determination to suspend refining operations at one of its
refineries. MPC has the discretion to make such decisions notwithstanding the fact that they may significantly
and adversely affect us. These actions could result in a suspension, reduction or termination of MPC’s
obligations under one or more transportation and storage services agreements.
Any such reduction, suspension or termination of MPC’s obligations would have a material adverse effect on our
financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
If MPC satisfies only its minimum obligations under, or if we are unable to renew or extend, the
transportation, terminal, fuels distribution, marketing and storage services agreements we have with MPC, or
if MPC elects to use credits upon the expiration or termination of an agreement, our cash available for
distribution will be materially and adversely affected.
MPC is not obligated to use our services with respect to volumes of crude oil or refined products in excess of the
minimum volume commitments under the transportation services agreements with us. Our cash available for
distribution will be materially and adversely affected to the extent that we do not transport volumes in excess of
the minimum volume commitments under our transportation services agreements or if MPC’s obligations under
our transportation, terminal, fuels distribution, marketing and storage services agreements are suspended, reduced
or terminated. If MPC fails to use our assets and services after expiration of those agreements and we are unable
to generate additional revenues from third parties, our ability to make distributions to unitholders may be
materially and adversely affected.
In addition, under our transportation services agreements, MPC must pay us a deficiency payment if it fails to
transport its minimum throughput commitment. MPC may then apply the amount of any such deficiency
payments as a credit for volumes transported on the applicable pipeline in excess of its minimum volume
commitment during a specified period under the terms of the applicable transportation services agreement. Upon
the expiration or termination of a transportation services agreement, MPC may use any remaining credits against
any volumes shipped by MPC on the applicable pipeline for the specified period, as applicable, without regard to
any minimum volume commitment that may have been in place during the term of the agreement. If that were to
occur, we would not receive any cash payments for volumes shipped on the applicable pipeline until any such
remaining credits were fully used or until the expiration of the specified period.
MPC’s level of indebtedness, the terms of its borrowings and its credit ratings could adversely affect our
ability to grow our business and our ability to make distributions to our unitholders. Our ability to obtain
credit in the future may also be adversely affected by MPC’s credit rating.
MPC must devote a portion of its cash flows from operating activities to service its indebtedness, and therefore,
cash flows may not be available for use in pursuing its growth strategy. Furthermore, a higher level of
indebtedness at MPC in the future increases the risk that it may default on its obligations to us under our
transportation and storage services agreements. As of December 31, 2019, MPC had consolidated long-term
indebtedness of approximately $28 billion, of which $8 billion was a direct obligation of MPC. The covenants
contained in the agreements governing MPC’s outstanding and future indebtedness may limit its ability to
borrow additional funds for development and make certain investments and may directly or indirectly impact our
operations in a similar manner.
Furthermore, if MPC were to default under certain of its debt obligations, there is a risk that MPC’s creditors
would attempt to assert claims against our assets during the litigation of their claims against MPC. The defense
of any such claims could be costly and could materially impact our financial condition, even absent any adverse
determination. If these claims were successful, our ability to meet our obligations to our creditors, make
distributions and finance our operations could be materially and adversely affected.
On November 1, 2019, Moody’s announced it had changed its outlook for MPC’s and MPLX’s credit ratings
from stable to negative following the recent announcements regarding MPC’s planned spinoff of its
Speedway business and its midstream review, and these developments could cause or contribute to a future
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determination by one or more of the rating agencies to lower MPLX’s credit ratings. If these ratings are lowered
in the future, the interest rate and fees MPC pays on its credit facilities may increase. Credit rating agencies will
likely consider MPC’s debt ratings when assigning ours because of MPC’s ownership interest in us, the
significant commercial relationships between MPC and us, and our reliance on MPC for a portion of our
revenues. If one or more credit rating agencies were to downgrade the outstanding indebtedness of us or MPC,
we could experience an increase in our borrowing costs or difficulty accessing the capital markets. Such a
development could adversely affect our ability to grow our business and to make distributions to our unitholders.
Risks Relating to Tax Matters
Our tax treatment depends on our status as a partnership for federal income tax purposes as well as our not
being subject to a material amount of entity level taxation by individual states. If the IRS were to treat us as a
corporation for federal income tax purposes, or we become subject to a material amount of entity level
taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to
our unitholders.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being
treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a
ruling from the IRS on this.
A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it
satisfies a “qualifying income” requirement. Based on our current operations, we believe that we are treated as a
partnership rather than as a corporation for such purposes; however, a change in our business or a change in
current law could cause us to be treated as a corporation for federal income tax purposes. We have requested and
received a favorable ruling from the IRS on the treatment of a portion of our “qualifying income.” The IRS may
adopt positions that differ from the ones we take. A successful IRS contest of the federal income tax positions we
take may adversely impact the market for our common units, and the costs of any IRS contest will reduce our
cash available for distribution to unitholders.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our
taxable income at the corporate tax rate, which is currently a maximum of 21 percent, and likely would pay state
and local income tax at varying rates. Distributions to unitholders generally would be taxed again as corporate
dividends, and no income, gains, losses, deductions, or credits would flow through to our unitholders. Treatment
of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our
unitholders, likely causing a substantial reduction in the value of our common units. Changes in current state or
local law may subject us to additional entity-level taxation by individual states and localities. Imposition of any
such additional taxes on us may substantially reduce the cash available for distribution to unitholders.
Our Partnership Agreement provides that, if a law is enacted or an existing law is modified or interpreted in a
manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal,
state or local income tax purposes, the minimum quarterly distribution amount and the target distribution
amounts may be adjusted to reflect the impact of that law on us.
If the IRS contests the federal income tax positions we take, the market for our common units may be
adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.
The IRS has made no determination as to our status as a partnership for federal income tax purposes. The IRS
may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court
proceedings to sustain some or all the positions we take. A court may not agree with some or all of the positions
we take. Any contest with the IRS may materially and adversely impact the market for our common units and the
price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our
unitholders and our general partner because the costs will reduce our cash available for distribution.
Our unitholders will be required to pay taxes on their share of income even if they do not receive any
distributions from us.
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Because our unitholders will be treated as partners to whom we will allocate taxable income that could be
different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes
and, in some cases, state and local income taxes on their share of our taxable income even if they receive no
distributions from us. Our unitholders may not receive distributions from us equal to their share of our taxable
income or even equal to the actual tax liability that result from that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell their common units, they will recognize gain or loss equal to the difference between the
amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s
allocable share of our net taxable income decrease the unitholder’s tax basis in their common units, the amount,
if any, of such prior excess distributions with respect to their units will, in effect, become taxable income to the
unitholder if the common units are sold at a price greater than the unitholder’s tax basis in those common units,
even if the price the unitholder receives is less than the unitholder’s original cost. Furthermore, a substantial
portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to
potential recapture items, including depreciation recapture. In addition, because the amount realized includes a
unitholder’s share of our non-recourse liabilities, if a unitholder sells units, the unitholder may incur a tax
liability in excess of the amount of cash received from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may
result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement
accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our
income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement
plans, will be unrelated business taxable income and will be taxable to them. Furthermore, a tax-exempt entity’s
gain on sale of common units may be treated, at least in part, as unrelated business taxable income. Distributions
to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and
non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income.
Non-U.S. persons will also potentially have tax filings and payment obligations in additional jurisdictions.
Furthermore, non-U.S. persons may be subject to tax on the gain on sale of their common units to the extent the
gain is attributable to effectively connected income. Tax-exempt entities and non-U.S. persons should consult
their tax advisor before investing in our common units.
We treat each purchaser of common units as having the same tax benefits without regard to the actual units
purchased. The IRS may challenge this treatment, which could adversely affect the value of the common
units.
To maintain the uniformity of the economic and tax characteristics of common units, we have adopted
depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A
successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our
unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common
units and could have a negative impact on the value of our common units or result in audit adjustments to our
unitholders’ tax returns.
Our unitholders will likely be subject to state and local taxes and return filing requirements in states where
they do not live as a result of investing in our units.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local
taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various
jurisdictions in which we do business or own property now or in the future, even if our unitholders do not live in
any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and
pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be
subject to penalties for failure to comply with those requirements. We currently conduct business in
approximately 35 states. Many of these states currently impose a personal income tax on individuals. As we
make acquisitions or expand our business, we may own assets or conduct business in additional states that
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impose a personal income tax. It is our unitholders’ responsibility to file all U.S. federal, state and local tax
returns.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and
deduction between our general partner and our unitholders. The IRS may challenge this treatment, which
could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of
our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our
unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In
that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general
partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent
purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b)
adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may
challenge our valuation methods, our allocation of the Section 743(b) adjustment attributable to our tangible and
intangible assets, or our allocations of income, gain, loss and deduction between our general partner and certain
of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income
or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of
common units and could have a negative impact on the value of the common units or result in audit adjustments
to our unitholders’ tax returns without the benefit of additional deductions.
A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be
considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as
a partner with respect to those common units during the period of the loan and may recognize gain or loss
from the disposition.
A unitholder who loans his common units to a “short seller” to cover a short sale of common units (i) may be
considered as having disposed of the loaned common units, (ii) may no longer be treated for tax purposes as a
partner with respect to those common units during the period of the loan to the short seller and (iii) may
recognize gain or loss from such disposition.
Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect
to those common units may not be reportable by the unitholder and any distributions received by the unitholder
as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as
partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable
brokerage account agreements to prohibit their brokers from borrowing their common units.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential
legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in
our common units may be modified by administrative, legislative or judicial interpretation at any time.
Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied
retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded
partnerships to be treated as partnerships for U.S. federal income tax purposes or increase the amount of taxes
payable by unitholders in publicly traded partnerships.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units
each month based upon the ownership of our units on the first day of each month, instead of on the basis of
the date a particular unit is transferred. The IRS may challenge this treatment, which could change the
allocation of items of income, gain, loss and deduction among our unitholders.
50
We prorate our items of income, gain, loss and deduction between existing unitholders and unitholders who
purchase our units based upon the ownership of our units on the first day of each month, instead of on the basis
of the date a particular unit is transferred. The use of this proration method may not be permitted under existing
Treasury Regulations. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a
safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to
allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration
method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were
issued, we may be required to change the allocation of items of income, gain, loss and deduction among our
unitholders.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect
any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash
available for distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for
tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest)
directly from us. We will generally have the ability to shift any such tax liability to our general partner and our
unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that
we will be able to do so (or choose to do so) under all circumstances. If we are required to make payments of
taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our
unitholders might be reduced.
Risks Relating to Ownership of our Common Units
Our general partner and its affiliates, including MPC, have conflicts of interest with us and limited duties to
us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders.
Additionally, we have no control over MPC’s business decisions and operations, and MPC is under no
obligation to adopt a business strategy that favors us.
MPC owns our general partner and approximately 63 percent of our outstanding common units as of
February 17, 2020. Although our general partner has a duty to manage us in a manner that is not adverse to the
best interests of our partnership, the directors and officers of our general partner also have a duty to manage our
general partner in a manner that is not adverse to the best interests of its owner, MPC.
Conflicts of interest may arise between MPC and its affiliates, including our general partner, on the one hand,
and us and our unitholders, on the other hand. In resolving these conflicts, the general partner may favor its own
interests and the interests of its affiliates, including MPC, over the interests of our common unitholders, which
may occur under our Partnership Agreement without being independently reviewed by the conflicts committee.
These conflicts include, among others, the following situations:
•
neither our Partnership Agreement nor any other agreement requires MPC to pursue a business strategy
that favors us or utilizes our assets, which could involve decisions by MPC to increase or decrease
refinery production, shut down or reconfigure a refinery, or pursue and grow particular markets. MPC’s
directors and officers have a fiduciary duty to make these decisions in the best interests of the
stockholders of MPC;
• MPC, as a significant customer, has an economic incentive to cause us to not seek higher tariff rates, even
if such higher rates or fees would reflect rates and fees that could be obtained in arm’s-length, third-party
transactions;
• MPC may be constrained by the terms of its debt instruments from taking actions, or refraining from
taking actions, that may be in our best interests;
•
•
except in limited circumstances, our general partner has the power and authority to conduct our business
without unitholder approval;
our general partner will determine the amount and timing of asset purchases and sales, borrowings,
issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each
of which can affect the amount of cash that is distributed to our unitholders;
51
•
•
•
•
•
•
•
•
•
our general partner will determine the amount and timing of many of our cash expenditures and whether a
cash expenditure is classified as an expansion capital expenditure, which would not reduce operating
surplus, or a maintenance capital expenditure, which would reduce our operating surplus. This
determination can affect the amount of cash that is distributed to our unitholders and to our general
partner and the amount of adjusted operating surplus generated in any given period;
our general partner will determine which costs incurred by it are reimbursable by us and may cause us to
pay it or its affiliates for any services rendered to us;
our general partner may cause us to borrow funds in order to permit the payment of distributions;
our Partnership Agreement permits us to classify up to $60 million as operating surplus, even if it is
generated from asset sales, non-working capital borrowings or other sources that would otherwise
constitute capital surplus. This cash may be used to fund distributions to our general partner;
our Partnership Agreement does not restrict our general partner from entering into additional contractual
arrangements with it or its affiliates on our behalf;
our general partner intends to limit its liability regarding our contractual and other obligations;
our general partner may exercise its right to call and purchase all of the common units not owned by it
and its affiliates if it and its affiliates own more than 85 percent of the common units;
our general partner controls the enforcement of obligations owed to us by our general partner and its
affiliates, including our transportation and storage services agreements with MPC; and
our general partner decides whether to retain separate counsel, accountants or others to perform services
for us.
Under the terms of our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine,
does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners.
Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter
that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any
such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other
duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such
opportunity to another person or entity or does not communicate such opportunity or information to us. This may
create actual and potential conflicts of interest between us and affiliates of our general partner and result in less
than favorable treatment of us and our unitholders.
Our Partnership Agreement requires that we distribute all of our available cash, which could limit our ability
to grow and make acquisitions.
Our Partnership Agreement requires that we distribute all of our available cash to our unitholders. As a result, we
may require external financing sources, including commercial bank borrowings and the issuance of debt and
equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are
unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we will distribute all of our available cash, our growth may not be as fast as that of
businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units
in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those
additional units may increase the risk that we will be unable to maintain or increase our per unit distribution
level. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would
result in increased interest expense, which, in turn, may reduce the amount of cash available to distribute to our
unitholders.
Our Partnership Agreement replaces our general partner’s fiduciary duties to holders of our common units
with contractual standards governing its duties and restricts the remedies available to unitholders for actions
taken by our general partner.
Our Partnership Agreement contains provisions that eliminate the fiduciary standards to which our general
partner would otherwise be held by state fiduciary duty law and replaces those duties with several different
52
contractual standards. For example, our Partnership Agreement permits our general partner to make a number of
decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us
and our unitholders other than the implied contractual covenant of good faith and fair dealing. Our general
partner is entitled to consider only the interests and factors that it desires and is relieved of any duty or obligation
to give consideration to any interest of, or factors affecting, us, our affiliates or our limited partners.
Our Partnership Agreement contains provisions that restrict the remedies available to unitholders for actions
taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty
law. For example, our Partnership Agreement:
•
•
•
•
provides that whenever our general partner makes a determination or takes, or declines to take, any other
action in its capacity as our general partner, our general partner is required to make such determination, or
take or decline to take such other action, in good faith and will not be subject to any other or different
standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at
equity;
provides that our general partner will not have any liability to us or our unitholders for decisions made in
its capacity as a general partner so long as it acted in good faith;
provides that our general partner and its officers and directors will not be liable for monetary damages to
us or our limited partners resulting from any act or omission unless there has been a final and
non-appealable judgment entered by a court of competent jurisdiction determining that our general
partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful
misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
provides that our general partner will not be in breach of its obligations under our Partnership Agreement
or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a
conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our
Partnership Agreement.
In connection with a transaction with an affiliate or a conflict of interest, our Partnership Agreement provides
that any determination by our general partner must be made in good faith, and that our conflicts committee and
the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any
proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting
such proceeding will have the burden of overcoming such presumption. By purchasing a common unit, a
unitholder is treated as having consented to the provisions in our Partnership Agreement, including the provisions
discussed above.
Unitholders have very limited voting rights and, even if they are dissatisfied, they have limited ability to
remove our general partner without its consent.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters
affecting our business and, therefore, limited ability to influence management’s decisions regarding our business.
Unitholders did not elect our general partner or the board of directors of our general partner and will have no
right to elect our general partner or the board of directors of our general partner on an annual or other continuing
basis. The board of directors of our general partner is chosen by the members of our general partner, which are
wholly owned subsidiaries of MPC. Furthermore, if the unitholders are dissatisfied with the performance of our
general partner, they will have little ability to remove our general partner. The vote of the holders of at least
66 2/3 percent of all outstanding common units voting together as a single class is required to remove our general
partner. As of February 17, 2020, our general partner and its affiliates owned approximately 63 percent of the
outstanding common units (excluding common units held by officers and directors of our general partner and
MPC). As a result of these limitations, the price at which our common units will trade could be diminished
because of the absence or reduction of a takeover premium in the trading price.
Furthermore, unitholders’ voting rights are further restricted by the Partnership Agreement provision providing
that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than
53
our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of
the board of directors of our general partner, cannot vote on any matter.
Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to
acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence
the manner or direction of management.
If unitholders are not both citizenship-eligible holders and rate-eligible holders, their common units may be
subject to redemption.
In order to avoid (1) any material adverse effect on the maximum applicable rates that can be charged to
customers by our subsidiaries on assets that are subject to rate regulation by the FERC or analogous regulatory
body and (2) any substantial risk of cancellation or forfeiture of any property, including any governmental
permit, endorsement or other authorization, in which we have an interest, we have adopted certain requirements
regarding those investors who may own our common units. Citizenship eligible holders are individuals or entities
whose nationality, citizenship or other related status does not create a substantial risk of cancellation or forfeiture
of any property, including any governmental permit, endorsement or authorization, in which we have an interest,
and will generally include individuals and entities who are U.S. citizens. Rate-eligible holders are individuals or
entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S.
federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such
taxation. If unitholders are not persons who meet the requirements to be citizenship-eligible holders and rate-
eligible holders, they run the risk of having their units redeemed by us at the market price as of the date three
days before the date the notice of redemption is mailed. The redemption price will be paid in cash or by delivery
of a promissory note, as determined by our general partner. In addition, if unitholders are not persons who meet
the requirements to be citizenship eligible holders, they will not be entitled to voting rights.
Cost reimbursements, which will be determined in our general partner’s sole discretion, and fees due our
general partner and its affiliates for services provided will be substantial and will reduce our cash available
for distribution.
Under our Partnership Agreement, we are required to reimburse our general partner and its affiliates for all costs
and expenses that they incur on our behalf for managing and controlling our business and operations. Except to
the extent specified under our omnibus agreements or our employee services agreements, our general partner
determines the amount of these expenses. Under the terms of the omnibus agreements, we will be required to
reimburse MPC for the provision of certain general and administrative services to us. Under the terms of our
employee services agreements, we have agreed to reimburse MPC or its affiliates for the provision of certain
operational and management services to us in support of our facilities. Our general partner and its affiliates also
may provide us other services for which we will be charged fees as determined by our general partner. Payments
to our general partner and its affiliates will be substantial and will reduce the amount of cash available for
distribution to unitholders.
The control of our general partner may be transferred to a third party without unitholder consent.
There is no restriction in our Partnership Agreement on the ability of MPC to transfer its membership interest in
our general partner to a third party. The new members of our general partner would then be in a position to
replace the board of directors and officers of our general partner with their own choices and to control the
decisions taken by the board of directors and officers.
We may issue additional units without unitholder approval, which will dilute limited unitholder interests.
At any time, we may issue an unlimited number of limited partner interests of any type, including limited
partner interests that are convertible into our common units, without the approval of our unitholders and our
unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to
purchase any such limited partner interests. Further, neither our Partnership Agreement nor our bank
revolving credit facility prohibits the issuance of additional preferred units, or other equity securities that
may effectively rank senior to our common units as to distributions or liquidations. The issuance by us of
54
additional common units, preferred units or other equity securities of equal or senior rank will have the following
effects:
•
•
•
•
•
our unitholders’ proportionate ownership interest in us will decrease;
it may be more difficult to maintain or increase our distributions to unitholders, and the amount of cash
available for distribution on each unit may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of our common units may decline.
MPC may sell units in the public or private markets, and such sales could have an adverse impact on the
trading price of the common units.
As of February 17, 2020, MPC held 665,997,540 common units. Additionally, we have agreed to provide MPC
with certain registration rights. The sale of these units in the public or private markets could have an adverse
impact on the price of the common units or on any trading market that may develop.
Affiliates of our general partner, including MPC, may compete with us, and neither our general partner nor
its affiliates have any obligation to present business opportunities to us.
MPC and other affiliates of our general partner are not prohibited from owning assets or engaging in businesses
that compete directly or indirectly with us. In addition, MPC and other affiliates of our general partner may
acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the
opportunity to purchase any of those assets. As a result, competition from MPC and other affiliates of our general
partner could materially and adversely impact our results of operations and cash available for distribution to
unitholders.
Our general partner has a limited call right that may require unitholders to sell common units at an
undesirable time or price.
If at any time our general partner and its affiliates own more than 85 percent of our common units, our general
partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire
all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then
current market price. As a result, unitholders may be required to sell their common units at an undesirable time or
price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of
such units.
A unitholder’s liability may not be limited if a court finds that unitholder action constitutes control of our
business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except
for those contractual obligations of the partnership that are expressly made non-recourse to the general partner.
Our partnership is organized under Delaware law, and we conduct business in a number of other states. The
limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have
not been clearly established in some jurisdictions. A unitholder could be liable for our obligations as if they were
a general partner if a court or government agency were to determine that:
• we were conducting business in a state but had not complied with that particular state’s partnership
statute; or
•
a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve
some amendments to our Partnership Agreement or to take other actions under our Partnership
Agreement constitute “control” of our business.
Unitholders may have to repay distributions that were wrongfully distributed to them.
55
Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under
Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to
unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law
provides that for a period of three years from the date of the impermissible distribution, limited partners who
received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable
to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations
of the transferor to make contributions to the partnership that are known to the transferee at the time of the
transfer and for unknown obligations if the liabilities could be determined from our Partnership Agreement.
Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the
partnership are not counted for purposes of determining whether a distribution is permitted.
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate
governance requirements.
We list our common units on the NYSE. Because we are a publicly traded limited partnership, the NYSE does
not require us to have a majority of independent directors on our general partner’s board of directors or to
establish a compensation committee or a nominating and corporate governance committee. Accordingly,
unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE
corporate governance requirements.
Item 1B. Unresolved Staff Comments
None
56
Item 2. Properties
LOGISTICS AND STORAGE
Crude Oil and Refined Product Pipelines
The following table sets forth information regarding our crude oil and refined product pipeline systems, which
we own or have an interest in as of December 31, 2019.
Total Crude Systems
Total Refined Products Systems
Diameter
2” - 48”
4” - 36”
Length
(miles) (1)(2)(3)
7,917
5,672
Capacity
Various
Various
(1)
(2)
(3)
Includes approximately 21 miles of crude pipeline and approximately 158 miles of refined product pipeline leased from
third parties.
Includes approximately 1,921 miles of crude pipeline in which we have a 9.2 percent ownership interest, 168 miles of
crude pipeline in which we have a 35.0 percent ownership interest, 48 miles of crude pipeline in which we have a
40.7 percent ownership interest, 57 miles of crude pipeline in which we have a 58.5 percent ownership interest, 118
miles of crude pipeline in which we have a 67.0 percent ownership interest and 975 miles of crude pipeline in which we
have a 17.0 percent ownership interest. Also includes approximately 1,830 miles of refined product pipeline in which we
have a 24.5 percent ownership interest and 87 miles of refined product pipeline in which we have a 65.16 percent
ownership interest.
Includes approximately 399 miles of inactive crude pipeline and 232 miles of inactive refined product pipeline.
Our crude oil pipeline and related assets are strategically positioned to support diverse and flexible crude oil
supply options for MPC’s refineries, which receive imported and domestic crude oil through a variety of sources.
Imported and domestic crude oil is transported to supply hubs from a variety of regions, including: Cushing,
Oklahoma on the Ozark pipeline; Western Canada, Wyoming and North Dakota on the Keystone, Platte,
Mustang and Enbridge pipelines; and the Gulf Coast on the Capline crude oil pipeline. Crude oil pipelines from
the Delaware and Midland Basins, as well as from the Bakken region transport crude oil into major regional
takeaway pipelines and refining centers. Our major crude oil pipelines are connected to these supply hubs and
transport crude oil to refineries owned by MPC and third parties.
Our pipelines are strategically positioned to supply feedstocks to MPC refineries and transport refined products
from certain MPC refineries to MPC and MPLX marketing operations, as well as those of third parties. These
refined product pipelines are integrated with MPC’s and MPLX’s expansive network of refined product
marketing terminals, which support MPC’s integrated midstream business.
Terminal Assets
The following table sets forth certain information regarding our owned and operated terminals as of
December 31, 2019.
57
Owned and Operated Terminals (1)
Refined Product Terminals:
Alabama
Alaska
California
Florida
Georgia
Idaho
Illinois
Indiana
Kentucky
Louisiana
Michigan
Minnesota
New Mexico
North Carolina
North Dakota
Ohio
Pennsylvania
South Carolina
Tennessee
Utah
Washington
West Virginia
Total Refined Product
Terminals
Asphalt Terminals:
Arizona
California
Minnesota
Nevada(2)
New Mexico
Texas
Total Asphalt Terminals
Total Terminals
Number of
Terminals
Tank Shell Capacity
(mbbls)
Number of Tanks
Number of Loading
Lanes
2
3
9
4
4
3
4
6
6
1
8
1
4
4
1
12
1
1
4
1
4
2
85
3
3
1
1
1
1
10
95
443
1,310
5,367
3,407
998
988
1,221
3,229
2,587
97
2,440
12
551
1,509
2
3,218
390
371
1,149
44
825
1,587
31,745
536
755
489
252
6
178
2,216
33,961
16
31
90
64
31
55
33
60
56
7
73
5
47
34
6
101
12
8
30
9
32
25
825
53
37
8
15
9
18
140
965
4
9
54
22
9
8
14
17
25
2
26
8
15
13
15
28
2
3
12
9
11
2
308
10
11
3
4
2
5
35
343
(1) MPLX also operates one leased terminal and has partial ownership interest in one terminal, with a combined tank shell
capacity of 1,045 mbbls.
(2) This terminal is accounted for as an equity method investment.
Marine Assets
The following table sets forth certain information regarding our marine assets as of December 31, 2019. The
marine business currently has an associated transportation service agreement with MPC.
Marine Vessels
Inland tank barges:
Inland towboats:
Number of Boats
and Barges
Capacity
(thousand barrels)
286
23
7,523
N/A
58
Our fleet of boats and barges transport light products, heavy oils, crude oil, renewable fuels, chemicals and
feedstocks to and from refineries and terminals owned by MPC in the Mid-Continent and Gulf Coast regions. We
also have an MRF which is a full-service marine shipyard located on the Ohio River, adjacent to MPC’s
Catlettsburg, Kentucky refinery. The MRF is responsible for the preventive routine and unplanned maintenance
of towing vessels, barges and local terminal facilities.
Refining Logistics Assets
The following table outlines the tankage, rail and truck racks, and docks owned by us, serving MPC’s refineries
as of December 31, 2019. Each of the following assets are currently included in storage services agreements with
MPC.
MPC Refining Logistics Assets
Galveston Bay, Texas City, Texas
Garyville, Louisiana
Los Angeles, California
Robinson, Illinois
Anacortes, Washington
Martinez, California
El Paso, Texas
Catlettsburg, Kentucky
Detroit, Michigan
St. Paul Park, Minnesota
Kenai, Alaska
Mandan, North Dakota
Canton, Ohio
Salt Lake City, Utah
Gallup, New Mexico
Total
Other L&S Assets
Tank Capacity (mbbls)
18,936
17,320
13,838
6,987
6,126
5,771
5,240
5,177
4,986
4,228
3,573
2,739
2,700
2,056
993
100,670
The following tables set forth certain information regarding our other midstream assets as of December 31, 2019,
each of which currently have an associated transportation services agreement or storage services agreement with
MPC.
Asset Name
LOOP(2)
Barge Docks
Mt. Airy Terminal(3)
Tank Farms(4)
Caverns
Pipeline Name
Belfield water system
Green River water system
Capacity (1)
Associated MPC
Refineries
N/A Garyville, LA
2,910 mbbls Multiple
4,099 mbbls Garyville, LA
26,264 mbbls N/A
4,709 mbbls N/A
Diameter
(inches)
4” - 8”
3” - 4”
Length
(miles)
Capacity
(mbpd)(5)
103
12
20 mbpd
15 mbpd
(1) Capacity for Tank Farms is shown as 100 percent of the available storage capacity. Capacity for the Barge Dock is
shown as 100 percent of the throughput capacity. Capacity for caverns is shown as the storage commitment.
(2) We have a 40.7 percent interest in LOOP, which includes a deep-water oil port and crude oil storage.
59
(3) The Mt. Airy Terminal includes 37 tanks, 2-bay ethanol loading rack, 3-vessel barge/ship dock and 7 dock loading lines.
(4) We own and operate 28 tank farms and operate two leased tank farms.
(5) All capacities reflect 100 percent of the pipeline systems’ capacity in thousands of barrels per day.
GATHERING AND PROCESSING
The following tables set forth certain information relating to our consolidated and operated joint venture gas
processing facilities, fractionation facilities, natural gas gathering systems, NGL pipelines and natural gas
pipelines as of and for the year ended December 31, 2019. All throughputs and utilizations included are
weighted-averages for days in operation. See further discussion about our joint ventures in Item 8. Financial
Statements and Supplementary Data - Note 5.
Gas Processing Complexes
Region
Marcellus Shale
Utica Shale
Southern Appalachia
Southwest(2)
Bakken
Rockies
Total Gas Processing
Design Throughput
Capacity (MMcf/d)
Natural Gas
Throughput(1)
(MMcf/d)
Utilization of
Design Capacity(1)
6,120
1,325
620
1,887
190
1,472
11,614
5,248
810
244
1,364
151
572
8,389
91%
61%
39%
79%
83%
39%
76%
(1) Natural gas throughput is a weighted average for days in operation. The utilization of design capacity has been calculated
using the weighted average design throughput capacity.
(2) Centrahoma Processing LLC’s processing capacity of 550 MMcf/d and actual throughput of 272 MMcf/d, that exceeded
our 40 percent share of the capacity of 220 MMcf/d, are not included in this table as we own a non-operating interest.
Fractionation & Condensate Stabilization Facilities
Region
Marcellus Shale(2)(3)
Utica Shale(2)(3)(4)
Southern Appalachia(2)(5)
Southwest
Bakken
Rockies
Total C3+ Fractionation and Condensate Stabilization
Design Throughput
Capacity
(mbpd)
NGL Throughput(1)
(mbpd)
Utilization
of Design
Capacity(1)
347
23
24
11
34
61
500
290
9
12
6
24
4
345
84%
39%
50%
55%
83%
7%
70%
(1) NGL throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using
the weighted average design throughput capacity.
(2) Certain complexes have above-ground NGL storage with a usable capacity of 938 thousand barrels, large-scale truck and
rail loading. We also have access to up to an additional 800 thousand barrels of propane storage capacity that can be
utilized by our assets in the Marcellus Shale, Utica Shale, and Appalachia region under an agreement with a third party.
Lastly, we have up to 240 thousand barrels of propane storage with third parties that can be utilized by our assets in the
Marcellus Shale and Utica Shale.
(3) The capacity, throughput and utilization of design capacity at the Hopedale fractionation complex is presented in
the Marcellus Shale totals, however, the Hopedale fractionation complex is jointly owned by MarkWest Ohio
Fractionation Company, L.L.C. (“Ohio Fractionation”) and MarkWest Utica EMG, L.L.C. (“MarkWest Utica
EMG”). Ohio Fractionation is a joint venture between MarkWest Liberty Midstream & Resources, L.L.C.
(“MarkWest Liberty Midstream”) and Sherwood Midstream (a joint venture between MarkWest Liberty
Midstream and Antero Midstream LLC). MarkWest Liberty Midstream and Sherwood Midstream are entities that
operate in the Marcellus region, and MarkWest Utica EMG is an entity that operates in the Utica region. During
the year ended December 31, 2019, the Marcellus Operations and Utica Operations utilized an average of 83
60
percent and 17 percent of the Hopedale fractionation complex, respectively. Additionally, Sherwood Midstream has the
right to fractionation revenue and the obligation to pay expenses related to 40 mbpd of capacity in the Hopedale 3 and
Hopedale 4 fractionators.
(4) We have access to 100 thousand barrels of condensate storage in this region.
(5) This region includes complexes with both above-ground, pressurized NGL storage facilities, with usable capacity of
48 thousand barrels, and underground storage facilities, with usable capacity of 238 thousand barrels. Product can be
received by truck, pipeline or rail and can be transported from the facility by truck, rail or barge. We also have large-scale
truck and rail loading and unloading capabilities, and a river barge facility capable of loading a 20 thousand barrel barge.
De-ethanization Facilities
Region
Marcellus Shale
Utica Shale
Southwest
Total De-ethanization
Design Throughput
Capacity
(mbpd)
NGL Throughput(1)
(mbpd)
Utilization
of Design
Capacity(1)
273
40
18
331
179
10
9
198
72%
25%
50%
64%
(1) NGL throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using
the weighted average design throughput capacity.
Natural Gas Gathering Systems
Region
Marcellus Shale
Utica Shale
Southwest
Bakken
Rockies(2)
Total Natural Gas Gathering
Design Throughput
Capacity
(MMcf/d)
Natural Gas
Throughput(1)
(MMcf/d)
Utilization of
Design Capacity(1)
1,547
3,183
2,570
194
1,486
8,980
1,287
2,200
1,628
151
701
5,967
84%
70%
72%
78%
47%
69%
(1) Natural gas throughput is a weighted average for days in operation. The utilization of design capacity has been calculated
using the weighted average design throughput capacity.
(2) This region does not include our operated joint venture, Rendezvous Gas Services, L.L.C. (“RGS”), which has a
gathering capacity of 1,032 MMcf/d; this system supports other systems which are included in the Rockies region and
that throughput is presented in the table above. The third party volumes gathered for RGS during the year ended
December 31, 2019 were 127 MMcf/d.
NGL Pipelines
Region
Marcellus Shale
Utica Shale
Southern Appalachia
Southwest(1)
Bakken
Rockies
(1)
Includes 38 miles of inactive pipeline.
Title to Properties
Diameter
4” - 20”
4” - 12”
6” - 8”
6”
8” - 12”
8”
Length
(miles)
Design Throughput
Capacity (mbpd)
399
119
138
50
84
10
Various
Various
35
39
80
15
Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the
property. In many instances, lands over which pipeline rights-of-way have been obtained may be subject to prior
liens that have not been subordinated to the right-of-way grants, as well as potential conflicts with other mineral
or surface use owners. We have obtained, where determined necessary, permits, leases, license agreements and
61
franchise ordinances from public authorities to cross over or under, or to lay facilities in or along water courses,
county roads, municipal streets and state highways, as applicable. We also have obtained easements and license
agreements from railroad companies to cross over or under railroad properties or rights-of-way. Some of the
property rights we have obtained are revocable at the election of the grantor. We believe that our properties and
facilities are adequate for our operations and that our facilities are adequately maintained. In addition, our L&S
segment leases vehicles, building spaces, and pipeline equipment under long-term operating leases, most of
which include renewal options. Our L&S segment also leases certain pipelines under a capital lease that has a
fixed price purchase option in 2020. Many of our compression, processing, fractionation and other facilities,
including certain fractionation plants and certain of our pipelines and other facilities, are on land that we either
own in fee or that is held under long-term leases, but for any such facilities that are on land that we lease, we
could be required to remove our facilities upon the termination or expiration of the leases.
Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that were transferred to
us required the consent of the then-current landowner to transfer these rights, which in some instances was a
governmental entity. We believe that we have obtained sufficient third-party consents, permits and authorizations
for the transfer of the assets necessary for us to operate our business. We also believe we have satisfactory title or
other right to all of our material land assets. Title to these properties is subject to encumbrances in some cases,
such as coal, that may require payment to other holders of title in the property at issue; however, we believe that
none of these burdens will materially detract from the value of these properties or from our interest in these
properties, or will materially interfere with their use in the operation of our business. See Item 8. Financial
Statements and Supplementary Data – Note 22, for additional information regarding our leases.
MPC indemnifies us for certain title defects and for failures to obtain certain consents and permits necessary to
conduct our business with respect to the assets contributed to us by MPC. Although title to these properties is
subject to encumbrances in some cases, such as customary interests generally retained in connection with
acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to
clean up environmental contamination, liens for current taxes and other burdens, and easements, restrictions and
other encumbrances to which the underlying properties were subject at the time of acquisition by our Predecessor
or us, we believe that none of these burdens should materially detract from the value of these properties or from
our interest in these properties or should materially interfere with their use in the operation of our business.
Item 3. Legal Proceedings
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.
Litigation
MPLX, MarkWest, MarkWest Liberty Midstream, MarkWest Liberty Bluestone, L.L.C., Ohio Fractionation and
MarkWest Utica EMG (collectively, the “MPLX Parties”) were parties to various lawsuits with Bilfinger Westcon,
Inc. (“Westcon”) that were instituted in 2016 and 2017 in the Court of Common Pleas in Butler County, Pennsylvania,
the Circuit Court in Wetzel County, West Virginia, and the Court of Common Pleas in Harrison County, Ohio. The
lawsuits related to disputes regarding construction work performed by Westcon at the Bluestone, Mobley and Cadiz
processing complexes in Pennsylvania, West Virginia and Ohio, respectively, and the Hopedale fractionation complex
in Ohio. As previously disclosed in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, in July
2019, Westcon and the MPLX Parties reached an agreement to resolve the disputes among those parties relating to the
Bluestone processing complex in Pennsylvania. In the quarter ended December 31, 2019, Westcon and the MPLX
Parties reached agreements to resolve the remaining disputes among those parties relating to the Mobley and Cadiz
62
processing complexes in West Virginia and Ohio, respectively, and the Hopedale fractionation complex in Ohio. The
settlements will not have a material adverse effect on MPLX’s consolidated financial position, results of operations or
cash flows.
Item 4. Mine Safety Disclosure
Not applicable
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
Our common limited partner units are listed on the NYSE and traded under the symbol “MPLX”. As of
February 17, 2020, there were 267 registered holders of 392,418,325 outstanding common units held by the
public, including 392,045,653 common units held in street name. In addition, as of February 17, 2020, MPC and
its affiliates owned 665,997,540 of our common units, constituting approximately 63 percent of the outstanding
common units. In addition, MPC, through our general partner, owns a non-economic general partnership interest
in us.
Distributions of Available Cash
Our Partnership Agreement requires that, within 60 days after the end of each quarter, we distribute all of our
available cash to unitholders of record on the applicable record date.
Definition of available cash. Available cash is defined in our Partnership Agreement. Available cash generally
means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
•
less the amount of cash reserves established by our general partner to:
•
•
•
provide for the proper conduct of our business (including reserves for our future capital expenditures
and for anticipated future credit needs);
comply with applicable law, any of our debt instruments or other agreements or obligations; or
provide funds for distributions to our unitholders and to our general partner for any one or more of the
next four quarters (provided that our general partner may not establish cash reserves for distributions
if the effect of the establishment of such reserves will prevent us from distributing the minimum
quarterly distribution on all common units for the current quarter);
•
plus, if our general partner so determines, all or any portion of the cash on hand resulting from working
capital borrowings made subsequent to the end of such quarter.
Intent to Distribute the Minimum Quarterly Distribution. Under our current cash distribution policy, we intend to
make a minimum quarterly distribution to the holders of our common units of $0.2625 per unit, or $1.05 per unit
on an annualized basis, to 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.
However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter.
The amount of distributions paid under our policy and the decision to make any distribution is determined by our
general partner, taking into consideration the terms of our Partnership Agreement. See Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources –
Debt and Liquidity Overview, for a discussion of the restrictions included in our bank revolving credit facility
that may restrict our ability to make distributions.
63
Preferred Unit Distributions
The holders of the Series A preferred units received cumulative quarterly distributions equal to $0.528125 per
unit for each quarter prior to the second quarter of 2018. Beginning with the second quarter of 2018, the holders
of the Series A preferred units are entitled to receive a quarterly distribution equal to the greater of $0.528125 per
unit or the amount of distributions they would have received on an as converted basis. Series B preferred
unitholders are entitled to receive a fixed distribution of $68.75 per unit, per annum, payable semi-annually in
arrears on February 15 and August 15, or the first business day thereafter, up to and including February 15, 2023.
After February 15, 2023, the holders of Series B preferred units are entitled to receive cumulative, quarterly
distributions payable in arrears on the 15th day of February, May, August and November of each year, or the first
business day thereafter, based on a floating annual rate equal to the three-month LIBOR plus 4.652 percent.
MPLX may not pay any distributions for any quarter on any junior securities, including any of the common units,
unless the distribution payable to the preferred units with respect to such quarter, together with any previously
accrued and unpaid distributions to the preferred units, have been paid in full.
Recent Sales of Unregistered Units
In connection with the closing of the Merger, each common unit held by ANDX’s public unitholders was
converted into the right to receive 1.135 MPLX common units. ANDX common units held by certain affiliates of
MPC were converted into the right to receive 1.0328 MPLX common units.
Additionally, as a result of the Merger, each ANDX TexNew Mex Unit issued and outstanding immediately prior
to the effective time of the Merger was converted into a right for Western Refining Southwest, Inc. (“Southwest,
Inc.”), a wholly-owned subsidiary of MPC, as the holder of all such units, to receive a unit representing a
substantially equivalent special limited partner interest in MPLX (the “MPLX TexNew Mex Units”). By virtue of
the conversion, all ANDX TexNew Mex Units were cancelled and ceased to exist as of the effective time of the
Merger. The MPLX TexNew Mex Units are a new class of units in MPLX substantially equivalent to the ANDX
TexNew Mex Units, including substantially equivalent rights, powers, duties and obligations that the ANDX
TexNew Mex Units had immediately prior to the closing of the Merger. As a result of the Merger, the ANDX
Special Limited Partner Interest outstanding immediately prior to the effective time of the Merger was converted
into a right for Southwest, Inc., as the holder of all such interest, to receive a substantially equivalent special
limited partner interest in MPLX (the “MPLX Special Limited Partner Interest”). By virtue of the conversion, the
ANDX Special Limited Partner Interest was cancelled and ceased to exist as of the effective time of the Merger.
The issuance of MPLX TexNew Mex Units and the MPLX Special Limited Partner Interest was effected in
reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended.
64
Item 6. Selected Financial Data
The following table shows selected historical consolidated financial data of MPLX LP as of the dates and for the
years indicated. The following table also presents the non-GAAP financial measures of Adjusted EBITDA and
DCF, which we use in our business. For the definitions of Adjusted EBITDA and DCF and a reconciliation to our
most directly comparable financial measures calculated and presented in accordance with GAAP, see Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP
Financial Information and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations – Results of Operations.
(In millions, except per unit data)
2019(1)
2018(1)
2017
2016
2015
Consolidated Statements of Income Data
Total revenues and other income
Income from operations
Net income
Net income attributable to MPLX LP
Limited partners’ interest in net income attributable
to MPLX LP
Per Unit Data
Net income attributable to MPLX LP per limited
partner unit:
Common - basic
Common - diluted
Subordinated - basic and diluted
Cash distributions declared per limited partner
common unit
Consolidated Balance Sheets Data (at period end)
Property, plant and equipment, net
Total assets
Long-term debt, including finance leases(2)
Series A preferred units
Consolidated Statements of Cash Flows Data
Net cash provided by (used in):
Operating activities
Investing activities
Financing activities
Additions to property, plant and equipment(3)
Other Financial Data
Adjusted EBITDA attributable to MPLX LP(4)(5)
DCF attributable to MPLX LP(4)(5)
Cash distributions declared on limited partner
common units
$ 9,041
2,377
1,462
1,033
$ 7,005
2,728
2,006
1,818
$ 3,867
1,191
836
794
$ 3,029
683
434
233
$ 1,101
381
333
156
935
1,743
411
1
99
1.00
1.00
—
2.29
2.29
—
1.07
1.06
—
—
—
—
1.23
1.22
0.11
2.6900
2.5300
2.2975
2.0500
1.8200
22,145
40,430
19,704
968
21,525
39,325
17,922
1,004
12,187
19,500
6,945
1,000
11,408
17,509
4,422
1,000
10,214
16,404
5,255
—
4,082
(3,063)
(1,089)
2,408
3,071
(2,878)
(117)
2,111
1,907
(2,308)
171
1,411
1,491
(1,417)
113
1,313
427
(1,681)
1,275
334
4,334
3,489
3,475
2,781
2,004
1,628
1,419
1,140
498
399
$ 2,635
$ 1,985
$
895
$
692
$
255
(1) On July 30, 2019, MPLX completed the acquisition of ANDX. ANDX’s assets, liabilities and results of operations prior
to the Merger are collectively included in what we refer to as the “Predecessor” from October 1, 2018, which was the
date that MPC acquired Andeavor. MPLX’s acquisition of ANDX is considered a transfer between entities under
common control due to MPC’s prior relationship with ANDX. As an entity under common control with MPC, MPLX
recorded the assets acquired and liabilities assumed on its consolidated balance sheets at MPC’s historical carrying value.
Transfers of businesses between entities under common control require prior periods to be retrospectively adjusted for
those dates that the entity was under common control. Accordingly, the table above includes the historical results of
ANDX beginning October 1, 2018.
(2) During 2015, in connection with the MarkWest Merger, MPLX LP assumed MarkWest senior notes with an
aggregate principal amount of $4.1 billion and used its credit facility to repay $850 million of the $943 million of
65
borrowings under MarkWest’s credit facility. In connection with the Merger, MPLX LP assumed ANDX senior notes
with an aggregate principal amount of $3.75 billion as of October 1, 2018.
(3) Represents cash capital expenditures as reflected on the Consolidated Statements of Cash Flows for the periods
indicated, which are included in cash used in investing activities.
(4) The 2015 Adjusted EBITDA attributable to MPLX LP includes pre-merger EBITDA from MarkWest and the 2015 DCF
includes undistributed DCF from MarkWest.
(5) For all years presented, Predecessor is excluded from Adjusted EBITDA attributable to MPLX LP and DCF attributable
to MPLX LP.
Operating Data
2019 L&S Pipeline Throughput
Refined
product
pipelines:
36.9%
Crude oil
pipelines:
63.1%
L&S
Crude oil transported for (mbpd)(1):
MPC
Third parties
Total
% MPC
Refined products transported for (mbpd)(2):
MPC(3)
Third parties
Total
% MPC
Average tariff rates ($ per Bbl)(4):
Crude oil pipelines
Refined product pipelines
Total pipelines
2019
2018
2017
2016
2015
2,671
557
3,228
2,446
675
3,121
1,622
314
1,936
1,461
182
1,643
1,443
197
1,640
83%
78%
84%
89%
88%
1,629
257
1,886
1,571
252
1,823
86%
86%
928
157
1,085
86%
844
146
990
85%
966
27
993
97%
$
$
0.94
0.75
0.87
$
$
0.67
0.75
0.70
$
$
0.56
0.74
0.63
$
$
0.57
0.68
0.61
$
$
Terminal throughput (mbpd)(5)
3,279
3,148
1,477
1,505
Marine Assets (number in operation)(6)
Barges
Towboats
286
23
256
23
232
18
222
18
66
0.55
0.65
0.59
N/A
219
18
2019 G&P Gathering Throughput
(MPLX LP Operated)
2019 G&P Natural Gas Processed
(MPLX LP Operated)
Utica: 36.1%
Marcellus:
21.1%
Southwest:
26.7%
Bakken: 2.5%
Rockies:
13.6%
Marcellus:
60.6%
Rockies: 6.6%
Bakken: 1.7%
Utica: 9.4%
Southwest:
18.9%
Southern Appalachian:
2.8%
2019 G&P C2+ NGLs Fractionated
(MPLX LP Operated)
Marcellus:
81.5%
Rockies: 0.7%
Bakken: 4.5%
Southern
Appalachian: 2.2%
Utica: 8.2%
Southwest: 2.8%
G&P Consolidated entities(8)
Gathering Throughput (MMcf/d)
Marcellus Operations
Utica Operations
Southwest Operations
Bakken Operations
Rockies Operations
Total gathering throughput
Natural Gas Processed (MMcf/d)
Marcellus Operations
Utica Operation
Southwest Operations
Southern Appalachian Operations
Bakken Operations
Rockies Operations
Total natural gas processed
C2 + NGLs Fractionated (mbpd)
Marcellus Operations(10)
Utica Operations
Southwest Operations
Southern Appalachian Operations(11)
Bakken Operations
Rockies Operations
Total C2 + NGLs fractionated(12)
2019
2018
2017
2016
2015(7)
1,155
—
1,566
147
654
3,522
3,826
—
1,438
247
147
573
6,231
379
—
18
15
15
4
431
1,004
—
1,410
N/A
N/A
2,414
3,619
—
1,326
265
N/A
N/A
5,210
320
—
20
14
N/A
N/A
354
910
—
1,431
N/A
N/A
2,341
3,210
—
1,226
253
N/A
N/A
4,689
260
—
18
15
N/A
N/A
293
889
—
1,439
N/A
N/A
2,328
2,964
—
1,125
243
N/A
N/A
4,332
220
—
24
12
N/A
N/A
256
1,287
—
1,625
151
630
3,693
4,192
—
1,629
244
151
572
6,788
435
—
15
12
24
4
490
67
G&P Consolidated entities plus
Partnership-Operated Equity Method
Investments(9)
Gathering Throughput (MMcf/d)
Marcellus Operations
Utica Operations
Southwest Operations
Bakken Operations
Rockies Operations
Total gathering throughput
Natural Gas Processed (MMcf/d)
Marcellus Operations
Utica Operations
Southwest Operations
Southern Appalachian Operations
Bakken Operations
Rockies Operations
Total natural gas processed
C2 + NGLs Fractionated (mbpd)
Marcellus Operations(10)
Utica Operations(10)
Southwest Operations
Southern Appalachian Operations(11)
Bakken Operations
Rockies Operations
Total C2 + NGLs fractionated(12)
2019
2018
2017
2016
2015(7)
1,287
2,200
1,628
151
828
6,094
5,248
810
1,636
244
151
572
8,661
435
44
15
12
24
4
534
1,155
1,809
1,567
147
841
5,519
4,448
886
1,438
247
147
573
7,739
379
47
18
15
15
4
478
1,004
1,192
1,412
N/A
N/A
3,608
3,885
984
1,326
265
N/A
N/A
6,460
320
40
20
14
N/A
N/A
394
910
932
1,433
N/A
N/A
3,275
3,210
1,072
1,226
253
N/A
N/A
5,761
260
42
18
15
N/A
N/A
335
889
745
1,441
N/A
N/A
3,075
2,964
1,136
1,125
243
N/A
N/A
5,468
220
51
24
12
N/A
N/A
307
2019
2018
2017
2016
2015
Pricing Information
Natural Gas NYMEX HH ($/MMBtu)
C2 + NGL Pricing/Gal(13)
$
$
2.53
0.52
$
$
3.07
0.78
$
$
3.02
0.66
$
$
2.55 $
0.47 $
2.04
0.40
(1)
(2)
(3)
Represents the average aggregate daily number of barrels of crude oil transported on our pipelines and at our Wood
River barge dock for MPC and for third parties. Volumes shown are 100 percent of the volumes transported on the
pipelines and barge dock.
Represents the average aggregate daily number of barrels of products transported on our pipelines for MPC and third
parties. Volumes shown are 100 percent of the volumes transported on the pipelines.
Includes volumes shipped by MPC on various pipelines under joint tariffs with third parties. For accounting purposes,
revenue attributable to these volumes is classified as third-party revenue because we receive payment from those third
parties with respect to volumes shipped under the joint tariffs; however, the volumes associated with this revenue are
applied towards MPC’s minimum quarterly volume commitments on the applicable pipelines because MPC is the
shipper of record.
(4) Average tariff rates calculated using pipeline transportation revenues divided by pipeline throughput barrels.
Throughput reported for 2016 represents average volumes for the nine months beginning April 1, 2016.
(5)
(6)
Represents total at the end of the period.
(7) G&P volumes reported for 2015 represent the average volumes after the close of the MarkWest Merger.
(8)
(9)
This table represents operating data for entities that have been consolidated into the MPLX financial statements.
This table 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.
(10) 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
68
fractionation complex. Additionally, Sherwood Midstream has the right to fractionation revenue and the obligation to
pay expenses related to 40 mbpd of capacity in the Hopedale 3 and Hopedale 4 fractionators.
Includes NGLs fractionated for the Marcellus and Utica Operations.
(11)
(12) Purity ethane makes up approximately 179 mbpd, 171 mbpd, 141 mbpd, 114 mbpd and 83 mbpd of MPLX LP
consolidated total fractionated products for the years ended December 31, 2019, 2018, 2017, 2016 and 2015,
respectively. Purity ethane makes up approximately 189 mbpd, 185 mbpd, 146 mbpd, 118 mbpd and 89 mbpd of MPLX
operated total fractionated products for the years ended December 31, 2019, 2018, 2017, 2016 and 2015, respectively.
(13) 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.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
All statements in this section, other than statements of historical fact, are forward-looking statements that are
inherently uncertain. See “Disclosures Regarding Forward-Looking Statements” and “Risk Factors” for a
discussion of the factors that could cause actual results to differ materially from those projected in these
statements. The following information concerning our business, results of operations and financial condition
should also be read in conjunction with the information included under Item 1. Business, Item 6. Selected
Financial Data and Item 8. Financial Statements and Supplementary Data.
MPLX OVERVIEW
We are a diversified, large-cap MLP formed by MPC that owns and operates midstream energy infrastructure and
logistics assets, and provides fuels distribution services. Our assets include a network of crude oil and refined
product pipelines; an inland marine business; light-product, asphalt, heavy oil and marine terminals; storage
caverns; refinery tanks, docks, loading racks, and associated piping; crude oil and natural gas gathering systems
and pipelines; as well as natural gas and NGL processing and fractionation facilities. The operation of these
assets are conducted in our Logistics and Storage (“L&S”) and Gathering and Processing (“G&P”) operating
segments. Our assets are positioned throughout the United States. Our L&S segment primarily engages in the
transportation, storage, distribution and marketing of crude oil, asphalt and refined petroleum products. The L&S
segment also includes the operation of our inland marine business, terminals, rail facilities, storage caverns and
refining logistics. Our G&P segment primarily engages in the gathering, processing and transportation of natural
gas as well as the gathering, transportation, fractionation, storage and marketing of NGLs. The assets and
operations of our L&S and G&P segments described above include the assets and operations of Andeavor
Logistics LP (“ANDX”) acquired via merger on July 30, 2019, which complemented our existing business in
addition to expanding our operations to the West Coast.
RECENT DEVELOPMENTS
On February 21, 2020, MPLX, through a wholly-owned subsidiary, formed a joint venture with Delek US
Energy, Inc. (“Delek”) (the “WWP Project Financing JV”) for the specific purpose of financing a portion of
MPLX’s and Delek’s combined construction costs for the Wink to Webster pipeline system. Both MPLX and
Delek contributed their respective 15 percent ownership interests in the Wink to Webster Pipeline JV to the
WWP Project Financing JV. Also on February 21, 2020, the WWP Project Financing JV, through a wholly-
owned subsidiary, entered into a committed term loan facility with a syndicate of lenders providing for up to
approximately $608 million in term loan borrowings to, among other things, fund future capital calls received
from the Wink to Webster Pipeline JV and pay debt service costs under the term loan facility prior to the
commercial operation date of the Wink to Webster pipeline system. The WWP Project Financing JV pledged the
combined 30 percent interest in the Wink to Webster Pipeline JV contributed to it by MPLX and Delek to secure
its obligations under the term loan facility.
On January 23, 2020, we announced the board of directors of our general partner had declared a distribution of
$0.6875 per common unit that was paid on February 14, 2020 to common unitholders of record on
February 4, 2020.
MPC’s board of directors has formed a special committee to evaluate strategies to enhance shareholder value
through a review of its Midstream business and to analyze, among other things, the strategic fit of assets with
69
MPC, the ability to realize full valuation credit for midstream earnings and cash flow, balance sheet impacts
including liquidity and credit ratings, transaction tax impacts, separation costs, and overall complexity.
SIGNIFICANT FINANCIAL AND OTHER HIGHLIGHTS
During 2019, we were able to focus and execute on our strategic vision by growing our business across the
midstream value chain and investing in new or existing assets to enhance the stability of our cash flows, while at
the same maintaining our investment grade credit profile. Significant financial and other highlights for the year
ended December 31, 2019 are shown in the chart below. Refer to the Results of Operations and the Liquidity and
Capital Resources sections for further details.
Financial Highlights (in millions)
$9,041
$7,005
Revenues and
Other Income
Income from
Operations(1)
$3,867
$2,377
$2,728
$1,191
$1,462
Net Income(1)
$2,006
$836
Adjusted EBITDA
Attributable to
MPLX(2)
DCF Attributable
to GP and LP
Unitholders(2)
$5,104
$3,810
$2,051
$1,608
$3,978
$2,950
2019
2018
2017
(1) Includes goodwill impairment of $1.2 billion within our G&P operating segment.
(2) Includes Adjusted EBITDA attributable to Predecessor and DCF adjustments attributable to Predecessor.
Additional highlights for the year ended December 31, 2019 include:
• MPLX completed the acquisition of ANDX via Merger on July 30, 2019. The historical results of ANDX
have been incorporated into the MPLX results from October 1, 2018, which is the date that MPC acquired
Andeavor. At the effective time of the Merger, each common unit held by ANDX’s public unitholders was
converted into the right to receive 1.135 MPLX common units. ANDX common units held by certain
affiliates of MPC were converted into the right to receive 1.0328 MPLX common units. The assets of
ANDX complement and enhance MPLX’s existing asset base and further expand MPLX’s existing
footprint.
• MPLX entered into a joint venture agreement related to the Wink-to-Webster crude oil pipeline, which
remains on schedule to be completed in the first half of 2021 and has 100 percent of the contractible
capacity committed with minimum volume commitments. This is a 36-inch diameter pipeline with a
capacity of 1.5 million barrels per day which will originate in the Permian Basin and have destination points
in the Houston market, including MPC’s Galveston Bay refinery.
70
• We also entered into a joint venture agreement related to the design and construction of the Whistler
Pipeline. The Whistler Pipeline is designed to be a 42-inch diameter pipeline, which will transport
approximately 2 Bcf/d of natural gas from Waha, Texas, to the Agua Dulce area in South Texas. The
majority of available capacity on the planned pipeline has been committed with minimum volume
commitments. The pipeline is expected to be in service in the second half of 2021.
•
Additionally, we continue to execute on our organic growth plan through terminal and marine fleet
expansions, the expansion of processing and fractionating capacity at numerous plants, as well as having a
continued focus on the optimization of our portfolio of assets, which could include asset divestitures.
Financing Activities
•
•
•
During the year, MPLX: entered into a Term Loan Agreement, which provides for a committed term loan
facility for up to an aggregate of $1.0 billion; issued $2.0 billion aggregate principal amount of floating rate
senior notes in a public offering; increased its borrowing capacity on the MPLX Credit Agreement to
$3.5 billion; extended the maturity of the MPLX Credit Agreement to July 30, 2024; and paid off
$500 million aggregate principal amount of the outstanding ANDX 5.5 percent senior notes due 2019 at
maturity.
In connection with the Merger, MPLX also assumed all outstanding ANDX senior notes, which had an
aggregate principal amount of $3.75 billion with interest rates ranging from 3.5 percent to 6.375 percent and
maturity dates ranging from 2019 to 2047. On September 23, 2019, $3.06 billion aggregate principal amount
of ANDX’s outstanding senior notes were exchanged for an aggregate principal amount of $3.06 billion
new senior notes issued by MPLX in an exchange offer and consent solicitation undertaken by MPLX,
leaving $690 million aggregate principal of outstanding senior notes issued by ANDX, of which
$500 million aggregate principal amount of outstanding ANDX 5.5 percent senior notes due 2019 were paid
off on October 15, 2019 at maturity as described above.
During the year ended December 31, 2019, we did not issue any common units under our ATM Program. As
of December 31, 2019, $1.7 billion of common units remain available for issuance through the ATM
Program.
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 and DCF. The amount of Adjusted EBITDA and DCF generated is considered by
the board of directors of our general partner in approving MPLX’s cash distributions.
We define Adjusted EBITDA as net income adjusted for: (i) depreciation and amortization; (ii) provision/
(benefit) for income taxes; (iii) amortization of deferred financing costs; (iv) extinguishment of debt;
(v) non-cash equity-based compensation; (vi) impairment expense; (vii) net interest and other financial costs;
(viii) income/(loss) from equity method investments; (ix) distributions and adjustments related to equity method
investments (x) unrealized derivative gains/(losses); (xi) acquisition costs; (xii) noncontrolling interests and
(xiii) other adjustments as deemed necessary. We also use DCF, which we define as Adjusted EBITDA adjusted
for: (i) deferred revenue impacts; (ii) net interest and other financial costs; (iii) net maintenance capital
expenditures; (iv) equity method investment capital expenditures paid out; and (v) other non-cash items. We
make a distinction between realized and 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.
We believe that the presentation of Adjusted EBITDA and DCF 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. Adjusted EBITDA and
DCF should not be considered alternatives to GAAP net income or net cash provided by operating activities.
Adjusted EBITDA and DCF 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
71
performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and DCF should not be
considered in isolation or as substitutes for analysis of our results as reported under GAAP. Additionally, because
Adjusted EBITDA and DCF 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 the Results of Operations section.
Management also utilizes Segment Adjusted EBITDA in evaluating the financial performance of our segments.
The disclosure of this measure allows investors to understand how management evaluates financial performance
to make operating decisions and allocate resources.
COMPARABILITY OF OUR FINANCIAL RESULTS
The comparability of our financial results has been impacted by acquisitions, dispositions, performance of our
equity method investments, and impairments among others (see Item 8. Financial Statements and Supplementary
Data – Notes 4, 5 and 14).
72
RESULTS OF OPERATIONS
The following table and discussion is a summary of our results of operations for the years ended 2019, 2018 and
2017, including a reconciliation of Adjusted EBITDA and DCF from net income and net cash provided by
operating activities, the most directly comparable GAAP financial measures. Prior period financial information
has been retrospectively adjusted for common control transactions.
(In millions)
Revenues and other income:
Service revenue
Service revenue - related parties
Service revenue - product related
Rental income
Rental income - related parties
Product sales
Product sales - related parties
Income from equity method investments(1)
Other income
Other income - related parties
Total revenues and other income
Costs and expenses:
Cost of revenues (excludes items below)
Purchased product costs
Rental cost of sales
Rental cost of sales - related parties
Purchases - related parties
Depreciation and amortization
Impairment expense
General and administrative expenses
Other taxes
Total costs and expenses
Income from operations
Related party interest and other financial costs
Interest expense (net of amounts capitalized)
Other financial costs
Income before income taxes
Provision for income taxes
Net income
Less: Net income attributable to noncontrolling
interests
Less: Net income attributable to Predecessor
Net income attributable to MPLX LP
Adjusted EBITDA attributable to MPLX LP
(excluding Predecessor results)(2)
Adjusted EBITDA attributable to MPLX LP
(including Predecessor results)(3)
DCF attributable to GP and LP unitholders
(including Predecessor results)(3)
$
2019
2018
$ Change
2017
$ Change
$
$
2,498
3,455
140
388
1,196
806
142
290
12
114
9,041
1,489
686
141
165
1,231
1,254
1,197
388
113
6,664
2,377
11
851
53
1,462
—
1,462
28
401
1,033
1,856
2,404
220
352
846
887
87
247
7
99
7,005
1,096
824
135
31
925
867
—
316
83
4,277
2,728
5
590
119
2,014
8
2,006
16
172
1,818
$
$
642
1,051
(80)
36
350
(81)
55
43
5
15
2,036
393
(138)
6
134
306
387
1,197
72
30
2,387
(351)
6
261
(66)
(552)
(8)
(544)
12
229
(785)
1,156
1,082
—
277
279
889
8
78
6
92
3,867
528
651
62
2
455
683
—
241
54
2,676
1,191
2
296
56
837
1
836
6
36
794
700
1,322
220
75
567
(2)
79
169
1
7
3,138
568
173
73
29
470
184
—
75
29
1,601
1,537
3
294
63
1,177
7
1,170
10
136
1,024
4,334
3,475
859
2,004
1,471
5,104
3,810
1,294
2,051
1,759
$
3,978
$
2,950
$
1,028
$
1,608
$
1,342
Includes impairment expense of $42 million related to two equity method investments in 2019.
(1)
(2) Non-GAAP measure. See reconciliation below for the most directly comparable GAAP measures. Excludes adjusted
EBITDA and DCF adjustments attributable to Predecessor.
(3) Non-GAAP measure. See reconciliation below for the most directly comparable GAAP measures. Includes adjusted
EBITDA and DCF adjustments attributable to Predecessor.
73
(In millions)
2019
2018
2017
Reconciliation of Adjusted EBITDA attributable to MPLX LP
and DCF attributable to GP and LP unitholders from Net
income:
Net income
$
Provision for income taxes
Amortization of deferred financing costs
Loss on extinguishment of debt
Net interest and other financial costs
Income from operations
Depreciation and amortization
Non-cash equity-based compensation
Impairment expense
Income from equity method investments(1)
Distributions/adjustments related to equity method
investments
Unrealized derivative (gains)/losses(2)
Acquisition costs
Other
Adjusted EBITDA
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to Predecessor(3)
Adjusted EBITDA attributable to MPLX LP
Deferred revenue impacts
Net interest and other financial costs
Maintenance capital expenditures
Maintenance capital expenditures reimbursements
Equity method investment capital expenditures paid out
Other
Portion of DCF adjustments attributable to Predecessor(2)
DCF
Preferred unit distributions(4)
DCF attributable to GP and LP unitholders
Adjusted EBITDA attributable to Predecessor(3)
Portion of DCF adjustments attributable to Predecessor(3)
DCF attributable to GP and LP unitholders (including
Predecessor results)
$
1,462
—
42
—
873
2,377
1,254
22
1,197
(290)
562
(1)
14
1
5,136
(32)
(770)
4,334
94
(873)
(262)
53
(28)
12
159
3,489
(122)
3,367
770
(159)
$
2,006
8
55
46
613
2,728
867
23
—
(247)
458
(5)
4
—
3,828
(18)
(335)
3,475
28
(613)
(175)
8
(31)
8
81
2,781
(85)
2,696
335
(81)
836
1
53
—
301
1,191
683
15
—
(78)
231
6
11
—
2,059
(8)
(47)
2,004
33
(301)
(103)
—
(13)
6
2
1,628
(65)
1,563
47
(2)
$
3,978
$
2,950
$
1,608
Includes impairment expense of $42 million related to two equity method investments in 2019.
(1)
(2) MPLX makes a distinction between realized and 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.
(3) The Adjusted EBITDA and DCF adjustments related to Predecessor are excluded from Adjusted EBITDA attributable to
(4)
MPLX LP and DCF attributable to GP and LP unitholders prior to the acquisition dates.
Includes MPLX distributions declared on the Series A and Series B preferred units as well as cash distributions earned
by the Series B preferred (as the Series B preferred units are declared and payable semi-annually) assuming a distribution
is declared by the Board of Directors. Cash distributions declared/to be paid to holders of the Series A and Series B
preferred units are not available to common unitholders.
74
(In millions)
2019
2018
2017
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
Changes in working capital items
All other, net
Non-cash equity-based compensation
Net gain/(loss) on disposal of assets
Net interest and other financial costs
Loss on extinguishment of debt
Current income taxes
Asset retirement expenditures
Unrealized derivative (gains)/losses(1)
Acquisition costs
Other adjustments to equity method investment distributions
Other
Adjusted EBITDA
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to Predecessor(2)
Adjusted EBITDA attributable to MPLX LP
Deferred revenue impacts
Net interest and other financial costs
Maintenance capital expenditures
Maintenance capital expenditures reimbursements
Equity method investment capital expenditures paid out
Other
Portion of DCF adjustments attributable to Predecessor(2)
DCF
Preferred unit distributions(3)
DCF attributable to GP and LP unitholders
Adjusted EBITDA attributable to Predecessor(2)
Portion of DCF adjustments attributable to Predecessor(2)
DCF attributable to GP and LP unitholders (including
Predecessor results)
$
$
4,082
108
(9)
22
6
873
—
2
1
(1)
14
37
1
5,136
(32)
(770)
4,334
94
(873)
(262)
53
(28)
12
159
3,489
(122)
3,367
770
(159)
$
3,071
31
(5)
23
(3)
613
46
—
7
(5)
4
46
—
3,828
(18)
(335)
3,475
28
(613)
(175)
8
(31)
8
81
2,781
(85)
2,696
335
(81)
1,907
(147)
(28)
15
—
301
—
2
2
6
11
(10)
—
2,059
(8)
(47)
2,004
33
(301)
(103)
—
(13)
6
2
1,628
(65)
1,563
47
(2)
$
3,978
$
2,950
$
1,608
(1) MPLX makes a distinction between realized and 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.
(2) The Adjusted EBITDA and DCF adjustments related to Predecessor are excluded from Adjusted EBITDA attributable to
(3)
MPLX LP and DCF attributable to GP and LP unitholders prior to the acquisition dates.
Includes MPLX distributions declared on the Series A and Series B preferred units as well as cash distributions earned
by the Series B preferred (as the Series B preferred units are declared and payable semi-annually) assuming a distribution
is declared by the Board of Directors. Cash distributions declared/to be paid to holders of the Series A and Series B
preferred units are not available to common unitholders.
75
2019 Compared to 2018
Service revenue increased $642 million in 2019 compared to 2018, of which $490 million is due to ANDX being
included in 2019 results for the full year, but only for the last three months of 2018. Additionally, higher fees
from higher volumes in the Marcellus, Southwest and Bakken regions, partially offset by lower cost
reimbursement revenue in the Marcellus region resulted in a net increase of $130 million. The remainder of the
variance is related to a slight increase in volume and transportation rates of crude and refined products shipped.
Service revenue-related parties increased $1,051 million in 2019 compared to 2018, of which $731 million is due
to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The
remaining variance was primarily due to an additional $74 million of revenue from the acquisition of MPLX
Refining Logistics LLC (“Refining Logistics”) and MPLX Fuels Distribution LLC (“Fuels Distribution”) on
February 1, 2018, as well as from annual fee escalations; $98 million from increased volume and transportation
rates of crude and refined product shipped; a $24 million increase from additional marine vessels; $8 million
from storage services revenue due to increased capacity; $16 million from increased terminal throughput; and
$2 million from the recognition of revenue related to volume deficiencies. The remaining variance is due to
reclassifications of certain lease revenue between rental income and service revenue as well as to other
miscellaneous items.
Rental income increased $36 million in 2019 compared to 2018, of which $13 million is due to ANDX being
included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance was
primarily due to an increase from the acquisition of the Mt. Airy Terminal as well as increased volumes in the
Marcellus region.
Rental income-related parties increased $350 million in 2019 compared to 2018, of which $389 million is due to
ANDX being included in 2019 results for the full year, but only for the last three months of 2018. Also
contributing to the variance was an additional $46 million of revenue from the acquisition of Refining Logistics;
an additional $6 million from the completion of a new butane cavern; a $3 million increase in terminal
throughput; and an additional $5 million from the acquisition of the Mt. Airy Terminal. These increases were
offset by a $96 million decrease due to reclassification of certain lease revenue between rental income and
service revenue.
Service revenue-product related, product sales and product sales-related parties decreased $106 million in 2019
compared to 2018, primarily due to lower prices in the Southwest, Southern Appalachia and Marcellus region of
$422 million offset by volume increases in the Southwest of $162 million. A portion of the volume increase in
the Southwest was offset by a volume decrease due to downtime at the Javelina facility. The overall decrease was
also offset by an increase of $137 million due to ANDX being included in 2019 results for the full year, but only
for the last three months of 2018 and by an increase of $22 million due to stronger margins in the wholesale fuels
business. The remainder of the variance is due to a decrease from commodity contracts in 2018.
Income (loss) from equity method investments increased $43 million in 2019 compared to 2018, of which
$30 million was due to ANDX being included in 2019 results for the full year, but only for the last three months
of 2018. The remaining variance was primarily due to increases in our MarEn Bakken Company, LLC, Sherwood
Midstream, MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”), Lincoln
Pipeline LLC, and Utica EMG joint ventures, partially offset by decreases in our Explorer Pipeline Co., Three
Rivers Gathering LLC, Ohio Condensate Company, LLC, and LOCAP L.L.C. joint ventures. This includes
impairment charges recognized related to our Ohio Condensate Company, L.L.C. and Three Rivers Gathering
LLC joint ventures of $42 million.
Other income and Other income-related parties increased $20 million in 2019 compared to 2018. This variance
was primarily due to an increase in management fees from our joint ventures and net gains on sales of assets
during the year.
Cost of revenues increased $393 million in 2019 compared to 2018. This variance was primarily due to an
increase of $400 million due to ANDX being included in 2019 results for the full year, but only for the last
three months of 2018. The remaining variance was primarily due to increased costs to operate new and
76
expanded assets such as the Mt. Airy Terminal, the expanded Ozark pipeline, additional marine vessels, and the
completed Robinson Butane cavern. There was also increased spend on projects, as well as other miscellaneous
items. These increases were partially offset by decreases in reimbursable costs as well as certain employee-
related costs.
Purchased product costs decreased $138 million in 2019 compared to 2018. This was primarily due to lower
prices of $280 million in the Southwest and Southern Appalachia as well as a decrease in unrealized derivative
gains from prior year. These decreases were partially offset by higher volumes of $119 million in the Southwest
and Southern Appalachia and an increase of $20 million is due to ANDX being included in 2019 results for the
full year, but only for the last three months of 2018.
Rental cost of sales increased $6 million in 2019 compared to 2018 primarily due to the acquisition of the Mt.
Airy Terminal.
Rental cost of sales-related parties increased $134 million in 2019 compared to 2018, of which $116 million was
due to the Merger. The remainder of the variance relates to the acquisition of the Mt. Airy Terminal and other
miscellaneous items.
Purchases-related parties increased $306 million in 2019 compared to 2018, of which $204 million was due to
the Merger. The remaining variance was primarily due the acquisition of Refining Logistics and Fuels
Distribution as well as to increases in certain employee-related costs.
Depreciation and amortization expense increased $387 million in 2019 compared to 2018, of which $277 million
was due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The
acquisitions of Refining Logistics and the Mt. Airy Terminal resulted in an increase of approximately
$25 million with the remainder of the variance being related to additions to in-service property, plant and
equipment throughout the year.
Impairment expense increased $1,197 million in 2019 compared to 2018. This variance is due to the fourth
quarter of 2019 goodwill impairment.
General and administrative expenses increased $72 million in 2019 compared to 2018. This variance was
primarily due to an increase of $65 million due to ANDX being included in 2019 results for the full year, but
only for the last three months of 2018; this includes $14 million of acquisition costs related to the Merger. The
remaining variance is due to the acquisition of Refining Logistics and Fuels Distribution and other employee-
related costs.
Other taxes increased $30 million in 2019 compared to 2018. This variance was primarily due to ANDX being
included in 2019 results for the full year, but only for the last three months of 2018.
Interest expense and other financial costs (including related parties) increased $201 million in 2019 compared to
2018. The increase is primarily due to increased interest and financing costs related to the senior notes issued in
the fourth quarter of 2018, interest on the new variable rate notes and term loan issued in the third quarter of
2019 and inclusion of the ANDX senior notes during the full year 2019 but only for the last three months of
2018.
2018 Compared to 2017
Service revenue increased $700 million in 2018 compared to 2017, of which $152 million was attributable to the
Merger. The remaining variance was primarily due to a $167 million increase in fees from volume growth in the
Marcellus and the Southwest regions; a $13 million increase related to increases in volume and transportation
rates of crude oil and refined products shipped, partially attributable to the Ozark pipeline acquisition and
expansion; and an increase of $369 million due to ASC 606 gross ups. The remainder of the change can be
attributable to impacts related to ASC 606 classification changes and other miscellaneous items.
Service revenue-related parties increased $1,322 million in 2018 compared to 2017, of which $245 million
was attributable to the Merger. The remaining variance was primarily due to a $947 million increase from the
acquisition of Refining Logistics and Fuels Distribution; a $100 million increase related to higher volumes
77
and transportation rates of related-party crude oil and refined products shipped, partially attributable to the
Ozark pipeline acquisition and expansion; a $15 million increase from additional boats and barges; a
$10 million increase from higher terminal throughputs; and a $12 million increase in the recognition of
revenue related to volume deficiencies. These increases were partially offset by ASC 606 classification
changes of $7 million.
Service revenue-product related increased $220 million in 2018 compared to 2017, of which $22 million was
attributable to the Merger. The remaining variance was primarily due to ASC 606 classification and non-cash
changes.
Rental income increased $75 million in 2018 compared to 2017, of which $3 million was attributable to the
Merger. The remaining variance was primarily due to a $6 million increase from the acquisition of the Mt. Airy
Terminal as well as $65 million related to higher ASC 606 cost reimbursements.
Rental income-related parties increased $567 million in 2018 compared to 2017, of which $128 million was
attributable to the Merger. The remaining variance was primarily due to a $411 million increase from the
acquisition of Refining Logistics with the remainder of the variance being primarily related to the acquisition of
additional marine vessels and the completion of the Robinson Butane Cavern.
Product sales and product sales-related parties increased $77 million in 2018 compared to 2017, of which
$23 million was attributable to the Merger. The remaining variance was primarily due to higher prices in the
Southwest, Northeast and Marcellus regions of $113 million, volume impacts of $9 million as well as a change in
unrealized gains associated with derivatives of $10 million, driven by favorable product hedges in 2018
compared to unfavorable product hedges in 2017. These increases were partially offset by ASC 606 classification
and non-cash changes of $78 million.
Income (loss) from equity method investments increased $169 million in 2018 compared to 2017, of which
$7 million was attributable to the Merger. The remaining variance was primarily due to the MarEn Bakken
acquisition, the Joint-Interest Acquisition, growth in the Jefferson Dry Gas joint venture as a result of an increase
in dry gas gathering volumes, as well as growth in the Sherwood Midstream joint venture due to additional plants
coming online. This was partially offset by a decrease in our Utica EMG joint venture as a result of decreased
volumes and the buy-out of an equity method investment partner.
Other income and Other income-related parties increased $8 million in 2018 compared to 2017. This variance
was primarily due to an increase in management fees from our joint ventures.
Cost of revenues increased $568 million in 2018 compared to 2017, of which $148 million was attributable to the
Merger. The remaining variance was primarily due to ASC 606 gross-ups of $369 million, higher repairs and
maintenance and operating costs in the Marcellus and Southwest regions of $32 million as well as from the
acquisition of Refining Logistics and the acquisition and expansion of the Ozark pipeline.
Purchased product costs increased $173 million in 2018 compared to 2017, of which a $21 million decrease was
attributable to the Merger. The remaining variance was primarily due to higher NGL and gas prices and volumes
of approximately $68 million and $36 million, respectively, primarily in the Southwest and Northeast areas; and
an increase due to ASC 606 imbalances and non-cash consideration of approximately $105 million with the
remaining variance being related to derivative activity.
Rental cost of sales and rental cost of sales-related parties increased $102 million in 2018 compared to 2017, of
which $26 million was attributable to the Merger. The remaining variance was primarily due to ASC 606 gross
ups of $65 million in addition to the acquisition of Mt. Airy Terminal and increased maintenance, repairs, and
operating costs.
Purchases-related parties increased $470 million in 2018 compared to 2017, of which $65 million was
attributable to the Merger. The remaining variance was primarily due to $372 million from the acquisition of
Refining Logistics and Fuels Distribution with the remainder of the variance primarily being related to increases
in employee-related costs.
78
Depreciation and amortization expense increased $184 million in 2018 compared to 2017, of which $101 million
was attributable to the Merger. The remaining variance was primarily due to the acquisitions of Refining
Logistics and the Mt. Airy Terminal for approximately $76 million, as well as additions to in-service property,
plant and equipment, slightly offset by accelerated depreciation expense incurred in 2017 related to
decommissioned assets.
General and administrative expenses increased $75 million in 2018 compared to 2017, of which $25 million was
attributable to the Merger. The remaining variance was primarily due to the acquisition of Refining Logistics and
Fuels Distribution as well as increased labor and benefits costs.
Other taxes increased $29 million in 2018 compared to 2017, of which $11 million was attributable to the
Merger. The remaining variance was primarily due to the acquisition of Refining Logistics as well as the Ozark
pipeline acquisition and expansion.
Interest expense and other financial costs increased $360 million in 2018 compared to 2017, of which
$53 million was attributable to the Merger. The remaining variance was primarily due to increased interest
expense due to the new senior notes issued in February 2018 and November 2018 and the loss on debt
extinguishment associated with the redemption of all of the outstanding 5.5 percent senior notes due February
2023.
SEGMENT REPORTING
We classify our business in the following reportable segments: L&S and G&P. Segment Adjusted EBITDA
represents Adjusted EBITDA attributable to the reportable segments. Amounts included in net income and
excluded from Segment Adjusted EBITDA include: (i) depreciation and amortization; (ii) provision/(benefit) for
income taxes; (iii) amortization of deferred financing costs; (iv) extinguishment of debt; (v) non-cash equity-
based compensation; (vi) impairment expense; (vii) net interest and other financial costs; (viii) income/(loss)
from equity method investments; (ix) distributions and adjustments related to equity method investments;
(x) unrealized derivative gains/(losses); (xi) acquisition costs; (xii) noncontrolling interests; and (xiii) other
adjustments as deemed necessary. 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 tied to the operational performance of the
segment.
The tables below present information about Segment Adjusted EBITDA for the reported segments for the years
ended December 31, 2019, 2018 and 2017.
79
L&S Segment
L&S Segment Financial Highlights (in millions)
$5,352
$3,672
$1,562
$2,752
$1,924
2019
2018
2017
2019
2018
$602
2017
$3,351
$2,319
$822
2019
2018
2017
Revenues and other income(1)
Income from operations(1)
Segment Adjusted EBITDA(1)
(1)
Includes results of Predecessor.
(In millions)
2019
2018
$ Change
2017
$ Change
Service revenue
Rental income
Product related revenue
Income from equity method investments
Other income
$
Total segment revenues and other income
Cost of revenues
Purchases - related parties
Depreciation and amortization
General and administrative expenses
Other taxes
Segment income from operations
Depreciation and amortization
Income from equity method investments
Distributions/adjustments related to equity
method investments
Acquisition costs
Non-cash equity-based compensation
Other
Adjusted EBITDA attributable to Predecessor
3,765
1,235
91
200
61
5,352
966
872
503
198
61
2,752
503
(200)
267
14
14
1
(603)
$
2,575
856
23
171
47
3,672
536
698
308
161
45
1,924
308
(171)
242
4
12
—
(262)
$
$ 1,190
379
68
29
14
1,680
430
174
195
37
16
828
195
(29)
25
10
2
1
(341)
1,200
279
—
36
47
1,562
370
299
163
106
22
602
163
(36)
76
11
6
—
(47)
$
1,375
577
23
135
—
2,110
166
399
145
55
23
1,322
145
(135)
166
(7)
6
—
(215)
Segment Adjusted EBITDA(1)
$
2,748
$
2,057
$
691
$
775
$
1,282
(1) See the Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders
from Net income table for the reconciliation to the most directly comparable GAAP measure.
2019 Compared to 2018
Service revenue increased $1,190 million in 2019 compared to 2018, of which $848 million is due to ANDX
being included in 2019 results for the full year, but only for the last three months of 2018. Other impacts include
an additional $74 million of revenue from the acquisition of Refining Logistics and Fuels Distribution on
February 1, 2018, as well as from annual fee escalations; $122 million from increased volume and transportation
rates of crude and refined product shipped; $24 million from additional marine vessels; $8 million from storage
services revenue due to increased capacity; $16 million from increased terminal throughput; and $2 million from
the recognition of revenue related to volume deficiencies. The remaining variance is due to a $89 million
increase due to reclassification of certain lease revenue between rental income and service revenue as well as to
other miscellaneous items.
80
Rental income increased $379 million in 2019 compared to 2018, of which $402 million is due to ANDX being
included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance was
primarily due to an additional $46 million of revenue from the acquisition of Refining Logistics on February 1,
2018; an additional $6 million from the completion of a new butane cavern; a $3 million increase in terminal
throughput; and an additional $21 million from the acquisition of the Mt. Airy Terminal. These increases were
offset by a $96 million decrease due to reclassification of certain lease revenue between rental income and
service revenue and other miscellaneous items.
Product related revenue increased $68 million in 2019 compared to 2018, of which $46 million is due to ANDX
being included in 2019 results for the full year, but only for the last three months of 2018. The remaining
variance is primarily due to stronger margins in the wholesale fuels business.
Income from equity method investments increased $29 million in 2019 compared to 2018, of which $19 million
is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The
remaining variance was due to increases in our MarEn Bakken Company, LLC and Lincoln Pipeline LLC joint
ventures due to increased throughput volumes partially offset by decreases in our Explorer Pipeline Co. joint
venture due to an upward adjustment to income in 2018 for a change in the corporate tax rate and our LOCAP
LLC joint venture due to lower throughput volumes.
Other Income increased $14 million in 2019 compared to 2018, primarily related to a gain recognized on the sale
of assets and other miscellaneous items.
Cost of revenues increased $430 million in 2019 compared to 2018, of which $396 million is due to ANDX
being included in 2019 results for the full year, but only for the last three months of 2018. The remaining
variance was primarily due to increased costs to operate new and expanded assets such as the Mt. Airy Terminal,
the expanded Ozark pipeline, additional marine vessels, and the completed Robinson Butane cavern. There was
also increased spend on projects, as well as other miscellaneous items. These increases were partially offset by a
decrease due to certain employee-related costs.
Purchases - related parties increased $174 million in 2019 compared to 2018, of which $83 million is due to
ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining
variance was primarily due to the acquisition of Refining Logistics and Fuels Distribution and increased
employee-related costs.
Depreciation and amortization increased $195 million in 2019 compared to 2018, of which $162 million is due to
ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining
variance was primarily due to the acquisitions of Refining Logistics and the Mt. Airy Terminal as well as
additions to in-service property, plant and equipment throughout the year.
General and administrative expenses increased $37 million in 2019 compared to 2018, of which $34 million is
due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. There
was also an increase due to acquisition costs incurred during 2019, which were offset by lower employee related
costs in the fourth quarter of 2019 when compared to the fourth quarter of 2018 as it relates to ANDX.
Other taxes increased $16 million in 2019 compared to 2018 due to ANDX being included in 2019 results for the
full year, but only for the last three months of 2018.
2018 Compared to 2017
Service revenue increased $1,375 million in 2018 compared to 2017, of which $286 million was attributable to
the Merger. The remaining variance was primarily due to an additional $947 million of revenue from the
acquisition of Refining Logistics and Fuels Distribution; a $113 million increase in volume and transportation
rates of crude and refined product shipped, partially attributable to the Ozark pipeline acquisition and
expansion; a $15 million increase from additional marine vessels; an additional $10 million from increased
terminal throughput; and a $12 million increase in the recognition of revenue related to volume deficiencies.
81
These increases were partially offset by ASC 606 classification changes and other miscellaneous items.
Rental income increased $577 million in 2018 compared to 2017, of which $131 million was attributable to the
Merger. The remaining variance was primarily due to an additional $411 million of revenue from the acquisition
of Refining Logistics and Fuels Distribution, an additional $16 million from the completion of a new butane
cavern, a $14 million increase from additional marine vessels, and an additional $6 million from the acquisition
of the Mt. Airy Terminal.
Product related revenue increased $23 million in 2018 compared to 2017, of which $9 million was attributable to
the Merger. The remaining variance was primarily due to ASC 606 classification changes.
Income from equity method investments increased $135 million in 2018 compared to 2017, of which $5 million
was attributable to the Merger. The remaining variance was primarily due to the Joint-Interest Acquisition and
the acquisition of MarEn Bakken.
Cost of revenues increased $166 million in 2018 compared to 2017, of which $135 million was attributable to the
Merger. The remaining variance was primarily due to an additional $13 million from the acquisition of Refining
Logistics and Fuels Distribution, $7 million from the acquisition of Ozark pipeline and related expansion,
$4 million from the acquisition of the Mt. Airy Terminal and $7 million for other miscellaneous items.
Purchases - related parties increased $399 million in 2018 compared to 2017, of which $13 million was
attributable to the Merger. The remaining variance was primarily due to a $372 million increase from the
acquisition of Refining Logistics and Fuels Distribution as well as an increase in employee-related costs.
Depreciation and amortization increased $145 million in 2018 compared to 2017, of which $68 million was
attributable to the Merger. The remaining variance was primarily due to the acquisitions of Refining Logistics,
Fuels Distribution and the Mt. Airy Terminal.
General and administrative expenses increased $55 million in 2018 compared to 2017, of which $19 million was
attributable to the Merger. The remaining variance was primarily due to an additional $22 million from the
acquisition of Refining Logistics and Fuels Distribution as well as increased other miscellaneous expenses.
Other taxes increased $23 million in 2018 compared to 2017, of which $9 million was attributable to the Merger.
The remaining variance was primarily due to the acquisition of Refining Logistics and Fuels Distribution as well
as the Ozark pipeline acquisition and expansion.
82
G&P Segment
$3,689
$3,333
$2,305
G&P Segment Financial Highlights (in millions)
$804
$589
$(375)
$1,753
$1,491
$1,229
2019
2018
2017
2019
2018
2017
2019
2018
2017
Revenues and other income(1)
Income from operations(1)
Segment Adjusted EBITDA(1)
(1)
Includes results of Predecessor.
(In millions)
2019
2018
$ Change
2017
$ Change
Service revenue
Rental income
Product related revenue
Income from equity method investments
Other income
Total segment revenues and other income
$
Cost of revenues
Purchased product costs
Purchases - related parties
Depreciation and amortization
Impairment expense
General and administrative expenses
Other taxes
Income/(loss) from operations
Depreciation and amortization
Impairment expense
Income from equity method investments
Distributions/adjustments related to equity
method investments
Unrealized derivative (gains)/losses(1)
Non-cash equity-based compensation
Adjusted EBITDA attributable to noncontrolling
interests
Adjusted EBITDA attributable to Predecessor
2,188
349
997
90
65
3,689
829
686
359
751
1,197
190
52
(375)
751
1,197
(90)
295
(1)
8
(32)
(167)
$
1,685
342
1,171
76
59
3,333
726
824
227
559
—
155
38
804
559
—
(76)
216
(5)
12
(19)
(73)
$
503
7
(174)
14
6
356
103
(138)
132
192
1,197
35
14
(1,179)
192
1,197
(14)
79
4
(4)
(13)
(94)
$
1,038
277
897
42
51
2,305
222
651
156
520
—
135
32
589
520
—
(42)
155
6
9
(8)
—
$
647
65
274
34
8
1,028
504
173
71
39
—
20
6
215
39
—
(34)
61
(11)
3
(11)
(73)
Segment Adjusted EBITDA(2)
$
1,586
$
1,418
$
168
$
1,229
$
189
(1) MPLX makes a distinction between realized and 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.
(2) See the Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders
from Net income table for the reconciliation to the most directly comparable GAAP measure.
83
2019 Compared to 2018
Service revenue increased $503 million in 2019 compared to 2018, of which $375 million is due to ANDX being
included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance is a
result of higher fees from higher volumes of $189 million in the Marcellus, Southwest and Bakken regions
partially offset by lower cost reimbursement revenue in the Marcellus region of $59 million and other
miscellaneous decreases.
Rental income increased $7 million in 2019 compared to 2018. This variance was primarily due to increased
volumes in the Marcellus region.
Product related revenue decreased $174 million in 2019 compared to 2018 due to lower prices in the Southwest,
Southern Appalachia, Marcellus, Bakken and Rockies regions of $422 million offset by volume increases in the
Southwest, Bakken and Rockies of $162 million. A portion of the volume increase in the Southwest was offset
by a volume decrease due to downtime at the Javelina facility. The overall decrease was also offset by an
increase of $91 million due to ANDX being included in 2019 results for the full year, but only for the last three
months of 2018. The remainder of the variance is due to a decrease from commodity contracts in 2018.
Income from equity method investments increased $14 million in 2019 compared to 2018, of which $11 million
is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. There
was also an increase of $49 million related to three of our joint ventures. The Sherwood Midstream joint venture
increased due to additional plants coming online at the end of 2018 while the Jefferson Dry Gas joint venture
increased as a result of higher dry gas gathering volumes and assets placed in service and the Utica EMG joint
venture increased as a result of assets written off in the prior period. These increases were partially offset by a
decrease in our Ohio Condensate Company, LLC and Three Rivers Gathering LLC joint ventures, which had
impairments of approximately $42 million in 2019. Additionally, Delaware Basin Residue, LLC joint venture
decreased due to unrealized derivative losses.
Other income increased $6 million in 2019 compared to 2018. This variance was primarily due to an increase in
management fees from our joint ventures and net gains on sales of assets during the year.
Cost of revenues increased $103 million in 2019 compared to 2018, of which $122 million is due to ANDX
being included in 2019 results for the full year, but only for the last three months of 2018. Additionally, we
experienced higher repairs and maintenance costs in the Southwest and Marcellus regions of $37 million which
were offset by lower reimbursable costs of $59 million in the same regions.
Purchased product costs decreased $138 million in 2019 compared to 2018. This was primarily due to lower
prices of $280 million in the Southwest and Southern Appalachia. These decreases were partially offset by higher
volumes of $119 million in the Southwest and Southern Appalachia and an increase of $20 million is due to
ANDX being included in 2019 results for the full year, but only for the last three months of 2018, as well as a
decrease in unrealized derivative gains from prior year.
Purchases - related parties increased $132 million in 2019 compared to 2018, of which $121 million is due to
ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining
variance is attributable to an increases in employee-related costs.
Depreciation and amortization increased $192 million in 2019 compared to 2018, of which $115 million is due to
ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining
variance is attributable to additions to in-service property, plant and equipment throughout 2018 and 2019 and
accelerated depreciation recorded in 2019, which was slightly offset by write-downs of equipment no longer in
use in the prior year.
Impairment expense increased $1,197 million as a result of our 2019 annual impairment test over goodwill. The
impairment was primarily driven by the slowing of drilling activity, which has reduced production growth
forecasts from our producer customers.
84
General and administrative expenses increased $35 million in 2019 compared to 2018, of which $20 million is
due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The
remainder of the variance is attributable to higher employee related costs.
Other taxes increased $14 million in 2019 compared to 2018, of which $9 million is due to ANDX being
included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance is
attributable to higher property taxes.
2018 Compared to 2017
Service revenue increased $647 million in 2018 compared to 2017, of which $111 million was attributable to the
Merger. The remaining variance was primarily due to ASC 606 cost reimbursements of $369 million and higher
fees from higher volumes in the Marcellus and Southwest regions of $167 million.
Rental income increased $65 million in 2018 compared to 2017. This variance was primarily due to higher ASC
606 cost reimbursements of $65 million.
Product related revenue increased $274 million in 2018 compared to 2017, of which $36 million was attributable
to the Merger. The remaining variance was primarily due to higher prices in the Southwest, Northeast and
Marcellus regions of $113 million, volume impacts of $9 million as well as ASC 606 classification and non-cash
changes of $106 million. In addition, there was a change in unrealized gains associated with derivatives of
$10 million, driven by favorable product hedges in 2018 compared to unfavorable product hedges in 2017.
Income from equity method investments increased $34 million in 2018 compared to 2017, of which $2 million
was attributable to the Merger. The remaining variance was primarily due to growth in the Jefferson Dry Gas
joint venture as a result of an increase in dry gas gathering volumes as well as growth in the Sherwood
Midstream joint venture due to additional plants coming online. This was partially offset by a decrease in our
Utica EMG joint venture as a result of decreased volumes and the buy-out of an equity method investment
partner.
Other income increased $8 million in 2018 compared to 2017. This variance was primarily due to an increase in
management fees from our joint ventures.
Cost of revenues increased $504 million in 2018 compared to 2017, of which $39 million was attributable to the
Merger. The remaining variance was primarily due to ASC 606 gross ups of $433 million as well as higher
repairs and maintenance and operating costs in the Marcellus and Southwest regions of $32 million.
Purchased product costs increased $173 million in 2018 compared to 2017. This variance was primarily due to
higher prices of $68 million and volumes of $36 million in the Southwest and Northeast as well as ASC 606
imbalances and non-cash consideration of $105 million. These increases were partially offset by a $21 million
decrease due to the Merger and unrealized gains and losses associated with derivatives of $15 million, which was
driven by NGL prices creating a smaller fractionation spread.
Purchases - related parties increased $71 million in 2018 compared to 2017, of which $52 million was
attributable to the Merger. The remaining variance was primarily due to employee-related costs.
Depreciation and amortization increased $39 million in 2018 compared to 2017, of which $33 million was
attributable to the Merger. The remaining variance primarily relates to accelerated depreciation taken in 2017 of
approximately $33 million offset by additions to in-service property, plant and equipment throughout 2017 and
2018 as well as a write-down of construction in progress projects of approximately $10 million, which are no
longer expected to be completed.
General and administrative expenses increased $20 million in 2018 compared to 2017, of which $6 million was
attributable to the Merger. The remaining variance was primarily due to increases in labor and benefits costs and
general increases in office expense.
85
Other taxes increased $6 million in 2018 compared to 2017, of which $2 million was attributable to the Merger.
The remaining variance was primarily due to an increase in property taxes.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Our cash, cash equivalents and restricted cash balance was $15 million at December 31, 2019, compared to
$85 million at December 31, 2018. 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 for the past
three years were as follows:
(In millions)
Net cash provided by/(used in):
Operating activities
Investing activities
Financing activities
Total
2019
2018
2017
$
$
$
4,082
(3,063)
(1,089)
$
3,071
(2,878)
(117)
(70)
$
76
$
1,907
(2,308)
171
(230)
Cash Flows Provided by Operating Activities. Net cash provided by operating activities increased $1,011 million
in 2019 compared to 2018. This change is a result of a decrease in net income of $544 million offset by a
goodwill impairment recognized in the amount of approximately $1.2 billion. Changes related to depreciation
and amortization, equity method investments and working capital items also had an impact on the overall change
from prior year, most of which were directly impacted by the Merger.
Net cash provided by operating activities increased $1,164 million in 2018 compared to 2017, of which
$245 million is due to the Merger. The majority of the remaining $919 million increase is related to the increase
in net income net of non-cash adjustments of approximately $931 million period over period. 2018 includes
Refining Logistics and Fuels Distribution as of February 1, 2018 as well as Joint-Interest Acquisition assets as of
September 1, 2017.
Cash Flows Used in Investing Activities. Net cash used in investing activities increased $185 million in 2019
compared to 2018 primarily due to spending related to the capital budget as well as increased investments in
equity method investments, offset by a decrease in cash used for acquisitions due to the Mt. Airy Terminal
acquisition in 2018.
Net cash used in investing activities increased $570 million in 2018 compared to 2017, of which $192 million is
due to the Merger. The majority of the remaining $378 million increase was primarily due to the Mt. Airy
Terminal acquisition as well as various capital projects that have taken place throughout 2018 in-line with
MPLX’s capital growth plan. The impact of this activity in 2018 was partially offset by the Ozark pipeline
acquisition and higher investments in unconsolidated affiliates which occurred in 2017.
Cash Flows Used in and Provided by Financing Activities. The change in financing activities was a
$1,089 million use of cash in 2019 compared to a $117 million use of cash in 2018. The uses of cash in 2019
primarily consisted of $8,719 million of repayments of borrowings under loan agreements with MPC, the
$500 million redemption of the 5.5 percent senior notes due October 2019, $7,424 million of repayments under
the MPLX and ANDX Credit Agreements and including payments on financing leases, debt issuance costs of
$20 million, distributions of $102 million and $30 million to preferred unitholders and noncontrolling interests
respectively, distributions of $2,435 million to unitholders related to the increase in units outstanding as well as
an increase in the distribution per limited partner unit, and distributions of $502 million to common and preferred
unitholders of the Predecessor. This was partially offset by sources of cash primarily related to $6,174 million of
proceeds from the MPLX and ANDX Credit Agreements, $2.0 billion of net proceeds from the floating rate
senior notes issued on September 9, 2019, $1.0 billion of net proceeds from the term loan, $9,313 million of net
proceeds from draws on loan agreements with MPC, and $169 million from contributions from MPC and
noncontrolling interests.
86
The change in financing activities was a $117 million use of cash in 2018 compared to a $171 million source of
cash in 2017. For 2018, $44 million of the $117 million use of cash was due to the Merger. The remaining
$73 million use of cash in 2018 primarily consisted of distributions to MPC of $4.1 billion for the acquisition of
Refining Logistics and Fuels Distribution, the $4.1 billion repayment of the 364-day term loan facility, the
$4,347 million repayment of borrowings under the MPC Loan Agreement, the $750 million redemption of the
5.5 percent senior notes due February 2023 and $14 million of related debt extinguishment charges, the
$1,915 million repayment of the MPLX Credit Agreement, debt issuance costs and discounts of $76 million and
$74 million respectively, distributions of $71 million and $17 million to preferred unitholders and noncontrolling
interests respectively, and distributions of $1,819 million to unitholders and our general partner due mainly to the
increase in units outstanding as well as an increase in the distribution per limited partner unit. This was partially
offset by sources of cash primarily related to $1,410 million of proceeds from the MPLX Credit Agreement,
$5.5 billion of net proceeds from the senior notes issued on February 8, 2018, $2.25 billion of net proceeds from the
senior notes issued on November 15, 2018, $4.1 billion of net proceeds under the 364-day term loan facility that
was drawn on February 1, 2018, and $3,962 million of net proceeds from draws on the MPC Loan Agreement.
The sources of cash in 2017 primarily consisted of $2.2 billion of net proceeds from the senior notes issued in
February 2017, $670 million of proceeds under the bank revolving credit facility, $129 million in contributions
from noncontrolling interests, and $483 million of net proceeds from sales of common units under the ATM
Program. These items were partially offset by distributions to MPC of $1.9 billion for the acquisition of HST,
WHC and MPLXT and the Joint-Interest Acquisition, $250 million repayment of the term loan facility,
$165 million repayment of the bank revolving credit facility, distributions of $65 million to preferred unitholders,
and distributions of $1.1 billion to unitholders and our general partner.
Long-term debt borrowings and repayments were a net $1.2 billion source of cash in 2019 compared to a
$6.5 billion source of cash in 2018 and a $2.5 billion source of cash in 2017. During 2019, we used proceeds
from the term loan and floating rate senior notes issued during the year to pay off ANDX’s credit facilities, repay
ANDX’s senior notes maturing in 2019 and for general business purposes. During 2018, we used proceeds from
senior notes issued during the year to redeem $750 million of 5.5 percent senior notes due February 2023, for the
acquisition of Refining Logistics and Fuels Distribution and to repay amounts outstanding under the MPLX
Credit Agreement and MPC Loan Agreement, as well as for general business purposes. During 2017, we used
proceeds from the issuance of the February 2017 senior notes and MPLX Credit Agreement for general business
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 acquisition of the Ozark pipeline and capital
expenditures.
Debt and Liquidity Overview
Credit Agreements
On July 30, 2019, in connection with the closing of the Merger, we amended our previously existing revolving
credit facility (the “MPLX Credit Agreement”) to, among other things, increase the borrowing capacity from
$2.25 billion to $3.5 billion and extend its maturity from July 2022 to July 2024. Borrowings under the MPLX
Credit Agreement bear interest at either the Adjusted LIBOR or the Alternate Base Rate (as defined in the MPLX
Credit Agreement), at our election, plus a specified margin. We are charged various fees and expenses in
connection with the agreement, including administrative agent fees, commitment fees on the unused portion of
the bank revolving credit facility and fees with respect to issued and outstanding letters of credit. The applicable
margins to the benchmark interest rates and certain fees fluctuate based on the credit ratings in effect from time
to time on MPLX’s long-term debt.
The MPLX Credit Agreement includes letter of credit issuing capacity of up to $300 million and swingline
capacity of up to $150 million. The borrowing capacity under the MPLX Credit Agreement may be
increased by up to an additional $1.0 billion, subject to certain conditions, including the consent of lenders
whose commitments would increase. In addition, the maturity date may be extended for up to two additional
one-year periods subject to, among other conditions, the approval of lenders holding the majority of the
commitments then outstanding, provided that the commitments of any non-consenting lenders will
terminate on the then-effective maturity date. During 2019, we borrowed $5,310 million under the MPLX
Credit Agreement, at an average interest rate of 3.547 percent, and repaid $5,310 million of borrowings
87
under the MPLX Credit Agreement. At December 31, 2019, we had no outstanding borrowings under this facility
and had less than $1.0 million in letters of credit outstanding, resulting in total availability of approximately
$3.5 billion, or almost 100 percent of the borrowing capacity.
The MPLX Credit Agreement contains 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) 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. Other covenants
restrict us and/or certain of our subsidiaries from incurring debt, creating liens on our assets and entering into
transactions with affiliates. As of December 31, 2019, we were in compliance with this financial covenant with a
ratio of Consolidated Total Debt to Consolidated EBITDA of 3.9 to 1.0, as well as all other covenants contained
in the MPLX Credit Agreement.
Prior to the Merger, ANDX had revolving credit facilities (the “ANDX credit facilities”) totaling $2.1 billion in
borrowing capacity, which were set to mature January 29, 2021. The ANDX credit facilities were terminated
upon closing of the Merger and repaid with borrowings under the MPLX revolving credit facility. During the
year ended December 31, 2019, there were borrowings of $864 million under the ANDX credit facilities, at an
average interest rate of 4.129 percent, and repayments of $2.1 billion.
For further discussion, see Item 8. Financial Statements and Supplementary Data – Note 17.
Term Loan
On September 26, 2019, MPLX entered into a Term Loan Agreement, which provides for a committed term loan
facility for up to an aggregate of $1.0 billion. Borrowings under the Term Loan Agreement bear interest, at
MPLX’s election, at either (i) the Adjusted LIBO Rate (as defined in the Term Loan Agreement) plus a margin
ranging from 75.0 basis points to 100.0 basis points per annum, depending on MPLX’s credit ratings, or (ii) the
Alternate Base Rate (as defined in the Term Loan Agreement). Amounts borrowed under the Term Loan
Agreement are due and payable on September 26, 2021. As of December 31, 2019, MPLX had drawn the full
$1.0 billion available on the term loan at an average interest rate of 2.561 percent. The proceeds from the
borrowings were used to repay existing indebtedness and for general business purposes.
The Term Loan Agreement contains representations and warranties, affirmative and negative covenants and
events of default that we consider to be customary for an agreement of this type and are substantially similar to
those contained in the MPLX Credit Agreement, including a covenant that requires MPLX’s ratio of
Consolidated Total Debt to Consolidated EBITDA (as both terms are defined in the Term Loan Agreement) for
the four prior fiscal quarters not to exceed 5.0 to 1.0 as of the last day of each fiscal quarter (or during
the six-month period following certain acquisitions, 5.5 to 1.0). Consolidated EBITDA is subject to adjustments
for certain acquisitions completed and capital projects undertaken during the relevant period.
Senior Notes
As of December 31, 2019, we had $19.1 billion in aggregate principal amount of senior notes outstanding. The
increase compared to year-end 2018 resulted primarily from the assumption of ANDX’s senior notes and the
issuance of variable rate senior notes as discussed below. As of December 31, 2019, minimum principal
payments due during the next five years include $1.0 billion to repay our floating rate notes due September 2021,
$1.0 billion to repay our floating rate notes due September 2022, $300 million to repay our 6.250 percent senior
notes due October 2022, $500 million to repay our 3.500 percent senior notes due December 2022, $500 million
to repay our 3.375 percent senior notes due March 2023, $1.0 billion to repay our 4.500 percent senior notes due
July 2023, $450 million to repay our 6.375 percent senior notes due May 2024 and $1.15 billion to repay our
4.875 percent senior notes due December 2024.
88
On September 9, 2019, MPLX issued $2.0 billion aggregate principal amount of floating rate senior notes in a
public offering, consisting of $1.0 billion aggregate principal amount of notes due September 2021 and
$1.0 billion aggregate principal amount of notes due September 2022 (collectively, the “Floating Rate Senior
Notes”). The Floating Rate Senior Notes were offered at a price to the public of 100 percent of par. The Floating
Rate Senior Notes are callable, in whole or in part, at par plus accrued and unpaid interest at any time on or after
September 10, 2020. The proceeds were used to repay MPLX’s existing indebtedness and for general business
purposes. Interest on the Floating Rate Senior Notes is payable quarterly in March, June, September and
December, commencing on December 9, 2019. The interest rate applicable to the floating rate senior notes due
September 2021 is LIBOR plus 0.9 percent per annum. The interest rate applicable to the floating rate senior
notes due September 2022 is LIBOR plus 1.1 percent per annum.
In connection with the Merger, MPLX assumed ANDX’s outstanding senior notes, which had an aggregate
principal amount of $3.75 billion, interest rates ranging from 3.5 percent to 6.375 percent and maturity dates
ranging from 2019 to 2047. On September 23, 2019, approximately $3.06 billion aggregate principal amount of
ANDX’s outstanding senior notes were exchanged for an aggregate principal amount of approximately
$3.06 billion new senior notes (the “Exchange Notes”) issued by MPLX in an exchange offer and consent
solicitation undertaken by MPLX, leaving approximately $690 million aggregate principal of outstanding senior
notes issued by ANDX. Of this, $500 million aggregate principal amount was related to 5.5 percent senior notes
due 2019. The aggregate principal amount of $500 million and accrued interest of $13.75 million was paid on
October 15, 2019 at maturity using net proceeds from the issuance of the Floating Rate Senior Notes and
borrowings under the Term Loan Agreement discussed above and includes interest through the payoff date. The
Exchange Notes consist of $266 million in aggregate principal amount of 6.25 percent senior notes due October
2022, $486 million in aggregate principal amount of 3.5 percent senior notes due December 2022, $381 million
in aggregate principal amount of 6.375 percent senior notes due May 2024, $708 million in aggregate principal
amount of 5.25 percent senior notes due January 2025, $732 million in aggregate principal amount of
4.25 percent senior notes due December 2027 and $487 million in aggregate principal amount of 5.2 percent
senior notes due December 2047.
For further discussion, see Item 8. Financial Statements and Supplementary Data – Note 17.
Our intention is to maintain an investment grade credit profile. As of February 1, 2020, the credit ratings on our
senior unsecured debt were at or above investment grade level as follows:
Rating Agency
Rating
Moody’s
Fitch
Standard & Poor’s
Baa2 (negative outlook)
BBB (stable outlook)
BBB (stable outlook)
The ratings shown above reflect the respective views of the rating agencies. 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.
The agreements governing our debt obligations do not contain credit rating triggers that would result in the
acceleration of interest, principal or other payments in the event that our credit ratings are downgraded. However,
any downgrades in the credit ratings of our senior unsecured debt ratings could, among other things, increase the
applicable interest rates and other fees payable under the MPLX Credit Agreement and the Term Loan
Agreement, which may limit our flexibility to obtain future financing.
89
Our liquidity totaled $4.4 billion at December 31, 2019, consisting of:
(In millions)
MPLX LP - bank revolving credit facility expiring 2024
Term Loan Agreement
MPC Loan Agreement
Total
Cash and cash equivalents
Total liquidity
December 31, 2019
Total Capacity
Outstanding
Borrowings
Available
Capacity
$
$
3,500
1,000
1,500
6,000
$
$
— $
(1,000)
(594)
(1,594)
3,500
—
906
4,406
15
$
4,421
We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our
revolving credit facilities and 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, acquisitions, contractual obligations, and quarterly cash distributions. We may,
from time to time, repurchase notes in the open market, in privately-negotiated transactions or otherwise in such
volumes, at such prices and upon such other terms as we deem appropriate.
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. 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.
Equity and Preferred Units Overview
The following table summarizes the changes in the number of units outstanding through December 31, 2019:
(In units)
Common
Class B
General Partner
Total
Balance at December 31, 2016
Unit-based compensation awards
Issuance of units under the ATM Program
Contribution of HST/WHC/Terminals
Class B Conversion
Contribution of the Joint-Interest
Acquisition
Balance at December 31, 2017
Unit-based compensation awards
Contribution of Refining Logistics and
Fuels Distribution
Conversion of GP economic interests
Balance at December 31, 2018
Unit-based compensation awards
Issuance of units in connection with the
Merger
Conversion of Series A preferred units
Balance at December 31, 2019
357,193,288
268,167
13,846,998
12,960,376
4,350,057
18,511,134
407,130,020
348,387
111,611,111
275,000,000
794,089,518
288,031
262,829,592
1,148,330
1,058,355,471
3,990,878
—
—
—
(3,990,878)
—
—
—
—
—
—
—
—
—
—
7,371,105
5,472
282,591
264,497
7,330
368,555,271
273,639
14,129,589
13,224,873
366,509
377,778
18,888,912
8,308,773
140
415,438,793
348,527
2,277,778
(10,586,691)
113,888,889
264,413,309
— 794,089,518
288,031
—
— 262,829,592
1,148,330
—
— 1,058,355,471
90
For more details on equity activity, see Item 8. Financial Statements and Supplementary Data – Notes 8 and 9.
Preferred Units
Series A Preferred Units - On May 13, 2016, MPLX completed the private placement of approximately
30.8 million Series A preferred units for a cash purchase price of $32.50 per unit. The aggregate net proceeds of
approximately $984 million from the sale of the preferred units were used for capital expenditures, repayment of
debt and general business purposes.
The Series A preferred units rank senior to all common units with respect to distributions and rights upon
liquidation. The holders of the Series A preferred units received cumulative quarterly distributions equal to
$0.528125 per unit for each quarter prior to the second quarter of 2018. Beginning with the second quarter of
2018, the holders of the Series A preferred units are entitled to receive a quarterly distribution equal to the greater
of $0.528125 per unit or the amount of distributions they would have received on an as converted basis.
Distributions paid to Series A preferred unitholders during the years ended December 31, 2019, 2018 and 2017
were $81 million, $71 million and $65 million, respectively.
On September 20, 2019, certain holders exercised their right to convert a total of 1.2 million Series A preferred
units into common units. As a result of the transaction, approximately 29.6 million Series A preferred units
remain outstanding as of December 31, 2019.
Series B Preferred Units - Prior to the Merger, ANDX issued 600,000 units of 6.875 percent Fixed-to-Floating
Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests of ANDX at a price
to the public of $1,000 per unit. Upon completion of the Merger, the ANDX preferred units converted to
preferred units of MPLX representing substantially equivalent limited partnership interests in MPLX (the “Series
B preferred units”). The Series B preferred units are pari passu with the Series A preferred units with respect to
distribution rights and rights upon liquidation. Distributions on the Series B preferred units are payable semi-
annually through February 15, 2023, and quarterly thereafter. Distributions paid to Series B preferred unitholders
during the year ended December 31, 2019 were $21 million.
Class B Units
On July 1, 2016, the previously outstanding 3,990,878 Class B units each automatically converted into 1.09
MPLX LP common units and the right to receive $6.20 per unit in cash. MPC funded the $6.20 per unit cash
payment, which reduced our liability payable to Class B unitholders by approximately $25 million on July 1,
2016. In connection with the Class B conversion on July 1, 2016, MPLX GP contributed less than $1 million in
exchange for 7,330 general partner units to maintain its two percent general partner interest. On July 1, 2017, all
of the remaining 3,990,878 Class B units each automatically converted into 1.09 MPLX LP common units and
the right to receive $6.20 per unit in cash. MPC funded this cash payment, which reduced our liability payable to
Class B unitholders by approximately $25 million on July 1, 2017. In connection with the Class B units
conversion on July 1, 2017, MPLX GP contributed less than $1 million in exchange for 7,330 general partner
units to maintain its then 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 2017 distribution.
GP/IDR Exchange
On February 1, 2018, our general partner’s IDRs were eliminated and its two percent economic general partner
interest in MPLX LP was converted into a non-economic general partner interest, all in exchange for 275 million
newly-issued MPLX LP common units. As a result of this transaction, the general partner units and IDRs were
eliminated, are no longer outstanding, and no longer participate in distributions of cash from MPLX.
91
ATM Program
On March 13, 2018, MPLX entered into a Third Amended and Restated Distribution Agreement providing for
the at-the-market issuances of common units having an aggregate offering price of up to approximately
$1.7 billion, in amounts, at prices and on terms determined by market conditions and other factors at the time of
the offerings. There were no issuances made under the ATM Program during the years ended December 31, 2019
or December 31, 2018. In 2017, the sale of common units under the ATM Program generated net proceeds of
approximately $473 million. MPLX used the net proceeds from sales under the ATM Program for general
business purposes, including repayment or refinancing of debt and funding for acquisitions, working capital
requirements and capital expenditures.
Distributions
We intend to pay a minimum quarterly distribution of $0.2625 per unit, which equates to $278 million per
quarter, or $1,111 million per year, based on the number of common units. On January 23, 2020, we announced
that the board of directors of our general partner had declared a distribution of $0.6875 per common unit that was
paid on February 14, 2020 to common unitholders of record on February 4, 2020. This represents a 6 percent
increase over the fourth quarter 2018 distribution. Although our Partnership Agreement requires that we
distribute all of our available cash each quarter, we do not otherwise have a legal obligation to distribute any
particular amount per common unit.
In connection with MPLX’s acquisition of ANDX, MPC waived $12.5 million in quarterly distributions. The
waiver was instituted in 2017 under the terms of ANDX’s historical partnership agreement and was to remain in
effect through 2019, the original term of the waiver agreement. This resulted in total waived distributions by
MPLX in 2019 of $37.5 million.
MPC also agreed to waive the fourth quarter 2017 distributions on the common units issued in connection with
the acquisition of Refining Logistics and Fuels Distribution, which took place on February 1, 2018. MPC also
agreed to waive the portion of the fourth quarter 2017 distributions on common units received on February 1,
2018 in the GP/IDR Exchange in excess of what would have been distributable to MPC for its economic general
partner interest, including IDRs, absent the exchange. Together, the value of these waived distributions was
$135 million.
Additionally, in connection with our acquisition of a partial, indirect equity interest in the Bakken Pipeline
system 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 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. This waiver is no
longer applicable as a result of the GP/IDR Exchange on February 1, 2018.
The allocation of total quarterly cash distributions to general and limited partners is as follows for the years
ended December 31, 2019, 2018 and 2017. Our 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. See additional discussion in Item 8. Financial Statements and Supplementary Data - Note 7.
92
(In millions)
Distribution declared:
Limited partner common units - public
Limited partner common units - MPC
General partner units - MPC
IDRs - MPC
Total GP & LP distribution declared
Series A preferred units
Series B preferred units
Total distribution declared
Cash distributions declared per limited partner common unit:
Quarter ended March 31,
Quarter ended June 30,
Quarter ended September 30,
Quarter ended December 31,
Year ended December 31,
2019
2018
2017
$
$
$
988
1,647
—
—
2,635
81
42
2,758
0.6575
0.6675
0.6775
0.6875
$
$
$
732
1,253
—
—
1,985
75
—
2,060
0.6175
0.6275
0.6375
0.6475
$
$
$
656
338
18
211
1,223
65
—
1,288
0.5400
0.5625
0.5875
0.6075
$
2.6900
$
2.5300
$
2.2975
The distribution on common units for the year ended December 31, 2019 includes the impact of the issuance of
approximately 102 million units issued to public unitholders and approximately 161 million units issued to MPC
in connection with the Merger. Due to the timing of the closing, distributions presented in the table above include
second quarter distributions on MPLX common units issued to former ANDX unitholders in connection with the
Merger. Due to the waiver mentioned above, the distributions on common units exclude $12.5 million of waived
distributions for the three months ended December 31, 2019 and $37.5 million of waived distributions for the
year ended December 31, 2019. Also included in the table above is $21 million of distributions on the Series B
preferred units subsequent to the Merger as well as $21 million of distributions on the Series B units prior to the
Merger and declared and paid by MPLX during the third quarter.
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 capital expenditures and growth capital expenditures. Examples of 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, growth capital expenditures are those incurred for
acquisitions or 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 capital expenditures include the acquisition of
equipment or the construction costs 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 MPLX.
93
Our capital expenditures for the past three years are shown in the table below:
(In millions)
Capital expenditures(1):
Maintenance
Maintenance Reimbursements
Growth
Growth Reimbursements
Total capital expenditures
Less: Increase (decrease) in capital accruals
Asset retirement expenditures
Additions to property, plant and equipment, net(2)
Investments in unconsolidated affiliates
Acquisitions
Total capital expenditures and acquisitions
Less: Maintenance capital expenditures (including
reimbursements)
Acquisitions
2019
2018
2017
$
$
$
262
(53)
2,001
(21)
2,189
(146)
1
2,334
713
(6)
3,041
209
(6)
175
(8)
2,078
(16)
2,229
135
7
2,087
341
451
2,879
167
451
103
—
1,381
—
1,484
71
2
1,411
761
249
2,421
103
249
Total growth capital expenditures(3)
$
2,838
$
2,261
$
2,069
Includes capital expenditures of the Predecessor for all periods presented.
(1)
(2) This amount is represented in the Consolidated Statements of Cash Flows as Additions to property, plant and equipment
after excluding growth and maintenance reimbursements. Reimbursements are shown as Contributions from MPC within
the Financing activities section of the Consolidated Statements of Cash Flows.
(3) Amount excludes contributions from noncontrolling interests of $95 million, $11 million and $129 million for the years
ended December 31, 2019, 2018 and 2017, respectively, as reflected in the financing section of our Consolidated
Statements of Cash Flows.
Our organic growth capital plan for 2020 is $1.5 billion. The L&S organic growth capital plan includes the
continued expansion of the Mt. Airy Terminal in addition to projects which increase our long-haul crude oil,
natural gas and NGL pipeline transportation capabilities. Many of our projects also increase our export
capabilities, which provides for additional flexibility and competitive advantages in how we operate our assets as
these projects further enhance our L&S segment full value chain capture. The G&P segment organic growth
capital plan includes the addition of approximately 580 MMcf/d of processing capacity at three gas processing
plants, one in the Marcellus region and two in the Southwest region. The G&P segment capital plan also includes
the addition of approximately 80 mbpd of fractionation capacity in the Marcellus and Utica regions. We
continuously evaluate our capital plan and make changes as conditions warrant.
94
Contractual Cash Obligations
The table below provides aggregated information on our consolidated obligations to make future payments under
existing contracts as of December 31, 2019:
(In millions)
Total
2020
2021-2022
2023-2024
Later Years
Bank revolving credit facility(1)
Term loan(1)
Intercompany loan(1)
Floating rate senior notes(1)
Long-term debt(1)
Finance lease obligations
Operating leases(2)
Contracts to acquire property, plant &
equipment(3)
Natural gas purchase obligations(4)
SMR liability(5)
Transportation and terminalling(6)
Other long-term liabilities reflected on the
Consolidated Balance Sheets:
AROs(7)
Other contracts(8)
$
$
25
1,044
675
2,129
28,915
27
1,120
753
15
177
10,811
27
3,182
$
6
25
18
59
804
10
92
720
5
17
2,246
1
146
$
11
1,019
35
2,070
2,409
4
164
33
10
34
4,421
—
234
$
8
—
622
—
4,552
3
120
—
—
34
3,953
—
219
—
—
—
—
21,150
10
744
—
—
92
191
26
2,583
Total contractual cash obligations
$
48,900
$
4,149
$
10,444
$
9,511
$
24,796
(1) Amounts represent outstanding borrowings at December 31, 2019, plus any commitment and administrative fees and
interest.
(2) Amounts relate primarily to facilities and equipment under leases, including ground leases, building space, office and
field equipment, storage facilities and transportation equipment. See Item 8. Financial Statements and Supplementary
Data – Note 22 for further discussion about our lease obligations.
(3) Represents purchase orders and contracts related to the purchase or build out of property, plant and equipment.
(4) Natural gas purchase obligations consist primarily of a purchase agreement with a producer in our Southern Appalachia
Operations. The contract provides for the purchase of keep-whole volumes at a specific price and is a component of a
broader regional arrangement. The contract price is designed to share a portion of the frac spread with the producer and
as a result, the amounts reflected for the obligation exceed the cost of purchasing the keep-whole volumes at a market
price. The contract is considered an embedded derivative (see Item 8. Financial Statements and Supplementary Data –
Note 16 for the fair value of the frac spread sharing component). We use the estimated future frac spreads as of
December 31, 2019 for calculating this obligation. The counterparty to the contract has the option to renew the gas
purchase agreement and the related keep-whole processing agreement for two successive five-year terms after 2022,
which is not included in the natural gas purchase obligations line item.
(5) Represents amounts due under a product supply agreement (see Item 8. Financial Statements and Supplementary Data –
Note 23 for further discussion of the product supply agreement).
(6) Represents transportation and terminalling agreements that obligate us to minimum volume, throughput or payment
commitments over the terms of the agreements, which will range from four to 20 years. We expect to pass any minimum
payment commitments through to producer customers. Minimum fees due under transportation agreements do not
include potential fee increases as required by FERC.
(7) Excludes estimated accretion expense of $24 million. The total amount to be paid is approximately $51 million.
(8) Other contracts include various service agreements and easements including right of way obligations.
In addition to the obligations included in the table above, we have omnibus agreements and employee services
agreements with MPC. The omnibus agreements with MPC addresses our payment of a fixed annual fee to MPC
for the provision of executive management services by certain executive officers of our general partner and our
reimbursement to MPC for the provision of certain general and administrative services to us. The omnibus
agreement remains in full force and effect as long as MPC controls our general partner.
We also pay MPC additional amounts based on the costs actually incurred by MPC in providing other services,
except for the portion of the amount attributable to engineering services, which is based on the amounts actually
95
incurred by MPC and its affiliates plus six percent of such costs. In addition, we are obligated to reimburse MPC
for most out-of-pocket costs and expenses incurred by MPC on our behalf.
MPLX has various employee services agreements with MPC under which MPLX reimburses MPC for employee
benefit expenses, along with the provision of operational and management services in support of both our L&S
and G&P segments’ operations.
We incurred $1,787 million of costs under the omnibus and employee services agreements for 2019.
Off-Balance Sheet Arrangements
As of December 31, 2019, we have not entered into any transactions, agreements or other arrangements that
would result in off-balance sheet liabilities.
Effects of Inflation
Inflation did not have a material impact on our results of operations for the years ended December 31, 2019, 2018
or 2017. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United
States economy and may increase the cost to acquire, build or replace property, plant and equipment. It may also
increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing
agreements, we have and expect to continue to pass along all or a portion of increased costs to our customers in
the form of higher fees.
TRANSACTIONS WITH RELATED PARTIES
As of December 31, 2019, MPC owned our general partner and an approximate 62.9 percent limited partner
interest in us. We perform a variety of services for MPC related to the transportation of crude and refined
petroleum products via pipeline, truck or marine as well as terminal services, storage services and fuels
distribution and marketing services, among other. The services that we provide may be based on regulated tariff
rates or on contracted rates. In addition, MPC performs certain services for us related to information technology,
engineering, legal, accounting, treasury, human resources and other administrative services. We believe that
transactions with related parties are conducted under terms comparable to those with unrelated parties. For
further discussion of agreements and activity with MPC and related parties see Item 1. Business and Item 8.
Financial Statements and Supplementary Data – Note 6.
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 54 percent, 48 percent and 36 percent of our
total revenues and other income for 2019, 2018 and 2017, respectively. Of our total costs and expenses, MPC
accounted for 24 percent, 27 percent and 22 percent for 2019, 2018 and 2017, respectively.
ENVIRONMENTAL MATTERS AND COMPLIANCE COSTS
We are subject to extensive federal, state and local environmental laws and regulations. These laws, which
change frequently, regulate the discharge of materials into the environment or otherwise relate to protection of
the environment. Compliance with these laws and regulations may require us to remediate environmental damage
from any discharge of hazardous, petroleum or chemical substances from our facilities or require us to install
additional pollution control equipment on our equipment and facilities. Our failure to comply with these or any
other environmental or safety-related regulations could result in the assessment of administrative, civil or
criminal penalties, the imposition of investigatory and remedial liabilities, and the issuance of injunctions that
may subject us to additional operational constraints.
Future expenditures may be required to comply with the CAA and other federal, state and local requirements for
our various facilities. The impact of these legislative and regulatory developments, if enacted or adopted, could
result in increased compliance costs and additional operating restrictions on our business, each of which could
have an adverse impact on our financial position, results of operations and liquidity. MPC will indemnify us for
certain of these costs.
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If these expenditures, as with all costs, are not ultimately reflected in the fees and tariff rates we receive for our
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. Our environmental expenditures for each of the past three years were:
(In millions)
Capital
Percent of total capital expenditures
Compliance:
Operating and maintenance
Remediation(1)
Total
2019
2018
2017
$
$
$
39
2%
40
10
50
$
$
$
29
1%
35
9
44
$
$
$
5
—%
26
4
30
(1) These amounts include spending charged against remediation reserves, where permissible, but exclude non-cash accruals
for environmental remediation.
We accrue for environmental remediation activities when the responsibility to remediate is probable and the
amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward
ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued
may be required.
New or expanded environmental requirements, which could increase our environmental costs, may arise in the
future. We believe we comply with all legal requirements regarding the environment, but since not all of them
are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or
regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that
may be incurred and penalties that may be imposed.
Our environmental capital expenditures are expected to approximate $66 million in 2020. Actual expenditures
may vary as the number and scope of environmental projects are revised as a result of improved technology or
changes in regulatory requirements and could increase if additional projects are identified or additional
requirements are imposed.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions
that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of
the date of the consolidated financial statements and the reported amounts of revenues and expenses during the
respective reporting periods. Accounting estimates are considered to be critical if (i) the nature of the estimates
and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly
uncertain matters or the susceptibility of such matters to change and (ii) the impact of the estimates and
assumptions on financial condition or operating performance is material. Actual results could differ from the
estimates and assumptions used.
The policies and estimates discussed below are considered by management to be critical to an understanding of
our financial statements because their application requires the most significant judgments from management in
estimating matters for financial reporting that are inherently uncertain. See Item 8. Financial Statements and
Supplementary Data – Note 2 for additional information on these policies and estimates, as well as a discussion
of additional accounting policies and estimates.
Fair Value Estimates
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date. There are three approaches for measuring
the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each
of which includes multiple valuation techniques. The market approach uses prices and other relevant
information generated by market transactions involving identical or comparable assets or liabilities. The
income approach uses valuation techniques to measure fair value by converting future amounts, such as cash
flows or earnings, into a single present value amount using current market expectations about those future
97
amounts. The cost approach is based on the amount that would currently be required to replace the service
capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the
fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of
comparable utility, adjusted for obsolescence.
The fair value accounting standards do not prescribe which valuation technique should be used when measuring
fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that
prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions
that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given
the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels
of the fair value hierarchy are as follows:
• Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active
markets as of the measurement date. Active markets are those in which transactions for the asset or
liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
• Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data.
These are inputs other than quoted prices in active markets included in Level 1, which are either directly
or indirectly observable as of the measurement date.
• Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally
developed methodologies that result in management’s best estimate of fair value.
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified
in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The
assessment of the significance of a particular input to the fair value measurement requires judgment and may
affect the placement of assets and liabilities within the levels of the fair value hierarchy. We use an income or
market approach for recurring fair value measurements and endeavor to use the best information available. See
Item 8. Financial Statements and Supplementary Data - Note 15 for disclosures regarding our fair value
measurements.
Significant uses of fair value measurements include:
•
•
•
•
assessment of impairment of long-lived assets, intangible assets, goodwill and equity method
investments;
assessment of values for assets in implicit leases;
recorded values for assets acquired and liabilities assumed in connection with acquisitions; and
recorded values of derivative instruments.
Impairment Assessments of Long-Lived Assets, Intangible Assets, Goodwill and Equity Method Investments
Fair value calculated for the purpose of testing our long-lived assets, intangible assets, goodwill and equity
method investments for impairment is estimated using the expected present value of future cash flows method
and comparative market prices when appropriate. Significant judgment is involved in performing these fair value
estimates since the results are based on forecasted assumptions. Significant assumptions include:
• Future Operating Performance. Our estimates of future operating performance are based on our analysis
of various supply and demand factors, which include, among other things, industry-wide capacity, our
planned utilization rate, end-user demand, capital expenditures and economic conditions as well as
commodity prices. Such estimates are consistent with those used in our planning and capital investment
reviews.
• Future volumes. Our estimates of future throughput of crude oil, natural gas, NGL and refined product
volumes are based on internal forecasts and depend, in part, on assumptions about our customers’ drilling
activity which is inherently subjective and contingent upon a number of variable factors (including future
or expected pricing considerations), many of which are difficult to forecast. Management considers these
volume forecasts and other factors when developing our forecasted cash flows.
98
• Discount rate commensurate with the risks involved. We apply a discount rate to our cash flows based on
a variety of factors, including market and economic conditions, operational risk, regulatory risk and
political risk. This discount rate is also compared to recent observable market transactions, if possible. A
higher discount rate decreases the net present value of cash flows.
• Future capital requirements. These are based on authorized spending and internal forecasts.
We base our fair value estimates on projected financial information which we believe to be reasonable. However,
actual results may differ from these projections.
The need to test for impairment can be based on several indicators, including a significant reduction in prices of
or demand for commodities, a poor outlook for profitability, a significant reduction in pipeline throughput
volumes, a significant reduction in natural gas or NGL volumes processed, other changes to contracts or changes
in the regulatory environment in which the asset or equity method investment is located.
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances
indicate that the carrying value of the assets may not be recoverable based on the expected undiscounted future
cash flow of an asset group. For purposes of impairment evaluation, long-lived assets must be grouped at the
lowest level for which independent cash flows can be identified, which is at least at the segment level and in
some cases for similar assets in the same geographic region where cash flows can be separately identified. If the
sum of the undiscounted cash flows is less than the carrying value of an asset group, fair value is calculated, and
the carrying value is written down if greater than the calculated fair value.
Unlike long-lived assets, goodwill must be tested for impairment at least annually, and between annual tests if an
event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit
below its carrying amount. Goodwill is tested for impairment at the reporting unit level. A goodwill impairment
loss is measured as the amount by which a reporting unit’s carrying value exceeds its fair value, without
exceeding the recorded amount of goodwill. As of December 31, 2019, we had a total of $9.5 billion of goodwill
recorded on the Consolidated Balance Sheets associated with all but one of our six reporting units.
Prior to performing our annual impairment assessment as of November 30, 2019, MPLX had goodwill totaling
approximately $10.7 billion. As part of that assessment, MPLX recorded approximately $1,197 million of
impairment expense in the fourth quarter of 2019 related to our Western G&P reporting unit within the G&P
operating segment, which brought the amount of goodwill recorded within this reporting unit to zero. The
impairment was primarily driven by updated guidance related to the slowing of drilling activity which has
reduced production growth forecasts from our producer customers. For the remaining reporting units with
goodwill, we determined that no significant adjustments to the carrying value of goodwill were necessary. The
annual impairment assessment resulted in the fair value of the reporting units exceeding their carrying value by
percentages ranging from approximately 8 percent to 457 percent. The reporting unit whose fair value exceeded
its carrying amount by 8 percent, our Crude Gathering reporting unit, had goodwill totaling $1.1 billion at
December 31, 2019. The operations which make up this reporting unit were acquired through the merger with
ANDX. MPC accounted for its October 1, 2018 acquisition of Andeavor (including acquiring control of ANDX),
using the acquisition method of accounting, which required Andeavor assets and liabilities to be recorded by
MPC at the acquisition date fair value. The Merger was closed on July 30, 2019 and has been treated as a
common control transaction, which required the recognition of assets acquired and liabilities assumed using
MPC’s historical carrying value. As such, given the short amount of time from when fair value was established to
the date of the annual impairment test, the amount by which the fair value exceeded the carrying value within this
reporting unit is not unexpected. Our Eastern G&P reporting unit had fair value exceeding its carrying value of
approximately 18 percent and had goodwill totaling $1.8 billion as of December 31, 2019. An increase of one
percentage point to the discount rate used to estimate the fair value of this reporting unit would not have resulted
in goodwill impairment as of November 30, 2019. No other reporting units had had fair values exceeding
carrying values of less than 20 percent.
99
Significant assumptions used to estimate the reporting units’ fair value included estimates of future cash flows
and market information for comparable assets. If estimates for future cash flows, which are impacted primarily
by producer customers’ development plans, which impact future volumes and capital requirements, were to
decline, the overall reporting units’ fair value would decrease, resulting in potential goodwill impairment
charges. Fair value determinations require considerable judgment and are sensitive to changes in underlying
assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for
purposes of the impairment tests will prove to be an accurate prediction of the future. See Item 8. Financial
Statements and Supplementary Data - Note 14 for additional information relating to our reporting units and
goodwill.
Equity method investments are assessed for impairment whenever factors indicate an other than temporary loss
in value. Factors providing evidence of such a loss include the fair value of an investment that is less than its
carrying value, absence of an ability to recover the carrying value or the investee’s inability to generate income
sufficient to justify our carrying value. During the fourth quarter of 2019, two of the joint ventures in which we
have an interest recorded impairments, which impacted the amount of income from equity method investments
during the period by approximately $28 million. For one of the joint ventures, we also had a basis difference,
which was being amortized over the life of the underlying assets. As a result of the impairment recorded by the
joint venture, we also assessed this basis difference for impairment and recorded approximately $14 million of
impairment during the quarter related to this investment, which was recorded through “Income from equity
method investments”. This impairment was largely due to a reduction in forecasted volumes of the joint venture
related to the loss of one of its customers. At December 31, 2019, we had $5.3 billion of equity method
investments recorded on the Consolidated Balance Sheets.
An estimate of the sensitivity to net income resulting from impairment calculations is not practicable, given the
numerous assumptions (e.g., pricing, volumes and discount rates) that can materially affect our estimates. That is,
unfavorable adjustments to some of the above listed assumptions may be offset by favorable adjustments in other
assumptions.
See Item 8. Financial Statements and Supplementary Data - Note 5 for additional information on our equity
method investments and Note 14 for additional information on our goodwill and intangibles.
Leases
In accounting for leases, MPLX may be required to analyze new or existing leases for lease classification. One of
the key inputs into the lease classification analysis is the fair value of the leased assets. Significant assumptions
used to estimate the leased assets’ fair value included market information for comparable assets and cost
estimates to replace the service capacity of an asset.
Acquisitions
In accounting for business combinations, acquired assets, assumed liabilities and contingent consideration are
recorded based on estimated fair values as of the date of acquisition. The excess or shortfall of the purchase price
when compared to the fair value of the net tangible and identifiable intangible assets acquired, if any, is recorded
as goodwill or a bargain purchase gain, respectively. A significant amount of judgment is involved in estimating
the individual fair values of property, plant and equipment, intangible assets, contingent consideration and other
assets and liabilities. We use all available information to make these fair value determinations and, for certain
acquisitions, engage third-party consultants for assistance.
The fair value of assets and liabilities, including contingent consideration, as of the acquisition date are often
estimated using a combination of approaches, including the income approach, which requires us to project related
future cash inflows and outflows and apply an appropriate discount rate; the cost approach, which requires
estimates of replacement costs and depreciation and obsolescence estimates; and the market approach, which
uses market data and adjusts for entity-specific differences. The estimates used in determining fair values are
based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results
may differ from the projected results used to determine fair value.
See Item 8. Financial Statements and Supplementary Data - Note 4 for additional information on our
acquisitions, which includes a discussion of common control transactions and the related impact of how such
100
transactions are recorded. See Item 8. Financial Statements and Supplementary Data - Note 15 for additional
information on fair value measurements.
Derivatives
We record all derivative instruments at fair value on the Consolidated Balance Sheets. To the extent that we have
any, our crude oil and natural gas commodity derivatives are Level 2 financial instruments. Our NGL commodity
derivatives and any option contracts are Level 3 financial instruments due to option volatilities and NGL prices
that are interpolated and extrapolated due to inactive markets. Substantially all of our commodity derivative
instruments are traded in OTC markets and are appropriately adjusted for non-performance risk.
We have a natural gas purchase commitment embedded in a keep-whole processing agreement with a producer
customer in the Southern Appalachian region expiring in December 2022. The customer has the unilateral option
to extend the agreements for two consecutive five-year terms through December 2032. For accounting purposes,
the natural gas purchase commitment and term extending options have been aggregated into a single compound
embedded derivative which is a Level 3 financial instrument and is appropriately adjusted for non-performance
risk (the “Natural Gas Embedded Derivative”). The significant unobservable inputs to the valuation of the
Natural Gas Embedded Derivative include:
• Probability of Renewal. As of December 31, 2019, we believe there is a 94 percent and 83 percent
probability that the customer will exercise its first and second term extending options, respectively. The
customer must exercise the first term extending option in order for the second term extending option to
become available.
• Commodity Prices. Third-party forward price curves are not available after 2023, which requires us to
extrapolate NGL and natural gas prices.
A ten percent difference in the estimated fair value of the Natural Gas Embedded Derivative at December 31,
2019 would have affected income before taxes by $6.0 million for the year ended December 31, 2019. If the
probabilities of renewal for the Natural Gas Embedded Derivative were changed to 84 percent and 73 percent,
the liability would have been reduced by $5.0 million as of December 31, 2019. If the probabilities of renewal for
the Natural Gas Embedded Derivative were changed to 99 percent and 87 percent, the liability would have been
increased by $2.3 million as of December 31, 2019. Fair value estimation for all our derivative instruments is
discussed in Item 8. Financial Statements and Supplementary Data - Note 15 and Note 16. Additional
information about derivatives and their valuation may be found in Item 7A. Quantitative and Qualitative
Disclosures about Market Risk.
Variable Interest Entities
We evaluate all legal entities in which we hold an ownership or other pecuniary interest to determine if the entity
is a VIE. Our interests in a VIE are referred to as variable interests. Variable interests can be contractual,
ownership or other pecuniary interests in an entity that change with changes in the fair value of the VIE’s assets.
When we conclude that we hold an interest in a VIE we must determine if we are the entity’s primary
beneficiary. A primary beneficiary is deemed to have a controlling financial interest in a VIE. This controlling
financial interest is evidenced by both (i) the power to direct the activities of the VIE that most significantly
impact the VIE’s economic performance and (ii) the obligation to absorb losses that could potentially be
significant to the VIE or the right to receive benefits that could potentially be significant to the VIE. We
consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any
interests in a VIE that is not consolidated.
Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interest in a
VIE. We use primarily a qualitative analysis to determine if an entity is a VIE. We evaluate the entity’s need for
continuing financial support; the equity holder’s lack of a controlling financial interest; and/or if an equity
holder’s voting interests are disproportionate to its obligation to absorb expected losses or receive residual
returns. We evaluate our interests in a VIE to determine whether we are the primary beneficiary. We use a
primarily qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE,
either on a standalone basis or as part of a related party group. We continually monitor our interests in legal
entities for changes in the design or activities of an entity and changes in our interests, including our status
101
as the primary beneficiary to determine if the changes require us to revise our previous conclusions.
Changes in the design or nature of the activities of a VIE, or our involvement with a VIE, may require us to
reconsider our conclusions on the entity’s status as a VIE and/or our status as the primary beneficiary. Such
reconsideration requires significant judgment and understanding of the organization. This could result in the
deconsolidation or consolidation of the affected subsidiary, which would have a significant impact on our
financial statements.
VIEs are discussed in Item 8. Financial Statements and Supplementary Data - Note 5.
Contingent Liabilities
We accrue contingent liabilities for legal actions, claims, litigation, environmental remediation, tax deficiencies
related to operating taxes and third-party indemnities for specified tax matters when such contingencies are both
probable and estimable. We regularly assess these estimates in consultation with legal counsel to consider
resolved and new matters, material developments in court proceedings or settlement discussions, new
information obtained as a result of ongoing discovery and past experience in defending and settling similar
matters. Actual costs can differ from estimates for many reasons. For instance, settlement costs for claims and
litigation can vary from estimates based on differing interpretations of laws, opinions on degree of responsibility
and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary from
estimates because of changes in laws, regulations and their interpretation, additional information on the extent
and nature of site contamination and improvements in technology.
We generally record losses related to these types of contingencies as cost of revenues or selling, general and
administrative expenses on the Consolidated Statements of Income, except for tax deficiencies unrelated to
income taxes, which are recorded as other taxes.
An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is
not practical because of the number of contingencies that must be assessed, the number of underlying
assumptions and the wide range of reasonably possible outcomes, in terms of both the probability of loss and the
estimates of such loss.
For additional information on contingent liabilities, see Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations - Environmental Matters and Compliance Costs and Item 8.
Financial Statements and Supplementary Data - Note 23.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to market risks related to the volatility of commodity prices. We employ various strategies,
including the potential 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 interest rates. As of December 31,
2019, we did not have any open financial derivative instruments to economically hedge the risks related to
interest rate fluctuations or commodity derivative instruments to economically hedge the risks related to the
volatility of commodity prices; however, we continually monitor the market and our exposure and may enter into
these arrangements in the future. While there is a risk related to changes in fair value of derivative instruments
we may enter into; such risk is mitigated by price or rate changes related to the underlying commodity or
financial transaction.
Commodity Price Risk
We may at times use a variety of commodity derivative instruments, including futures and options, as part
of an overall program to economically hedge commodity price risk. A portion of our profitability is directly
affected by prevailing commodity prices primarily as a result of purchasing and selling NGLs and natural
gas at index-related prices. To the extent that commodity prices influence the level of drilling by our
producer customers, such prices also indirectly affect profitability. We may enter into derivative contracts,
which are primarily swaps traded on the OTC market as well as fixed price forward contracts. Our risk
management policy does not allow us to enter into speculative positions with our derivative contracts.
102
Execution of our hedge strategy and the continuous monitoring of commodity markets and our open derivative
positions are carried out by our hedge committee, comprised of members of senior management.
To mitigate our cash flow exposure to fluctuations in the price of NGLs, we may use NGL derivative swap
contracts. A small portion of our NGL price exposure may be managed by using crude oil contracts. To mitigate
our cash flow exposure to fluctuations in the price of natural gas, we may use natural gas derivative swap
contracts, taking into account the partial offset of our long and short natural gas positions resulting from normal
operating activities.
We would be exposed to additional commodity risk in certain situations such as if producers under-deliver or
over-deliver products or if processing facilities are operated in different recovery modes. In the event that we
have 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 we have provided
the counterparties with a guaranty as credit support for our obligations. A separate agreement with certain
counterparties allows MarkWest Liberty Midstream to enter into derivative positions without posting cash
collateral. We use standardized agreements that allow for offset of certain positive and negative exposures in the
event of default or other terminating events, including bankruptcy.
Outstanding Derivative Contracts
We have a natural gas purchase commitment embedded in a keep-whole processing agreement with a producer
customer in the Southern Appalachian region expiring in December 2022. The customer has the unilateral option
to extend the agreement for two consecutive five-year terms through December 2032. For accounting purposes,
the natural gas purchase commitment and term extending options have been aggregated into a single compound
embedded derivative. The probability of the customer exercising its options is determined based on assumptions
about the customer’s potential business strategy decision points that may exist at the time they would elect 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” on the Consolidated Statements of Income.
As of December 31, 2019 and 2018, the estimated fair value of this contract was a liability of $60 million and
$61 million, respectively.
Open Derivative Positions and Sensitivity Analysis
The estimated fair value of our Level 2 and 3 financial instruments are sensitive to the assumptions used in our
pricing models. Sensitivity analysis of a ten percent difference in our estimated fair value of Level 2 and 3
commodity derivatives (excluding embedded derivatives) as of December 31, 2019 would not have affected
income before income taxes for the year ended December 31, 2019, given we had no open commodity derivative
contracts during the year. We evaluate our portfolio of commodity derivative instruments on an ongoing basis
and add or revise strategies in anticipation of changes in market conditions and in risk profiles.
Interest Rate Risk
Sensitivity analysis of the effect of a hypothetical 100-basis-point change in interest rates on long-term debt,
excluding 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.
103
(In millions)
Long-term debt
Fixed-rate
Variable-rate
Fair Value as of
December 31, 2019(1)
Change in Fair Value (2)
Change in Income
before income taxes for
the Year Ended
December 31, 2019 (3)
$
$
18,045
3,009
$
$
1,749
43
$
N/A
20
(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 December 31, 2019.
(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 year ended December 31, 2019.
At December 31, 2019, our portfolio of long-term debt consisted of fixed-rate instruments and variable-rate
instruments including our term loan, floating rate senior notes and our revolving credit facility. We had no
outstanding balance under the revolving credit facility at December 31, 2019. 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, but may affect our results of operations and cash flows. As of December 31, 2019, we did not have any
commodity or financial derivative instruments to hedge the risks related to commodity price or interest rate
fluctuations; however, we continually monitor the market and our exposure and may enter into these agreements
in the future.
Credit Risk
We are subject to risk of loss resulting from non-payment by our customers to whom we provide services, lease
assets, or sell natural gas or NGLs. We believe that certain contracts would allow us to pass those losses through
to our customers, thus reducing our risk, when we are selling NGLs and acting as our producer customers’ agent.
Our credit exposure related to these customers is represented by the value of our trade receivables or lease
receivables. Where exposed to credit risk, we analyze the customer’s financial condition prior to entering into a
transaction or agreement, establish credit terms and monitor the appropriateness of these terms on an ongoing
basis. In the event of a customer default, we may sustain a loss and our cash receipts could be negatively
impacted.
We would also be subject to risk of loss resulting from non-payment or non-performance by the counterparties to
our derivative contracts. Our credit exposure related to commodity derivative instruments is represented by the
fair value of contracts with a net positive fair value at the reporting date. Outstanding instruments expose us to
credit loss in the event of non-performance by the counterparties to the agreements. Should the creditworthiness
of one or more of our counterparties decline, our ability to mitigate non-performance risk is limited to a
counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the
derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash
receipts could be negatively impacted.
104
Item 8. Financial Statements and Supplementary Data
INDEX
Management’s Responsibilities for Financial Statements
Management’s Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Audited Consolidated Financial Statements:
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Equity
Notes to Consolidated Financial Statements
Select Quarterly Financial Data (Unaudited)
Page
106
106
107
110
111
112
113
114
115
172
105
Management’s Responsibilities for Financial Statements
The accompanying consolidated financial statements of MPLX LP and its subsidiaries (the “Partnership”) are the
responsibility of management of the Partnership’s general partner, MPLX GP LLC, and have been prepared in
conformity with accounting principles generally accepted in the United States of America. They necessarily
include some amounts that are based on best judgments and estimates. The financial information displayed in
other sections of this Annual Report on Form 10-K is consistent with these consolidated financial statements.
MPLX GP LLC seeks to assure the objectivity and integrity of the Partnership’s financial records by careful
selection of its managers, by organizational arrangements that provide an appropriate division of responsibility
and by communications programs aimed at assuring that its policies and methods are understood throughout the
organization.
The MPLX GP LLC Board of Directors pursues its oversight role in the area of financial reporting and internal
control over financial reporting through its Audit Committee. This committee, composed solely of independent
directors, regularly meets (jointly and separately) with the independent registered public accounting firm,
management and internal auditors to monitor the proper discharge by each of their responsibilities relative to
internal accounting controls and the consolidated financial statements.
/s/ Michael J. Hennigan
Michael J. Hennigan
Director, President and Chief
Executive Officer of MPLX GP LLC
(the general partner of MPLX LP)
/s/ Pamela K.M. Beall
Pamela K.M. Beall
Director, Executive Vice President
and Chief Financial Officer of
MPLX GP LLC
(the general partner of MPLX LP)
/s/ C. Kristopher Hagedorn
C. Kristopher Hagedorn
Vice President and Controller of
MPLX GP LLC
(the general partner of MPLX
LP)
Management’s Report on Internal Control over Financial Reporting
MPLX LP’s management is responsible for establishing and maintaining adequate internal control over financial
reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended). An evaluation
of the design and effectiveness of our internal control over financial reporting, based on the framework in
Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission, was conducted under the supervision and with the participation of management,
including our chief executive officer and chief financial officer. Based on the results of this evaluation, MPLX
LP’s management concluded that its internal control over financial reporting was effective as of December 31,
2019.
The effectiveness of MPLX LP’s internal control over financial reporting as of December 31, 2019 has been
audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their
report which is included herein.
/s/ Michael J. Hennigan
Michael J. Hennigan
Director, President and Chief
Executive Officer of MPLX GP LLC
(the general partner of MPLX LP)
/s/ Pamela K.M. Beall
Pamela K.M. Beall
Director, Executive Vice President
and Chief Financial Officer of
MPLX GP LLC
(the general partner of MPLX LP)
106
Report of Independent Registered Public Accounting Firm
To the Partners of MPLX LP and the Board of Directors of MPLX GP LLC
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of MPLX LP and its subsidiaries (the
“Company”) as of December 31, 2019 and 2018, and the related consolidated statements of income,
comprehensive income, equity and cash flows for each of the three years in the period ended December 31, 2019,
including the related notes (collectively referred to as the “consolidated financial statements”). We also have
audited the Company’s internal control over financial reporting as of December 31, 2019, based on criteria
established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its
cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting
principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in
all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria
established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective
internal control over financial reporting, and for its assessment of the effectiveness of internal control over
financial reporting, included in the accompanying Management’s Report on Internal Control over Financial
Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on
the Company’s internal control over financial reporting based on our audits. We are a public accounting firm
registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to
be independent with respect to the Company in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are
free of material misstatement, whether due to error or fraud, and whether effective internal control over financial
reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material
misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures
that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts
and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of
the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary in the circumstances. We
believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that,
in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation
107
of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and
directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the
consolidated financial statements that was communicated or required to be communicated to the audit committee
and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and
(ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit
matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we
are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit
matter or on the accounts or disclosures to which it relates.
Goodwill Impairment Tests - Eastern and Western Gathering and Processing and Crude Gathering Reporting
Units
As described in Notes 2 and 14 to the consolidated financial statements, the Company’s consolidated goodwill
balance was $9.5 billion as of December 31, 2019. As disclosed by management, of that amount, the goodwill
associated with the Eastern Gathering and Processing reporting unit amounted to $1.8 billion and goodwill
associated with the Crude Gathering reporting unit amounted to $1.1 billion. In addition, an impairment charge
of $1.2 billion was recorded in 2019 related to the Western Gathering and Processing reporting unit, which
brought the amount of goodwill recorded within this reporting unit to zero. Management conducts impairment
tests as of November 30 of each year or more frequently if events or circumstances indicate that reporting unit
carrying values of goodwill may be impaired. As a result of a change in reporting units during 2019, management
performed impairment tests on these reporting units prior to and immediately following the change in reporting
units. The fair value of each reporting unit is determined using a combination of income and market approach
methods. The significant assumptions that were used to develop the estimates of the fair values of each reporting
unit under the income approach include the discount rate as well as estimates of future cash flows, which are
impacted primarily by producer customers’ development plans, which impact future volumes and capital
requirements.
The principal consideration for our determination that performing procedures relating to the goodwill impairment
tests of the Company’s Eastern Gathering and Processing, Western Gathering and Processing, and Crude
Gathering reporting units, as well as certain related reporting units prior to the change, is a critical audit matter as
there was significant judgment by management when estimating the fair values of the reporting units. This in turn
led to a high degree of auditor judgment, subjectivity, and effort in performing audit procedures and evaluating
evidence related to management’s fair value estimates and significant assumptions related to producer customers’
development plans, which impact future volumes and capital requirements.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with
forming our overall opinion on the consolidated financial statements. These procedures included testing the
effectiveness of controls relating to management’s goodwill impairment tests, including controls over the
estimation of the fair values of the Eastern Gathering and Processing, Western Gathering and Processing,
and Crude Gathering reporting units. These procedures also included, among others, testing management’s
process for developing the fair value estimates; evaluating the appropriateness of the valuation methods
used; testing the completeness and accuracy of underlying data used by management; and evaluating the
reasonableness of significant assumptions related to producer customers’ development plans, which impact
future volumes and capital requirements used in determining the fair values of each reporting unit under the
income approach. Professionals with specialized skill and knowledge were utilized to assist in evaluating
108
the appropriateness of the Company’s income and market approach methods. Evaluating the assumptions related
to producer customers’ development plans, which impact future volumes and capital requirements involved
(i) considering whether the assumptions used were reasonable considering past performance of each reporting
unit, producer customers’ historical and future production volumes, historical and approved future capital
projects, and industry outlook reports, and (ii) considering whether the assumptions were consistent with
evidence obtained in other areas of the audit.
/s/PricewaterhouseCoopers LLP
Toledo, Ohio
February 28, 2020
We have served as the Company’s auditor since 2012.
109
MPLX LP
Consolidated Statements of Income
(In millions, except per unit data)
Revenues and other income:
Service revenue
Service revenue - related parties
Service revenue - product related
Rental income
Rental income - related parties
Product sales
Product sales - related parties
Income from equity method investments
Other income
Other income - related parties
Total revenues and other income
Costs and expenses:
Cost of revenues (excludes items below)
Purchased product costs
Rental cost of sales
Rental cost of sales - related parties
Purchases - related parties
Depreciation and amortization
Impairment expense
General and administrative expenses
Other taxes
Total costs and expenses
Income from operations
Related party interest and other financial costs
Interest expense (net of amounts capitalized of $51 million, $37 million
and $32 million, respectively)
Other financial costs
Income before income taxes
Provision for income taxes
Net income
Less: Net income attributable to noncontrolling interests
Less: Net income attributable to Predecessor
Net income attributable to MPLX LP
Less: Series A preferred unit distributions
Less: Series B preferred unit distributions
Less: General partner’s interest in net income attributable to MPLX LP
Limited partners’ interest in net income attributable to MPLX LP
Per Unit Data (See Note 7)
Net income attributable to MPLX LP per limited partner unit:
Common - basic
Common - diluted
Weighted average limited partner units outstanding:
Common - basic
Common - diluted
$
$
$
$
2019
2018
2017
$
2,498
3,455
140
388
1,196
806
142
290
12
114
9,041
1,489
686
141
165
1,231
1,254
1,197
388
113
6,664
2,377
11
851
53
1,462
—
1,462
28
401
1,033
81
17
—
$
1,856
2,404
220
352
846
887
87
247
7
99
7,005
1,096
824
135
31
925
867
—
316
83
4,277
2,728
5
590
119
2,014
8
2,006
16
172
1,818
75
—
—
935
$
1,743
$
$
$
1.00
1.00
906
907
$
$
2.29
2.29
761
761
1,156
1,082
—
277
279
889
8
78
6
92
3,867
528
651
62
2
455
683
—
241
54
2,676
1,191
2
296
56
837
1
836
6
36
794
65
—
318
411
1.07
1.06
385
388
The accompanying notes are an integral part of these consolidated financial statements.
110
MPLX LP
Consolidated Statements of Comprehensive Income
(In millions)
Net income
Other comprehensive income/(loss), net of tax:
Remeasurements of pension and other postretirement benefits
related to equity method investments, net of tax
Comprehensive income
Less comprehensive income attributable to:
Noncontrolling interests
Income attributable to Predecessor
2019
2018
2017
$
1,462
$
2,006
$
836
1
1,463
28
401
(2)
2,004
16
172
—
836
6
36
794
Comprehensive income attributable to MPLX LP
$
1,034
$
1,816
$
The accompanying notes are an integral part of these consolidated financial statements.
111
(In millions)
Assets
Current assets:
Cash and cash equivalents
Receivables, net
Current assets - related parties
Inventories
Other current assets
Total current assets
Equity method investments
Property, plant and equipment, net
Intangibles, net
Goodwill
Right of use assets
Noncurrent assets - related parties
Other noncurrent assets
Total assets
Liabilities
Current liabilities:
Accounts payable
Accrued liabilities
Current liabilities - related parties
Accrued property, plant and equipment
Accrued interest payable
Operating lease liabilities
Other current liabilities
Total current liabilities
Long-term deferred revenue
Long-term liabilities - related parties
Long-term debt
Deferred income taxes
Long-term operating lease liabilities
Deferred credits and other liabilities
Total liabilities
MPLX LP
Consolidated Balance Sheets
December 31,
2019
2018
$
$
15
593
656
110
110
1,484
5,275
22,145
1,270
9,536
365
303
52
40,430
242
187
1,008
283
210
66
136
2,132
217
290
19,704
12
302
192
22,849
968
10,800
4,968
611
—
(15)
16,364
249
16,613
77
611
556
98
98
1,440
4,901
21,525
1,359
10,016
—
24
60
39,325
266
272
502
399
184
—
645
2,268
132
46
17,922
14
—
208
20,590
1,004
8,336
(1,612)
—
10,867
(16)
17,575
156
17,731
39,325
Commitments and contingencies (see Note 23)
Series A preferred units
Equity
Common unitholders - public (392 million and 289 million units issued and
outstanding)
Common unitholder - MPC (666 million and 505 million units issued and outstanding)
Series B preferred units (.6 million and zero units issued and outstanding)
Equity of Predecessor
Accumulated other comprehensive loss
Total MPLX LP partners’ capital
Noncontrolling interests
Total equity
Total liabilities, preferred units and equity
$
40,430
$
The accompanying notes are an integral part of these consolidated financial statements.
112
MPLX LP
Consolidated Statements of Cash Flows
(In millions)
2019
2018
2017
Increase/(decrease) in cash, cash equivalents and restricted cash
Operating activities:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
$
1,462
$
2,006
$
Amortization of deferred financing costs
Depreciation and amortization
Impairment expense
Deferred income taxes
Asset retirement expenditures
Gain on disposal of assets
Income from equity method investments
Distributions from unconsolidated affiliates
Changes in:
Current receivables
Inventories
Fair value of derivatives
Current accounts payable and accrued liabilities
Current assets/current liabilities - related parties
Right of use assets/operating lease liabilities
Deferred revenue
All other, net
42
1,254
1,197
(2)
(1)
(6)
(290)
525
17
(9)
2
(59)
(163)
4
100
9
55
867
—
8
(7)
3
(247)
412
(104)
(5)
(10)
88
(61)
—
61
5
836
53
683
—
(1)
(2)
—
(78)
241
8
(3)
6
48
55
—
33
28
Net cash provided by operating activities
4,082
3,071
1,907
Investing activities:
Additions to property, plant and equipment
Acquisitions, net of cash acquired
Investments - net related party loans
Disposal of assets
Investments in unconsolidated affiliates
Distributions from unconsolidated affiliates - return of capital
All other, net
Net cash used in investing activities
Financing activities:
Long-term debt - borrowings
- repayments
Related party debt - borrowings
- repayments
Debt issuance costs
Net proceeds from equity offerings
Distributions to Series A preferred unitholders
Distributions to Series B preferred unitholders
Distributions to MPC for acquisitions
Distributions to MPC from Predecessor
Distributions to unitholders and general partner
Distributions to common and Series B preferred unitholders from Predecessor
Distributions to noncontrolling interests
Contributions from MPC
Contributions from noncontrolling interests
Consideration payment to Class B unitholders
All other, net
Net cash used in financing activities
Net (decrease)/increase in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
(2,408)
6
—
30
(713)
18
4
(3,063)
9,174
(7,924)
9,313
(8,719)
(20)
—
(81)
(21)
—
—
(2,435)
(502)
(30)
74
95
—
(13)
(1,089)
(70)
85
Cash, cash equivalents and restricted cash at end of period
$
15
$
(2,111)
(451)
—
8
(341)
16
1
(2,878)
13,476
(6,946)
3,962
(4,347)
(76)
—
(71)
—
(4,111)
—
(1,819)
(239)
(17)
41
11
—
19
(117)
76
9
85
$
(1,411)
(249)
80
7
(761)
26
—
(2,308)
2,911
(416)
2,369
(1,983)
(29)
483
(65)
—
(1,951)
(113)
(1,120)
—
(7)
—
129
(25)
(12)
171
(230)
239
9
The accompanying notes are an integral part of these consolidated financial statements.
113
MPLX LP
Consolidated Statements of Equity
Partnership
(In millions)
Common
Unit-holder
Public
Class B
Unit-holder
Public
Common
Unit-holder
MPC
Series B
Preferred
Unit-
holders
General
Partner
MPC
Accumulated
Other
Comprehensive
Loss
Non-
controlling
Interests
Equity of
Predecessor
Total
Balance at December 31, 2016
$
8,086
$
133
$
1,069
$ — $ 1,013
$
— $
18
$
791
$ 11,110
Net income (excludes amounts
attributable to Series A preferred
units)
Unit issuances under ATM
Program
Class B unit conversion
Allocation of MPC’s net
investment at acquisition
Distributions to:
MPC from Predecessor
MPC for acquisition
Unitholders and general
partner
Noncontrolling interests
MPC of cash received from
Joint-Interest Acquisition
entities
Contributions from:
MPC
Noncontrolling interests
Other
301
473
133
—
—
—
(622)
—
—
—
—
8
Balance at December 31, 2017
8,379
Net income (excludes amounts
attributable to Series A preferred
units)
Allocation of MPC’s net
investment at acquisition
Conversion of GP economic
interests
Distributions to:
MPC for acquisition
Unitholders and general
partner
Noncontrolling interests
Contributions from:
MPC
Noncontrolling interests
Other
667
—
—
—
(722)
—
—
—
12
Balance at December 31, 2018
8,336
Net income (excludes amounts
attributable to Series A preferred
units)
Allocation of MPC’s net
investment at acquisition
Conversion of Series A preferred
units
Distributions to:
Unitholders and general
partner
Noncontrolling interests
Contributions from:
MPC
Noncontrolling interests
Other
340
2,983
36
(907)
—
—
—
12
—
—
(133)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
110
—
—
1,669
—
(537)
(212)
—
—
—
—
—
2,099
1,076
5,172
—
—
—
—
318
10
—
(266)
—
—
— (1,394)
—
—
—
—
—
—
—
—
(286)
—
(32)
—
—
—
(637)
—
— (4,126)
(7,926)
—
7,926
(936)
— (3,164)
(1,097)
—
—
—
—
(1,612)
595
7,199
—
(1,529)
—
315
—
—
—
—
—
—
—
—
17
615
—
(21)
—
—
—
—
—
—
—
—
1
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(14)
—
—
(14)
—
—
—
—
—
—
—
—
(2)
(16)
—
—
—
—
—
—
—
1
6
—
—
—
—
—
—
(7)
—
—
129
—
146
16
—
—
—
—
(17)
—
11
—
156
28
—
—
—
(30)
—
95
—
36
—
—
(1,403)
(113)
—
—
—
—
689
—
—
—
771
483
—
—
(113)
(1,931)
(1,120)
(7)
(32)
675
129
8
9,973
172
1,931
(1,046)
—
—
(239)
—
11,980
—
—
10,867
—
—
(4,100)
(2,058)
(17)
11,980
11
11
17,731
401
1,381
(10,797)
—
—
36
(502)
—
(2,959)
(30)
31
—
—
346
95
13
Balance at December 31, 2019
$
10,800
$
— $
4,968
$
611
$ —
$
(15)
$
249
$
— $ 16,613
The accompanying notes are an integral part of these consolidated financial statements.
114
Notes to Consolidated Financial Statements
1. Description of the Business and Basis of Presentation
Description of the Business – MPLX LP is a diversified, large-cap master limited partnership formed by
Marathon Petroleum Corporation (“MPC”) that owns and operates midstream energy infrastructure and logistics
assets, and provides fuels distribution services. References in this report to “MPLX LP,” “MPLX,” “the
Partnership,” “we,” “ours,” “us,” or like terms refer to MPLX LP and its subsidiaries. References to “MPC” refer
collectively to Marathon Petroleum Corporation as our sponsor and its subsidiaries, other than the Partnership.
We are engaged in the transportation, storage and distribution of crude oil, asphalt and refined petroleum
products; the gathering, processing and transportation of natural gas; and the gathering, transportation,
fractionation, storage and marketing of NGLs. MPLX’s principal executive office is located in Findlay, Ohio.
MPLX was formed on March 27, 2012 as a Delaware limited partnership and completed its Initial Offering on
October 31, 2012.
MPLX’s business consists of two segments based on the nature of services it offers: Logistics and Storage
(“L&S”), which relates primarily to crude oil and refined petroleum products; and Gathering and Processing
(“G&P”), which relates primarily to natural gas and NGLs. See Note 10 for additional information regarding the
operations and results of these segments.
On July 30, 2019, MPLX completed its acquisition by merger (the “Merger”) of Andeavor Logistics LP
(“ANDX”). At the effective time of the Merger, each common unit held by ANDX’s public unitholders was
converted into the right to receive 1.135 MPLX common units. ANDX common units held by certain affiliates of
MPC were converted into the right to receive 1.0328 MPLX common units. See Note 4 for additional
information regarding the Merger.
Basis of Presentation – The 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
investments, 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 a VIE in which MPLX exercises significant influence but does
not control and is not the primary beneficiary are also accounted for using the equity method.
In relation to the Merger described above and in Note 4, ANDX’s assets, liabilities and results of operations prior
to the Merger are collectively included in what we refer to as the “Predecessor” from October 1, 2018, which was
the date that MPC acquired Andeavor. MPLX’s acquisition of ANDX is considered a transfer between entities
under common control due to MPC’s relationship with ANDX prior to the Merger. As an entity under common
control with MPC, MPLX recorded the assets acquired and liabilities assumed on its consolidated balance sheets
at MPC’s historical carrying value. Transfers of businesses between entities under common control require prior
periods to be retrospectively adjusted for those dates that the entity was under common control. Accordingly, the
accompanying financial statements and related notes of MPLX LP have been retrospectively adjusted to include
the historical results of ANDX beginning October 1, 2018.
Certain prior period financial statement amounts have been reclassified to conform to current period presentation.
The accompanying consolidated financial statements of MPLX have been prepared in accordance with GAAP.
2. Summary of Principal Accounting Policies
Use of Estimates – The preparation of financial statements in accordance with GAAP requires management to
make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of
contingent assets and liabilities as of the date of the consolidated financial statements and the reported
amounts of revenues and expenses during the respective reporting periods. Actual results could differ
materially from those estimates. Estimates are subject to uncertainties due to the levels of subjectivity and
judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change and
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affect items such as valuing identified intangible assets; determining the fair value of derivative instruments;
evaluating impairments of long-lived assets, goodwill and equity investments; establishing estimated useful
lives for long-lived assets; acquisition accounting; recognizing share-based compensation expense; estimating
revenues, expense accruals and capital expenditures; valuing AROs; and determining liabilities, if any, for
environmental and legal contingencies.
Revenue Recognition – Revenue is measured based on consideration specified in a contract with a customer.
MPLX recognizes revenue when it satisfies a performance obligation by transferring control over a product or
providing services to a customer.
MPLX enters into a variety of contract types in order to generate “Product sales” and “Service revenue.” MPLX
provides services under the following types of arrangements:
• Fee-based arrangements – Under fee-based arrangements, MPLX receives a fee or fees for one or more
of the following services: gathering, processing and transportation of natural gas; gathering,
transportation, fractionation, exchange and storage of NGLs; and transportation, storage and distribution
of crude oil, refined products and other hydrocarbon-based products. The revenue MPLX earns from
these arrangements is generally directly related to the volume of natural gas, NGLs, refined products or
crude oil that is handled by or flows through MPLX’s systems and facilities and is not normally directly
dependent on commodity prices. In certain cases, MPLX’s arrangements provide for minimum annual
payments or fixed demand charges.
Fee-based arrangements are reported as “Service revenue” on the Consolidated Statements of Income.
Revenue is recognized over time as services are performed. In certain instances when specifically stated
in the contract terms, MPLX purchases product after fee-based services have been provided. Revenue
from the sale of products purchased after services are provided is reported as “Product sales” on the
Consolidated Statements of Income and recognized on a gross basis, as MPLX takes control of the
product and is the principal in the transaction.
• Percent-of-proceeds arrangements – Under percent-of-proceeds arrangements, MPLX: gathers and
processes natural gas on behalf of producers; sells the resulting residue gas, condensate and NGLs at
market prices; and remits to producers an agreed-upon percentage of the proceeds. In other cases, instead
of remitting cash payments to the producer, MPLX delivers an agreed-upon percentage of the residue gas
and NGLs to the producer (take-in-kind arrangements) and sells the volumes MPLX retains to third
parties or related parties. Revenue is recognized on a net basis when MPLX acts as an agent and does not
have control of the gross amount of gas and/or NGLs prior to it being sold. Percent-of-proceeds revenue
is reported as “Service revenue - product related” on the Consolidated Statements of Income.
• Keep-whole arrangements – Under keep-whole arrangements, MPLX gathers natural gas from the
producer, processes the natural gas and sells the resulting condensate and NGLs to third parties at market
prices. Because the extraction of the condensate and NGLs from the natural gas during processing
reduces the Btu content of the natural gas, MPLX must either purchase natural gas at market prices for
return to producers or make cash payment to the producers equal to the value of the energy content of this
natural gas. Certain keep-whole arrangements also have provisions that require MPLX to share a
percentage of the keep-whole profits with the producers based on the oil to gas ratio or the NGL to gas
ratio. “Service revenue - product related” is recorded based on the value of the NGLs received on the date
the services are performed. Natural gas purchased to return to the producer and shared NGL profits are
recorded as a reduction of “Service revenue - product related” on the Consolidated Statements of Income
on the date the services are performed. Sales of NGLs under these arrangements are reported as “Product
sales” on the Consolidated Statements of Income and are reported on a gross basis as MPLX is the
principal in the arrangement and controls the product prior to sale. The sale of the NGLs may occur
shortly after services are performed at the tailgate of the plant, or after a period of time as determined by
MPLX.
• Purchase arrangements – Under purchase arrangements, MPLX purchases natural gas at either the
wellhead or the tailgate of a plant. MPLX then gathers and delivers the natural gas to pipelines
where MPLX may resell the natural gas. Wellhead purchase arrangements represent an
arrangement with a supplier and are recorded in “Purchased product costs.” Often, MPLX earns
fees for services performed prior to taking control of the product in these arrangements and
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“Service revenue” is recorded for these fees. Revenue generated from the sale of product obtained in
tailgate purchase arrangements is reported as “Product sales” on the Consolidated Statements of Income
and is recognized on a gross basis as MPLX purchases and takes control of the product prior to sale and is
the principal in the transaction.
In many cases, MPLX provides services under contracts that contain a combination of more than one of the
arrangements described above. When fees are charged (in addition to product received) under
percent-of-proceeds arrangements, keep-whole arrangements or purchase arrangements, MPLX records such fees
as “Service revenue” on the Consolidated Statements of Income. The terms of MPLX’s contracts vary based on
gas quality conditions, the competitive environment when the contracts are signed and customer requirements.
Performance obligations are determined based on the specific terms of the arrangements, economics of the
geographical regions, and the services offered and whether they are deemed distinct. MPLX allocates the
consideration earned between the performance obligations based on the stand-alone selling price when multiple
performance obligations are identified.
Revenue from MPLX’s service arrangements will generally be recognized over time as the performance
obligation is satisfied as services are provided. MPLX has elected to use the output measure of progress to
recognize revenue based on the units delivered, processed or transported. The transaction price has fixed
components related to minimum volume commitments and variable components which are primarily dependent
on volumes. Variable consideration will generally not be estimated at contract inception as the transaction price
is specifically allocable to the services provided each period. In instances in which tiered pricing structures do
not reflect our efforts to perform, MPLX will estimate variable consideration at contract inception. “Product
sales” will be recognized at a point in time when control of the product transfers to the customer.
Minimum volume commitments may create contract liabilities or deferred credits if current period payments can
be used for future services. Breakage is estimated and recognized into service revenue in instances where it is
probable the customer will not use the credit in future periods.
Amounts billed to customers for shipping and handling, electricity, and other costs to perform services are
included in “Service revenue” on the Consolidated Statements of Income. Shipping and handling costs associated
with product sales are included in “Purchased product costs” on the Consolidated Statements of Income. Facility
expenses, costs of revenues and depreciation represent those expenses related to operating our various facilities
and are necessary to provide both “Product sales” and “Service revenue.”
Customers usually pay monthly based on the products purchased or services performed that month. Taxes
collected from customers and remitted to the appropriate taxing authority are excluded from revenue.
Based on the terms of certain natural gas gathering, transportation and processing agreements, MPLX is
considered to be the lessor under several implicit operating lease arrangements in accordance with GAAP.
Revenue and costs related to the portion of the revenue earned under these contracts considered to be implicit
leases are recorded as “Rental income” and “Rental cost of sales,” respectively, on the Consolidated Statements
of Income.
Revenue and Expense Accruals – MPLX routinely makes accruals based on estimates for both revenues and
expenses due to the timing of compiling billing information, receiving certain third-party information and
reconciling MPLX’s records with those of third parties. The delayed information from third parties includes,
among other things, actual volumes purchased, transported or sold, adjustments to inventory and invoices for
purchases, actual natural gas and NGL deliveries and other operating expenses. MPLX makes accruals to reflect
estimates for these items based on its internal records and information from third parties. Estimated accruals are
adjusted when actual information is received from third parties and MPLX’s internal records have been
reconciled.
Cash and Cash Equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in
highly liquid debt instruments with initial maturities of three months or less.
Restricted Cash – Restricted cash consists of cash and investments that must be maintained as collateral for
letters of credit issued to certain third-party producer customers. The balances will be outstanding until certain
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capital projects are completed and the third party releases the restriction. Restricted cash also consists of cash
advances to be used for the operation and maintenance of an operated pipeline system. Restricted cash is
included in “Other current assets” on the Consolidated Balance Sheets.
Receivables – Receivables primarily consist of customer accounts receivable, which are recorded at the invoiced
amount and generally do not bear interest. Allowances for doubtful accounts are generally recorded when it
becomes probable that the receivable will not be collected and are recorded to bad debt expense. We review the
allowance quarterly with past-due balances over 90 days and other higher-risk amounts being reviewed
individually for collectability. Balances that remain outstanding after reasonable collection efforts have been
unsuccessful are written off through a charge to the valuation allowance and a credit to accounts receivable.
Lease Receivables - Lease receivables are the present value of the sum of the future minimum lease payments
and the unguaranteed residual value of the leased assets under arrangements where MPLX is the lessor.
Management assesses these lease receivables for recoverability quarterly.
Inventories – Inventories consist primarily of natural gas, propane, other NGLs and materials and supplies to be
used in operations. Natural gas, propane, and other NGLs are valued at the lower of cost or market value.
Materials and supplies are stated at the lower of cost or market value. Cost for materials and supplies are
determined primarily using the weighted-average cost method.
Imbalances – Within our pipelines and storage assets, we experience volume gains and losses due to pressure
and temperature changes, evaporation and variances in meter readings and other measurement methods. Until
settled, positive imbalances are recorded as other current assets and negative imbalances are recorded as accounts
payable. Positive and negative product imbalances are settled in cash, settled by physical delivery of gas from a
different source, or tracked and settled in the future.
Property, Plant and Equipment – Property, plant and equipment are recorded at cost and depreciated on a
straight-line basis over the estimated useful lives of the assets. Expenditures that extend the useful lives of assets
are capitalized. Such assets are reviewed for impairment whenever events or changes in circumstances indicate
that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash
flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an
impairment assessment is performed and the excess of the book value over the fair value is recorded as an
impairment loss.
When items of property, plant and equipment are sold or otherwise disposed of, any gains or losses are reported
on the Consolidated Statements of Income. Gains on the disposal of property, plant and equipment are
recognized when they occur, which is generally at the time of closing. If a loss on disposal is expected, such
losses are recognized when the assets are classified as held for sale.
Interest costs for the construction or development of long-lived assets are capitalized and amortized over the
related asset’s estimated useful life.
Goodwill and Intangibles – Goodwill represents the excess of the purchase price over the estimated fair value of
the net assets acquired in the acquisition of a business. Goodwill is not amortized, but rather is tested for
impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit
with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other
assets and liabilities to reporting units. The fair value of each reporting unit is determined using an income and/or
market approach which is compared to the carrying value of the reporting unit. The fair value under the income
approach is calculated using the expected present value of future cash flows method. Significant assumptions
used in the cash flow forecasts include future operating performance, future volumes, discount rates, and future
capital requirements. If the fair value of the reporting unit is less than the carrying value, including goodwill, the
excess, if any, of the book value over the fair value of the reporting unit up to the amount of goodwill recorded is
charged to net income as an impairment expense.
Amortization of intangibles with definite lives is calculated using the straight-line method which is
reflective of the benefit pattern in which the estimated economic benefit is expected to be received over the
estimated useful life of the intangible asset. Intangibles subject to amortization are reviewed for impairment
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whenever events or changes in circumstances indicate that the carrying amount of the intangible may not be
recoverable. If the sum of the expected undiscounted future cash flows related to the asset is less than the
carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Intangibles
not subject to amortization are tested for impairment annually and when circumstances indicate that the fair value
is less than the carrying amount of the intangible. If the fair value is less than the carrying value, an impairment
is recorded for the difference.
As a result of MPLX’s November 30, 2019 annual goodwill impairment analysis, we recorded an impairment
charge of approximately $1.2 billion, which resulted in a goodwill balance of $9.5 billion at December 31, 2019.
See Note 14 for further details. No impairments were recorded as a result of our 2018 annual goodwill
impairment analysis.
Other Taxes – Other taxes primarily include real estate taxes.
Environmental Costs – Environmental expenditures are capitalized if the costs mitigate or prevent future
contamination or if the costs improve environmental safety or efficiency of the existing assets. MPLX recognizes
remediation costs and penalties when the responsibility to remediate is probable and the amount of associated
costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility
study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of
known environmental exposure and are discounted when the estimated amounts are reasonably fixed and
determinable. If recoveries of remediation costs from third parties are probable, a receivable is recorded and is
discounted when the estimated amount is reasonably fixed and determinable.
Asset Retirement Obligations – An ARO is a legal obligation associated with the retirement of tangible long-
lived assets that generally result from the acquisition, construction, development or normal operation of the asset.
AROs are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can
be made, and added to the carrying amount of the associated asset. This additional carrying amount is then
depreciated over the life of the asset. The liability is determined using a credit adjusted risk free interest rate and
increases due to the passage of time based on the time value of money until the obligation is settled. MPLX
recognizes a liability of a conditional ARO as soon as the fair value of the liability can be reasonably estimated.
A conditional ARO is defined as an unconditional legal obligation to perform an asset retirement activity in
which the timing and/or method of settlement are conditional on a future event that may or may not be within the
control of the entity. AROs have not been recognized for certain assets because the fair value cannot be
reasonably estimated since the settlement dates of the obligations are indeterminate. Such obligations will be
recognized in the period when sufficient information becomes available to estimate a range of potential
settlement dates.
Investment in Unconsolidated Affiliates – Equity investments in which MPLX exercises significant influence,
but does not control and is not the primary beneficiary, are accounted for using the equity method and are
reported in “Equity method investments” on the accompanying Consolidated Balance Sheets. This includes
entities in which we hold majority ownership but the minority shareholders have substantive participating rights.
Differences in the basis of the investments and the separate net asset values of the investees, if any, are amortized
into net income over the remaining useful lives of the underlying assets and liabilities, except for the excess
related to goodwill.
MPLX believes the equity method is an appropriate means for it to recognize increases or decreases measured by
GAAP in the economic resources underlying the investments. Regular evaluation of these investments is
appropriate to evaluate any potential need for impairment. MPLX uses evidence of a loss in value to identify if
an investment has an other than a temporary decline. During the fourth quarter of 2019, two of the joint ventures
in which we have an interest recorded impairments, which impacted the amount of income from equity method
investments during the period by approximately $28 million. For one of the joint ventures, we also had a basis
difference which was being amortized over the life of the underlying assets. As a result of the impairment
recorded by the joint venture, we also assessed this basis difference for impairment and recorded approximately
$14 million of impairment during the quarter related to this investment, which was recorded through “Income
from equity method investments”. This impairment was largely due to a reduction in forecasted volumes of the
joint venture related to the loss of one of its customers.
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Deferred Financing Costs – Deferred financing costs are an asset for credit facility costs and netted against debt
for senior notes. These costs are amortized over the contractual term of the related obligations using the effective
interest method or, in certain circumstances, accelerated if the obligation is refinanced.
Derivative Instruments – MPLX may use commodity derivatives to economically hedge a portion of its exposure
to commodity price risk. All derivative instruments (including derivatives embedded in other contracts) are
recorded at fair value. Certain commodity derivatives are reflected on the consolidated balance sheets on a net
basis by counterparty as they are governed by master netting arrangements. MPLX discloses the fair value of all
derivative instruments under the captions “Other noncurrent assets,” “Other current liabilities” and “Deferred
credits and other liabilities” on the Consolidated Balance Sheets. Changes in the fair value of derivative
instruments are reported on the Consolidated Statements of Income in accounts related to the item whose value
or cash flows are being managed. All derivative instruments are marked to market through “Product sales,”
“Purchased product costs,” or “Cost of revenues” on the Consolidated Statements of Income. Revenue gains and
losses relate to contracts utilized to manage the cash flow for the sale of a product, typically NGLs. Purchased
product costs gains and losses relate to contracts utilized to manage the cost of natural gas purchases, typically
related to keep-whole arrangements. Cost of revenues gains and losses relate to a contract utilized to manage
electricity costs. Changes in risk management for unrealized activities are reported as an adjustment to net
income in computing cash flow from operating activities on the accompanying Consolidated Statements of Cash
Flows.
During the years ended December 31, 2019, 2018 and 2017, MPLX did not elect hedge accounting for any
derivatives. MPLX has elected the normal purchases and normal sales designation for certain contracts related to
the physical purchase of electric power and the sale of some commodities.
Fair Value of Financial Instruments – Management believes the carrying amount of financial instruments,
including cash and cash equivalents, receivables, receivables from related parties, other current assets, accounts
payable, accounts payable to related parties and accrued liabilities approximate fair value because of the short-
term maturity of these instruments. The recorded value of the amounts outstanding under the bank revolving
credit facility, if any, approximate fair value due to the variable interest rate that approximates current market
rates (see Note 15). Derivative instruments are recorded at fair value, based on available market information (see
Note 16).
Fair Value Measurement – Financial assets and liabilities recorded at fair value in the Consolidated Balance
Sheets are categorized based upon the fair value hierarchy established by GAAP, which classifies the inputs used
to measure fair value into Level 1, Level 2 or Level 3. A financial instrument’s categorization within the
valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The
methods and assumptions utilized may produce a fair value that may not be realized in future periods upon
settlement. Furthermore, while MPLX believes its valuation methods are appropriate and consistent with other
market participants, the use of different methodologies or assumptions to determine the fair value of certain
financial instruments could result in a different estimate of fair value at the reporting date. For further discussion
see Note 15.
Equity-Based Compensation Arrangements – MPLX issues phantom units under its share-based compensation
plan as described further in Note 21. A phantom unit entitles the grantee a right to receive a common unit upon
the issuance of the phantom unit. The fair value of phantom unit awards granted to employees and non-employee
directors is based on the fair market value of MPLX LP common units on the date of grant. The fair value of the
units awarded is amortized into earnings using a straight-line amortization schedule over the period of service
corresponding with the vesting period. For phantom units that vest immediately and are not forfeitable, equity-
based compensation expense is recognized at the time of grant.
Performance units paying out in cash are accounted for as liability awards and recorded at fair value with a
mark-to-market adjustment made each quarter. The performance units paying out in units are accounted for as
equity awards and use a Monte Carlo valuation model to calculate a grant date fair value.
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To satisfy common unit awards, MPLX may issue new common units, acquire common units in the open market
or use common units already owned by the general partner.
Tax Effects of Share-Based Compensation – MPLX elected to adopt the simplified method to establish the
beginning balance of the additional paid-in capital pool (“APIC Pool”) related to the tax effects of employee
share-based compensation and to determine the subsequent impact on the APIC Pool and Consolidated
Statements of Cash Flows of the tax effects of share-based compensation awards that were outstanding upon
adoption. Additional paid-in capital is reported as “Common unitholders - public” on the accompanying
Consolidated Balance Sheets.
Income Taxes – MPLX is not a taxable entity for United States federal income tax purposes or for the majority
of the states that impose an income tax. Taxes on MPLX’s net income generally are borne by its partners through
the allocation of taxable income. MPLX’s taxable income or loss, which may vary substantially from the net
income or loss reported on the Consolidated Statements of Income, is includable in the federal income tax returns
of each partner. MPLX and certain legal entities are, however, taxable entities under certain state jurisdictions.
MPLX accounts for income taxes under the asset and liability method. Deferred income taxes are recognized for
the future tax consequences attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax basis, capital loss carryforwards and net operating loss and
credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates applied to taxable
income in the years in which those temporary differences are expected to be recovered or settled. The effect of
any tax rate change on deferred taxes is recognized as tax expense/(benefit) from continuing operations in the
period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed and,
if not more likely than not, a valuation allowance is recorded to reflect the deferred tax assets at net realizable
value as determined by management. All deferred tax balances are classified as long-term in the accompanying
Consolidated Balance Sheets. All changes in the tax bases of assets and liabilities are allocated among operations
and items charged or credited directly to equity.
Distributions – In preparing the Consolidated Statements of Equity, net income attributable to MPLX LP is
allocated to Series A and Series B preferred unitholders based on a fixed distribution schedule, as discussed in
Notes 8 and 9, and subsequently allocated to the general partner and limited partner unitholders. Distributions,
although earned, are not accrued as a liability until declared. However, when distributions related to the
eliminated IDRs were made, earnings equal to the amount of those distributions were 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 below.
Net Income Per Limited Partner Unit – MPLX uses the two-class method when calculating the net income per
unit applicable to limited partners, because there is more than one class of participating security. The classes of
participating securities include common units, general partner units, Series A and Series B preferred units, certain
equity-based compensation awards and eliminated IDRs. Class B units were considered to be a separate class of
common units that did not participate in distributions.
Net income attributable to MPLX LP is allocated to the unitholders differently for preparation of the
Consolidated Statements of Equity and the calculation of net income per limited partner unit. In preparing the
Consolidated Statements of Equity, net income attributable to MPLX LP is allocated to Series A and Series B
preferred unitholders based on a fixed distribution schedule and subsequently allocated to remaining unitholders
in accordance with their respective ownership percentages. However, prior to 2018 when distributions related to
the eliminated IDRs were 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, except Class B unitholders, based
on their respective ownership percentages. Subsequent to the conversion of the general partner to a
non-economic interest as described in Note 8, no earnings are allocated to the general partner. Distributions,
although earned, are not accrued until declared. The allocation of net income attributable to MPLX LP for
purposes of calculating net income per limited partner unit is described in Note 7.
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In preparing net income per limited partner units, during periods in which a net loss attributable to MPLX is
reported or periods in which the total distributions exceed the reported net income attributable to MPLX’s
unitholders, the amount allocable to certain equity-based compensation awards is based on actual distributions to
the equity-based compensation awards. Diluted earnings per unit is calculated by dividing net income attributable
to MPLX’s common unitholders, after deducting amounts allocable to other participating securities, by the
weighted average number of common units and potential common units outstanding during the period. Potential
common units are excluded from the calculation of diluted earnings per unit during periods in which net income
attributable to MPLX’s unitholders, after deducting amounts that are allocable to the outstanding equity-based
compensation awards, preferred units, and eliminated IDRs, is a loss as the impact would be anti-dilutive.
Business Combinations – MPLX recognizes and measures the assets acquired and liabilities assumed in a
business combination based on their estimated fair values at the acquisition date, with any remaining difference
recorded as goodwill or gain from a bargain purchase. Depending on the nature of the transaction, management
may engage an independent valuation specialist to assist with the determination of fair value of the assets
acquired, liabilities assumed, noncontrolling interests, if any, and goodwill, based on recognized business
valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the
reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and
not later than one year from the acquisition date, MPLX will record any material adjustments to the initial
estimate based on new information obtained that would have existed as of the acquisition date. An adjustment
that arises from information obtained that did not exist as of the date of the acquisition will be recorded in the
period of the adjustment. An income, market or cost valuation method may be utilized to estimate the fair value
of the assets acquired, liabilities assumed, and noncontrolling interests, if any, in a business combination. The
income valuation method represents the present value of future cash flows over the life of the asset using:
(i) discrete financial forecasts, which rely on management’s estimates of volumes, NGL prices, revenue and
operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market valuation method
uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments relating to any
differences between the assets. The cost valuation method is based on the replacement cost of a comparable asset
at prices at the time of the acquisition reduced for depreciation of the asset. Acquisition-related costs are
expensed as incurred in connection with each business combination.
Acquisitions in which the company or business being acquired by MPLX had an existing relationship with MPC
may result in the transaction being considered a transfer between entities under common control. In this
situations, MPLX records the assets acquired and liabilities assumed on its consolidated balance sheets at MPC’s
historical carrying value. Transfers of businesses between entities under common control require prior periods to
be retrospectively adjusted for those dates that the entity was under common control. See Note 4 for more
information about the acquisitions.
Accounting for Changes in Ownership Interests in Subsidiaries – MPLX’s ownership interest in a consolidated
subsidiary may change if it sells a portion of its interest or acquires additional interest or if the subsidiary issues
or repurchases its own shares. If the transaction does not result in a change in control over the subsidiary, the
transaction is accounted for as an equity transaction. If a sale results in a loss of control, it would result in the
deconsolidation of a subsidiary with a gain or loss recognized on the Consolidated Statements of Income unless
the subsidiary meets the definition of in-substance real estate. Deconsolidation of in-substance real estate is
recorded at cost with no gain or loss recognized. If the purchase of additional interest occurs that changes the
acquirer’s ownership interest from noncontrolling to controlling, the acquirer’s preexisting interest in the
acquiree is remeasured to its fair value, with a resulting gain or loss recorded in earnings upon consummation of
the business combination. Once an entity has control of a subsidiary, its acquisitions of some or all of the
noncontrolling interests in that subsidiary are accounted for as equity transactions and are not considered to be a
business combination.
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3. Accounting Standards
Recently Adopted
ASU 2016-02, Leases
We adopted ASU No. 2016-02, Leases (Topic 842), as of January 1, 2019, electing the transition method, which
permits entities to adopt the provisions of the standard using the modified retrospective approach without
adjusting comparative periods. We also elected the package of practical expedients permitted under the transition
guidance within the new standard, which among other things, allowed us to grandfather the historical accounting
conclusions until a reassessment event is present. We have also elected the practical expedient to not recognize
short-term leases on the balance sheet, the practical expedient related to right of way permits and land easements
which allows us to carry forward our accounting treatment for those existing agreements, and the practical
expedient to combine lease and non-lease components for the majority of our underlying classes of assets except
for our third-party contractor service and equipment agreements and boat and barge equipment agreements in
which we are the lessee. We did not elect the practical expedient to combine lease and non-lease components for
arrangements in which we are the lessor. In instances where the practical expedient was not elected, lease and
non-lease consideration is allocated based on relative standalone selling price.
Right of use (“ROU”) assets represent our right to use an underlying asset in which we obtain substantially all of
the economic benefits and the right to direct the use of the asset during the lease term. Lease liabilities represent
our obligation to make lease payments arising from the lease. Operating lease ROU assets and lease liabilities are
recognized at the commencement date based on the present value of lease payments over the lease term. We
recognize ROU assets and lease liabilities on the balance sheet for leases with a lease term of greater than one
year. Payments that are not fixed at the commencement of the lease are considered variable and are excluded
from the ROU asset and lease liability calculations. In the measurement of our ROU assets and lease liabilities,
the fixed lease payments in the agreement are discounted using a secured incremental borrowing rate for a term
similar to the duration of the lease, as our leases do not provide implicit rates. Operating lease expense is
recognized on a straight-line basis over the lease term.
Adoption of the new standard resulted in the recording of ROU assets and lease liabilities of approximately
$629 million and $629 million, respectively, as of January 1, 2019. This is inclusive of ROU assets and lease
liabilities related to ANDX of $124 million and $127 million, respectively. The standard did not materially
impact our consolidated statements of income, cash flows or equity as a result of adoption.
As a lessor under ASC 842, MPLX may be required to re-classify existing operating leases to sales-type leases
upon modification and related reassessment of the leases. See Note 22 for further information regarding our
ongoing evaluation of the impacts of lease reassessments as modifications occur.
ASU 2017-04, Intangibles - Goodwill and Other - Simplifying the Test for Goodwill Impairment
In connection with our annual goodwill impairment test, we adopted ASU 2017-04 prospectively during the
fourth quarter of 2019. Under ASU 2017-04, 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 former 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. During the fourth
quarter of 2019, we recorded certain goodwill impairment charges as described in Note 14.
We also adopted the following standard during 2019, which did not have a material impact to our financial
statements or financial statement disclosures:
ASU
Effective Date
2017-12 Derivatives and Hedging - Targeted Improvements to Accounting for Hedging
January 1, 2019
Activities
123
Not Yet Adopted
ASU 2016-13, Credit Losses - Measurement of Credit Losses on Financial Instruments
In June 2016, the FASB issued an ASU related to the accounting for credit losses on certain financial
instruments. The guidance requires that for most financial assets, losses be 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 application
of this ASU will not have a material impact on our consolidated financial statements.
4. Acquisitions
Acquisition of Andeavor Logistics LP
On May 7, 2019, ANDX, Tesoro Logistics GP, LLC, then the general partner of ANDX (“TLGP”), MPLX,
MPLX GP LLC, the general partner of MPLX (“MPLX GP”), and MPLX MAX LLC, a wholly-owned
subsidiary of MPLX (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”)
that provided for, among other things, the merger of Merger Sub with and into ANDX. On July 30, 2019, the
Merger was completed, and ANDX survived the Merger as a wholly-owned subsidiary of MPLX. At the
effective time of the Merger, each common unit held by ANDX’s public unitholders was converted into the right
to receive 1.135 MPLX common units. ANDX common units held by certain affiliates of MPC were converted
into the right to receive 1.0328 MPLX common units. See Note 8 for information on common units issued in
connection with the Merger as well as Series B preferred units.
Additionally, as a result of the Merger, each ANDX TexNew Mex Unit issued and outstanding immediately prior
to the effective time of the Merger was converted into a right for Western Refining Southwest, Inc. (“Southwest,
Inc.”), a wholly-owned subsidiary of MPC, as the holder of all such units, to receive a unit representing a
substantially equivalent limited partner interest in MPLX (the “MPLX TexNew Mex Units”). By virtue of the
conversion, all ANDX TexNew Mex Units were cancelled and ceased to exist as of the effective time of the
Merger. The MPLX TexNew Mex Units are a new class of units in MPLX substantially equivalent to the ANDX
TexNew Mex Units, including substantially equivalent rights, powers, duties and obligations that the ANDX
TexNew Mex Units had immediately prior to the closing of the Merger. As a result of the Merger, the ANDX
Special Limited Partner Interest outstanding immediately prior to the effective time of the Merger was converted
into a right for Southwest Inc., as the holder of all such interest, to receive a substantially equivalent special
limited partner interest in MPLX (the “MPLX Special Limited Partner Interest”). By virtue of the conversion, the
ANDX Special Limited Partner Interest was cancelled and ceased to exist as of the effective time of the Merger.
For information on ANDX’s preferred units, please see Note 8.
The assets of ANDX consist of a network of owned and operated crude oil, refined product and natural gas
pipelines; crude oil and water gathering systems; refining logistics assets; terminals with crude oil and refined
products storage capacity; rail facilities; marine terminals including storage; bulk petroleum distribution
facilities; a trucking fleet; and natural gas processing and fractionation complexes. The assets are located in the
western and inland regions of the United States and complement MPLX’s existing business and assets.
MPC accounted for its October 1, 2018 acquisition of Andeavor (including acquiring control of ANDX), using
the acquisition method of accounting, which required Andeavor assets and liabilities to be recorded by MPC at
the acquisition date fair value. The Merger was closed on July 30, 2019, and the results of ANDX have been
incorporated into the results of MPLX as of October 1, 2018, which is the date that common control was
established. As a result of MPC’s relationship with both MPLX and ANDX, the Merger has been treated as a
common control transaction, which requires the recasting of MPLX’s historical results and the recognition of
assets acquired and liabilities assumed using MPC’s historical carrying value. The fair value of assets acquired
and liabilities assumed shown below represents MPC’s historical carrying values as of October 1, 2018.
124
(In millions)
Cash and cash equivalents
Receivables, net
Inventories
Other current assets(2)
Equity method investments
Property, plant and equipment, net
Intangibles, net(3)
Other noncurrent assets(4)
Total assets acquired
Accounts payable
Other current liabilities(5)
Long-term debt
Deferred credits and other long-term liabilities(6)
Total liabilities assumed
Net assets acquired excluding goodwill
Goodwill
Total purchase price
$
As Originally
Reported
Adjustments(1)
As Adjusted
$
83
241
21
59
731
6,709
960
31
8,835
198
188
4,916
75
5,377
3,458
7,428
$
(53)
259
—
(7)
(89)
(427)
74
(8)
(251)
265
(41)
—
1
225
(476)
724
30
500
21
52
642
6,282
1,034
23
8,584
463
147
4,916
76
5,602
2,982
8,152
$
10,886
$
248
$
11,134
(1)
(2)
(3)
(4)
(5)
(6)
Inclusive of activity recorded subsequent to the acquisition of ANDX on July 30, 2019, a portion of which was recorded
as a non-cash contribution from MPC.
Includes both related party and third party other current assets.
Includes approximately $4 million of favorable lease assets. In connection with the implementation of ASC 842, this
balance was reclassed to “Right of use assets” on the Consolidated Balance Sheets during 2019.
Includes both related party and third party other noncurrent assets as well as right of use assets associated with leases.
Includes accrued liabilities, operating lease liabilities, long-term debt due within one year, as well as related party and
third party other current liabilities.
Includes deferred revenue and deferred income taxes, as well as related party and third party other noncurrent liabilities.
Details of our valuation methodology and significant inputs for fair value measurements are included by asset
class below. The fair value measurements for equity method investments; property, plant and equipment;
intangible assets and long-term debt are based on significant inputs that are not observable in the market and,
therefore, represent Level 3 measurements.
Goodwill
The purchase consideration allocation resulted in the recognition of $8.2 billion in goodwill, which has been
allocated between the L&S segment and the G&P segment at $7.2 billion and $1.0 billion, respectively. See Note
14 for further information related to goodwill.
Inventory
The fair value of inventory was recorded at cost as of October 1, 2018, as these items are related to spare parts as
well as materials and supplies and approximate fair value.
Equity Method Investments
The fair value of the equity method investments was $642 million, which was determined based on applying
income and market approaches. The income approach relied on the discounted cash flow method and the market
approach relied on a market multiple approach considering historical and projected financial results. Discount
rates for the discounted cash flow models were based on capital structures for similar market participants and
included various risk premiums that account for risks associated with the specific investments.
125
Property, Plant and Equipment
The fair value of property, plant and equipment was $6.3 billion, which was based primarily on the cost
approach. Key assumptions in the cost approach include determining the replacement cost by evaluating recent
purchases of similar assets or published data, and adjusting replacement cost for economic and functional
obsolescence, location, normal useful lives, and capacity (if applicable).
Acquired Intangible Assets
The fair value of the acquired identifiable intangible assets was $1.0 billion, which represents the value of
various customer contracts and relationships and other intangible assets. The fair value of customer contracts and
relationships was $950 million, which was valued by applying the multi-period excess earnings method, which is
an income approach. Key assumptions in the income approach include the underlying contract cash flow
estimates, remaining contract term, probability of renewal, growth rates and discount rates. The intangible assets
are all finite lived and will be amortized over two to 10 years.
Debt
The fair value of the ANDX notes was measured using a market approach, based upon the average of quotes for
the acquired debt from major financial institutions and a third-party valuation service. Additionally,
approximately $1.1 billion of borrowings under revolving credit agreements approximated fair value. The ANDX
revolving credit facilities with total capacity of $2.1 billion were terminated upon closing of the Merger and were
repaid with borrowings under the MPLX revolving credit facility.
Acquisition Costs
We recognized $14 million in acquisition costs during 2019, which are reflected in general and administrative
expenses.
ANDX Revenue and Net Income
For the year ended December 31, 2019, we recognized $2,400 million of revenues and other income related to
ANDX and $266 million of net loss related to ANDX, which was impacted by the goodwill impairment
discussed in Note 14. For the year ended December 31, 2018, we recognized $580 million of revenues and other
income related to ANDX and $172 million of net income related to ANDX.
Pro Forma Financial Information
The following unaudited pro forma information combines the historical operations of MPLX and ANDX, giving
effect to the Merger as if it had been consummated on January 1, 2018, the beginning of the earliest period
presented.
(In millions)
Total revenues and other income
Net income attributable to MPLX LP
2019
2018
$
$
9,041
1,434
$
$
8,666
2,446
The pro forma information includes adjustments to align accounting policies, which include adjustments for
capitalization of assets and treatment of planned major maintenance costs. The pro forma information also
includes adjustments related to: eliminating transactions between MPLX and ANDX, which previously would
have been recorded as transactions between related parties; basis differences on equity method investments as a
result of recognition of MPC’s investments in ANDX’s equity method investments; depreciation and
amortization expense to reflect the increased fair value of property, plant and equipment and increased
amortization expense related to identifiable intangible assets, as well as adjustments to interest expense for the
amortization of fair value adjustments over the remaining term of ANDX’s outstanding debt, reversal of
ANDX’s historical amortization of debt issuance costs and debt discounts and to adjust for the difference in the
weighted average interest rate between MPLX’s revolving credit facility and ANDX’s revolving credit facilities.
126
The following table presents MPLX’s previously reported Consolidated Balance Sheet Data as of December 31,
2018 retrospectively adjusted for the Merger:
(In millions)
Assets
Current assets:
Cash and cash equivalents
Receivables, net
Current assets - related parties
Inventories
Other current assets
Total current assets
Equity method investments
Property, plant and equipment, net
Intangibles, net
Goodwill
Noncurrent assets - related parties
Other noncurrent assets
Total assets
Liabilities
Current liabilities:
Accounts payable
Accrued liabilities
Current liabilities - related parties
Accrued property, plant and equipment
Accrued interest payable
Other current liabilities
Total current liabilities
Long-term deferred revenue
Long-term liabilities - related parties
Long-term debt
Deferred income taxes
Deferred credits and other liabilities
Total liabilities
Commitments and contingencies (see Note 20)
Series A preferred units
Equity
Common unitholders - public
Common unitholder - MPC
Equity of Predecessor
Accumulated other comprehensive loss
Total MPLX LP partners’ capital
Noncontrolling interests
Total equity
December 31, 2018
MPLX LP
(Previously
Reported)
Predecessor
MPLX LP
(Currently
Reported)
$
$
68
417
290
77
45
897
4,174
14,639
424
2,586
24
35
22,779
162
250
254
294
143
83
1,186
80
43
13,392
13
197
14,911
1,004
8,336
(1,612)
—
(16)
6,708
156
6,864
$
9
194
266
21
53
543
727
6,886
935
7,430
—
25
16,546
104
22
248
105
41
562
1,082
52
3
4,530
1
11
5,679
—
—
—
10,867
—
10,867
—
10,867
77
611
556
98
98
1,440
4,901
21,525
1,359
10,016
24
60
39,325
266
272
502
399
184
645
2,268
132
46
17,922
14
208
20,590
1,004
8,336
(1,612)
10,867
(16)
17,575
156
17,731
39,325
Total liabilities, preferred units and equity
$
22,779
$
16,546
$
127
Mt. Airy Terminal
On September 26, 2018, MPLX acquired an eastern U.S. Gulf Coast export terminal (the “Mt. Airy Terminal”)
from Pin Oak Holdings, LLC for total consideration of $451 million. At the time of the acquisition, the terminal
included tanks with 4 million barrels of third-party leased storage capacity and a dock with 120 mbpd of
capacity. The Mt. Airy Terminal is located on the Mississippi River between New Orleans and Baton Rouge, is
in close proximity to several Gulf Coast refineries including MPC’s Garyville Refinery and is near numerous rail
lines and pipelines. The Mt. Airy Terminal is accounted for within the L&S segment. In the first quarter of 2019,
an adjustment to the initial purchase price was made for approximately $5 million related to the final settlement
of the acquisition, which was paid in the first six months of 2019 as shown on the statement of cash flow. This
reduced the total purchase price to $446 million and resulted in $336 million of property, plant and equipment,
$121 million of goodwill and the remainder being attributable to net liabilities assumed.
Based on the fair value estimates of assets acquired and liabilities assumed at the acquisition date, the purchase
price was allocated as follows:
(In millions)
Receivables, net
Other current assets
Property, plant and equipment, net
Intangibles, net
Goodwill
Accounts payable
Other current liabilities
Net assets acquired
Balance as of
September 26, 2018
$
$
3
1
336
9
121
(17)
(7)
446
Goodwill represents the significant growth potential of the terminal due to the multiple pipelines and rail lines
which cross the property, the terminal’s position as an aggregation point for liquids growth in the region for both
ocean-going export vessels and inland barges, the proximity of the terminal to MPC’s Garyville refinery and
other refineries in the region as well as the opportunity to construct an additional dock at the site.
The amount of revenue and income from operations associated with the acquisition of the Mt. Airy Terminal
included on the Consolidated Statement of Income since the September 26, 2018 acquisition date was not
material to the financial statements. Assuming the acquisition had occurred on January 1, 2017, the consolidated
pro forma results would not have been materially different from the reported results.
Refining Logistics and Fuels Distribution Acquisition
On February 1, 2018, MPC and MPLX LP closed on an agreement for the dropdown of refining logistics
assets and fuels distribution services to MPLX LP. MPC contributed these assets and services in exchange
for $4.1 billion in cash and a fixed number of MPLX LP common units and general partner units of
111,611,111 and 2,277,778, respectively. The fair value of the common and general partner units issued as
of the acquisition date was $4.3 billion based on the closing common unit price as of February 1, 2018, as
recorded on the Consolidated Statements of Equity, for a total purchase price of $8.4 billion. The equity
issued consisted of: (i) 85,610,278 common units to MPLX GP LLC (“MPLX GP”), (ii) 18,176,666
common units to MPLX Logistics Holdings LLC (“MPLX Logistics”) and (iii) 7,824,167 common units to
MPLX Holdings Inc. (“MPLX Holdings”). MPLX also issued 2,277,778 general partner units to MPLX GP
in order to maintain its two percent general partner interest (“GP Interest”) in MPLX. MPC agreed to waive
approximately one-third of the first quarter 2018 distributions on the common units issued in connection
with this transaction. As a result of this waiver, MPC did not receive $23.7 million of the distributions that
would have otherwise accrued on such common units with respect to the first quarter 2018. Immediately
128
following this transaction, the GP Interest was converted into a non-economic general partner interest as
discussed in Note 8.
MPLX recorded this transaction on a historical basis as required for transactions between entities under common
control. No effect was given to the prior periods as these entities were not considered businesses prior to the
February 1, 2018 dropdown. In connection with the dropdown, approximately $830 million of net property, plant
and equipment was recorded in addition to $85 million and $130 million of goodwill allocated to MPLX
Refining Logistics LLC (“Refining Logistics”) and MPLX Fuels Distribution LLC (“Fuels Distribution”),
respectively. Both the Refining Logistics assets and the Fuels Distribution services are accounted for within the
L&S segment.
As of the transaction date, the Refining Logistics assets included 619 tanks with approximately 56 million barrels
of storage capacity (crude, finished products and intermediates), 32 rail and truck racks, 18 docks, and gasoline
blenders. These assets generate revenue through storage services agreements with MPC. Refining Logistics
provides certain services to MPC related to the receipt, storage, throughput, custody and delivery of petroleum
products in and through certain storage and logistical facilities and assets associated with MPC’s refineries.
Fuels Distribution, which is a wholly owned subsidiary of MPLXT, generates revenue through a Fuels
Distribution Services Agreement with MPC. Fuels Distribution is structured to provide a broad range of
scheduling and marketing services as MPC’s agent.
The amounts of revenue and income from operations associated with these investments included on the
Consolidated Statements of Income, since the February 1, 2018 acquisition date, were as follows:
(In millions)
Revenues and other income
Income from operations
Joint-Interest Acquisition
Twelve Months
Ended
December 31, 2018
$
$
1,359
874
On September 1, 2017, MPLX entered into a Membership Interests and Shares Contributions Agreement with
MPLX GP, MPLX Logistics, MPLX Holdings and MPC Investment LLC (“MPC Investment”), each a wholly-
owned subsidiary of MPC, whereby MPLX agreed to acquire certain ownership interests in joint venture entities
indirectly held by MPC. Pursuant to the agreement, MPC Investment agreed to contribute: all of the membership
interests of Lincoln Pipeline LLC, which holds a 35 percent interest in Illinois Extension; all of the membership
interests of MPL Louisiana Holdings LLC, which holds a 41 percent interest in LOOP; a 59 percent interest in
LOCAP; and a 25 percent interest in Explorer, through a series of intercompany contributions to MPLX 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 trailing 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. MPLX also issued 377,778
general partner units to MPLX GP in order to maintain its two percent GP Interest in MPLX.
Illinois Extension operates the 168-mile, 24-inch diameter Southern Access Extension 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-
129
mile common carrier pipeline that primarily transports gasoline, diesel, diluent and jet fuel from the Gulf
Coast region to the Midwest United States. MPLX accounts for the Joint-Interest Acquisition entities as
equity method investments within its L&S segment.
As a transfer between entities under common control, MPLX recorded the Joint-Interest Acquisition on its
Consolidated Balance Sheets at MPC’s historical basis, which included accumulated other comprehensive loss.
MPLX 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 is not a sponsor of these benefit plans.
Distributions of cash received from the entities and interests acquired in the Joint-Interest Acquisition related to
periods prior to the acquisition were prorated on a daily basis with MPLX retaining the portion of distributions
beginning on the closing date. All amounts distributed to MPLX related to periods before the acquisition have
been paid to MPC. Additionally, MPLX 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 could not be
reasonably quantified, a liability was not recorded in connection with the acquisition. MPLX subsequently
received distributions related to the time period prior to the acquisition, which it remitted to MPC and recorded a
corresponding decrease to the general partner’s equity for $32 million.
MPLX accounts for the interests acquired in the Joint-Interest Acquisition one month in arrears, which is the
most recently available information. The amount of income associated with these investments included on the
Consolidated Statements of Income under the caption “Income from equity method investments” for the twelve
months ended December 31, 2019, December 31, 2018 and December 31, 2017 totaled $110 million,
$118 million and $21 million, respectively. 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 MPLX 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
MPLX for approximately $1.5 billion in cash and equity consideration valued at approximately $504 million.
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, 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. MPLX
also issued 264,497 general partner units to MPLX GP in order to maintain its two percent GP Interest in MPLX.
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 eight 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
130
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. MPLX accounts for these businesses within its
L&S segment.
MPLX 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.
Acquisition of Ozark Pipeline
On March 1, 2017, MPLX 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 assumed at the acquisition date, the purchase price was primarily
allocated to property, plant and equipment. The Ozark pipeline is a 433-mile, 22-inch crude oil pipeline
originating in Cushing, Oklahoma, and terminating in Wood River, Illinois, capable of transporting
approximately 230 mbpd. MPLX accounts for the Ozark pipeline within its L&S segment.
The amounts of revenue and income from operations associated with the acquisition included on the
Consolidated Statements of Income, since the March 1, 2017 acquisition date are as follows:
(In millions)
Revenues and other income
Income from operations
Twelve Months
Ended December 31,
2017
$
$
64
20
Assuming the acquisition of the Ozark pipeline had occurred on January 1, 2017, the consolidated pro forma
results would not have been materially different from reported results.
MarEn Bakken
On February 15, 2017, MPLX closed on a joint venture, MarEn Bakken Company, LLC (“MarEn Bakken”), with
Enbridge Energy Partners L.P. in which MPLX LP acquired a partial, indirect interest in 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, LP. The Bakken Pipeline
system is capable of transporting more than 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. MPLX contributed
$500 million of the $2.0 billion purchase price paid by MarEn Bakken to acquire a 37 percent indirect interest in
the Bakken Pipeline system. MPLX holds, through a subsidiary, a 25 percent interest in MarEn Bakken, which
equates to an approximate 9 percent indirect interest in the Bakken Pipeline system.
MPLX accounts for its investment in MarEn Bakken as an equity method investment and bases the equity
method accounting for this joint venture one month in arrears which is the most recently available information.
The amount of income or loss associated with these investments included on the Consolidated Statements of
Income under the caption “Income from equity method investments” for the twelve months ended December 31,
2019, December 31, 2018 and December 31, 2017 totaled $72 million, $48 million and $15 million, respectively.
In connection with MPLX’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. This waiver is no longer applicable as a
result of the conversion of the GP Interest to a non-economic general partner interest as discussed in Note 8.
131
5. Investments and Noncontrolling Interests
The following table presents MPLX’s equity method investments at the dates indicated:
(In millions, except ownership percentages)
2019
2019
2018
Ownership as of
December 31,
Carrying value at
December 31,
L&S
MarEn Bakken Company LLC
Illinois Extension Pipeline Company, L.L.C.
LOOP LLC
Andeavor Logistics Rio Pipeline LLC(1)
Minnesota Pipe Line Company, LLC(1)
Whistler Pipeline LLC
Wink to Webster Pipeline LLC
Explorer Pipeline Company
Other(1)
Total L&S
G&P
MarkWest Utica EMG, L.L.C.
Sherwood Midstream LLC
MarkWest EMG Jefferson Dry Gas Gathering Company,
L.L.C.
Rendezvous Gas Services, L.L.C.(1)
Sherwood Midstream Holdings LLC
Centrahoma Processing LLC
Other(1)
Total G&P
Total
$
25%
35%
41%
67%
17%
38%
15%
25%
56%
50%
67%
78%
53%
40%
$
481
265
238
202
190
134
126
83
55
1,774
1,984
537
302
170
157
153
198
3,501
$
5,275
$
498
275
226
181
197
—
—
90
51
1,518
2,039
366
236
248
157
160
177
3,383
4,901
(1) These investments as well as certain investments included within “Other” for both L&S and G&P are investments
acquired as part of the Merger. The December 31, 2019 balance reflects all purchase accounting adjustments identified
by MPC as part of its acquisition of Andeavor.
As a result of the Merger, MPLX acquired an ownership interest in Rendezvous Gas Services, L.L.C. (“RGS”),
Minnesota Pipe Line Company, LLC (“MNPL”) and Andeavor Logistics Rio Pipeline LLC (“ALRP”), among
others. RGS and ALRP have been deemed to be VIEs; however, neither MPLX nor any of its subsidiaries have
been deemed to be the primary beneficiary due to voting rights on significant matters. For all of the investments
acquired through the Merger, we have the ability to exercise influence through participation in the management
committees which make all significant decisions. However, since we have equal or proportionate influence over
each committee as a joint interest partner and all significant decisions require the consent of the other investors
without regard to economic interest, we have determined that these entities should not be consolidated and apply
the equity method of accounting with respect to our investments in each entity.
In addition to the investments acquired through the Merger, MarkWest Utica EMG, L.L.C. (“MarkWest
Utica EMG”), Sherwood Midstream LLC (“Sherwood Midstream”), MarkWest EMG Jefferson Dry Gas
Gathering Company, L.L.C. (“Jefferson Dry Gas”) and Sherwood Midstream Holdings LLC (“Sherwood
Midstream Holdings”) are also deemed to be VIEs. However, consistent with the investments above, neither
MPLX nor any of its subsidiaries are deemed to be the primary beneficiary due to voting rights on
significant matters. 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, MPLX also reports its
132
portion of Sherwood Midstream Holdings’ net assets as a component of its investment in Sherwood
Midstream. As of December 31, 2019, MPLX has a 23.7 percent indirect ownership interest in Sherwood
Midstream Holdings through Sherwood Midstream. During 2019, MPLX acquired equity interests in
Whistler Pipeline LLC and Wink to Webster Pipeline LLC. Both joint ventures are located in the Permian
Basin and will transport crude oil or natural gas to the U.S. Gulf Coast. These investments are deemed to be
VIEs; however, MPLX does not operate these joint ventures and is not deemed to be the primary beneficiary
due to voting rights on significant matters as described above.
MPLX’s maximum exposure to loss as a result of its involvement with 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. MPLX
did not provide any financial support to equity method investments that it was not contractually obligated to
provide during the years ended December 31, 2019, 2018 and 2017.
During the fourth quarter of 2019, two joint ventures in which we have an interest recorded impairments, which
impacted the amount of income from equity method investments during the period by approximately $28 million
and took the carrying value of one of the investments to zero. For the other joint venture, we had a basis
difference recorded which was being amortized over the life of the underlying assets. As a result of the
impairment recorded by the joint venture, we assessed our investment, including the related basis difference, for
impairment and recorded an additional $14 million of impairment during the quarter related to our basis
difference. The fair value of the investment was determined based upon applying the discounted cash flow
method, which is an income approach. The discounted cash flow fair value estimate is based on known or
knowable information at the interim measurement date. The significant assumptions that were used to develop
the estimate of the fair value under the discounted cash flow method include management’s best estimates of the
expected future results using a probability-weighted average set of cash flow forecasts and the discount rate. Fair
value determinations require considerable judgment and are sensitive to changes in underlying assumptions and
factors. As such, the fair value of these equity method investments represents a Level 3 measurement. As a result,
there can be no assurance that the estimates and assumptions made for purposes of the impairment test will prove
to be an accurate prediction of the future. The impairment of the basis difference was also recorded through
“Income from equity method investments” for a total impact during the quarter of approximately $42 million.
The impairments were largely due to a reduction in forecasted volumes of the joint ventures.
Summarized financial information for MPLX’s equity method investments for the years ended December 31,
2019, 2018 and 2017 is as follows:
(In millions)
Revenues and other income
Costs and expenses
Income from operations
Net income
Income from equity method investments(2)
(In millions)
Revenues and other income
Costs and expenses
Income from operations
Net income
Income from equity method investments(2)
133
December 31, 2019(1)
Other VIEs
Non-VIEs
Total
$
$
650
375
275
215
103
$
$
1,417
568
849
752
187
$
$
2,067
943
1,124
967
290
December 31, 2018(1)
Other VIEs
Non-VIEs
Total
$
$
484
286
198
197
67
$
$
1,421
738
683
606
180
$
$
1,905
1,024
881
803
247
(In millions)
December 31, 2017(1)
Other VIEs
Non-VIEs
Total
Revenues and other income
Costs and expenses
Income from operations
Net income
Income from equity method investments(2)
(1) The financial information for equity method investments for 2019 includes financial information of equity method
954
520
434
345
48
273
139
134
133
30
$
$
$
$
$
$
1,227
659
568
478
78
investments acquired as part of the Merger. The financial information for equity method investments for 2018 includes
financial information of equity method investments acquired as part of the Merger for the last three months of 2018. The
financial information for equity method investments for 2017 does not include financial information of equity method
investments acquired as part of the Merger. See Note 1 for additional information.
(2) “Income from equity method investments” includes the impact of any basis differential amortization or accretion.
Summarized balance sheet information for MPLX’s equity method investments as of December 31, 2019 and
2018 is as follows:
(In millions)
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
(In millions)
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
December 31, 2019
Other VIEs
Non-VIEs
Total
$
$
$
$
534
5,862
192
305
$
$
330
5,134
245
822
$
$
864
10,996
437
1,127
December 31, 2018
Other VIEs
Non-VIEs
Total
252
3,796
158
191
$
$
415
5,290
280
845
$
$
667
9,086
438
1,036
As of December 31, 2019 and 2018, the carrying value of MPLX’s equity method investments in the G&P
segment exceeded the underlying net assets of its investees by $1.0 billion and $1.3 billion, respectively. As of
December 31, 2019 and 2018, the carrying value of MPLX’s equity method investments in the L&S segment
exceeded the underlying net assets of its investees by $329 million and $187 million, respectively. This basis
difference is being amortized into net income over the remaining estimated useful lives of the underlying net
assets, except for $498 million and $167 million of excess related to goodwill for the G&P and L&S segments,
respectively, as of December 31, 2019 and $542 million and $167 million of excess related to goodwill for the
G&P and L&S segments, respectively, as of December 31, 2018.
6. Related Party Agreements and Transactions
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 are further described below.
MPLX has various long-term, fee-based commercial agreements with MPC. Under these agreements,
MPLX provides transportation, terminal, fuels distribution, marketing, storage, management, operational
and other services to MPC. MPC has committed to provide MPLX with minimum quarterly throughput
volumes on crude oil and refined products and other fees for storage capacity; operating and management
fees; as well as reimbursements for certain direct and indirect costs. MPC has also committed to provide a
fixed fee for 100 percent of available capacity for boats, barges and third-party chartered equipment under
the marine transportation service agreement. In addition, MPLX has obligations to MPC for services
134
provided to MPLX by MPC under omnibus and employee services type agreements as well as other various
agreements as discussed below.
The commercial agreements with MPC include:
• MPLX has fuels distribution agreements with MPC under which MPC pays MPLX for marketing and
selling MPC’s products. This can include MPC paying MPLX a tiered monthly fee based on the volume
of products sold or thought margin support under a related product supply agreement. Agreements are
subject to minimum volume commitments and are subject various terms and renewal periods.
• MPLX has various pipeline transportation agreements under which MPC pays MPLX fees for
transporting crude and refined products on MPLX’s pipeline systems. These agreements are subject to
minimum throughput volumes under which MPC will pay MPLX deficiency payments for any period in
which they do not ship the minimum committed volume. These deficiency payments can be applied as
credits to future periods in which MPC ships volumes in excess of the minimum volume, subject to a
limited period of time. These agreements are subject to various terms and renewal periods.
• MPLX has a six-year marine transportation agreement under which MPC pays MPLX fees for providing
marine transportation of crude oil, feedstock and refined petroleum products, and related services.
• MPLX has various trucking transportation services agreements with terms ranging from month-to-month
to 10 years, under which MPC pays MPLX fees for gathering barrels and providing trucking, dispatch,
delivery and data services. Most of these agreements are subject to minimum volume commitments and
have various terms regarding carry-forward of deficiency payments as credits towards excess volumes
shipped in future periods. These agreements are subject to various terms and renewal periods.
• MPLX has numerous storage services agreements governing storage services at various types of facilities
including terminals, pipeline tank farms, caverns and refineries, under which MPC pays MPLX per-barrel
fees for providing storage services. Some of these agreements provide MPC with exclusive access to
storage at certain locations, such as storage located at MPC’s refineries or storage in certain caverns.
Under these agreements, MPC pays MPLX a per-barrel fee for such storage capacity, regardless of
whether MPC fully utilizes the available capacity. Many of the refinery storage agreements also contain
provisions for logistical services to be provided by MPLX, for which MPC pays monthly fees. These
agreements are subject to terms ranging from three to 17 years and are subject to various renewal periods.
• MPLX has a 10-year terminal services agreement governing certain terminals under which MPC pays
MPLX fees for terminal storage for refined petroleum products. Under this agreement MPC pays MPLX
agreed upon fees relating to MPC product deliveries as well as any viscosity surcharges, loading,
handling, transfers or other related charges. This agreement is subject to minimum volume throughput
commitments under which MPC pays a deficiency payment for any period in which they do not meet the
minimum committed volume. The terminal services agreement with MPC includes automatic renewal
terms ranging from one to five years. MPLX also has numerous additional terminal services agreements
governing terminals acquired through the Merger. Under these agreements, MPC pays MPLX agreed
upon fees relating to various terminal activities including throughput, blending, on and offloading and
additives. Many of these agreements contain various minimum commitments for some or all of these
activities. Some of these agreements allow for deficiency payments to be applied as credits to future
periods with excess throughput volumes. These agreements have terms ranging from one to 10 years with
varying renewal terms.
• MPLX has a year to year keep-whole commodity agreement with MPC under which MPC pays us a
processing fee for NGL’s related to keep-whole agreements and delivers shrink gas to the producers on
our behalf. We pay MPC a marketing fee in exchange for assuming the commodity risk. The pricing
135
structure under this agreement provides for a base volume subject to a base rate and incremental volumes
subject to variable rates which are calculated with reference to certain of our costs incurred as processor
of the volumes. The pricing for both the base and incremental volumes are subject to revision each year.
In many cases, agreements are location-based hybrid agreements, containing provisions relating to multiple of
the types of agreements and services described above.
Operating Agreements
MPLX operates various pipelines owned by MPC under operating services agreements. Under these operating
services agreements, MPLX receives an operating fee for operating the assets and is reimbursed for all direct and
indirect costs associated with operating the assets. Most of these agreements are indexed for inflation. These
agreements range from one to five years in length and automatically renew unless terminated by either party.
Co-location Services Agreements
MPLX is party to co-location services agreements with MPC’s refineries, under which MPC provides
management, operational and other services to the subsidiaries of Refining Logistics. Refining Logistics pays
MPC monthly fixed fees and direct reimbursements for such services calculated as set forth in the agreements.
These agreements have initial terms of 50 years.
Ground Lease Agreements
MPLX is party to ground lease agreements with certain of MPC’s refineries under which MPLX is the lessor of
certain sections of property which contain facilities owned by Refining Logistics and are within the premises of
MPC’s refineries. Refining Logistics pays MPC monthly fixed fees under these ground leases. These agreements
have initial terms of 50 years.
Management Services Agreement
MPLX, through its subsidiary, HSM, has a management services agreement with MPC under which it provides
management services to assist MPC in the oversight and management of the marine business. HSM receives a
fixed annual fee for providing the required management services. This fee is adjusted annually on the anniversary
of the contract for inflation and any changes in the scope of the management services provided. This agreement
is set to expire on January 1, 2021 and automatically renews for two additional renewal terms of 5 years each
unless terminated by either party.
Omnibus Agreements
MPLX has omnibus agreements with MPC that address MPLX’s payment of fixed annual fees to MPC for the
provision of executive management services by certain executive officers of the general partner and MPLX’s
reimbursement of MPC for the provision of certain general and administrative services to it. They also provide
for MPC’s indemnification to MPLX for certain matters, including environmental, title and tax matters; as well
as our indemnification of MPC for certain matters under these agreements. Certain environmental
indemnifications related to the Los Angeles Logistics Assets Acquisition are excluded from coverage under
omnibus agreements and are instead covered by a Carson Assets Indemnity Agreement.
Employee Services Agreements
MPLX has various employee services agreements and secondment agreements with MPC under which MPLX
reimburses MPC for employee benefit expenses, along with the provision of operational and management
services in support of both our L&S and G&P segments’ operations.
136
Loan Agreement
MPLX is party to a loan agreement with MPC Investment (the “MPC Loan Agreement”). Under the terms of the
agreement, MPC Investment makes a loan or loans to MPLX on a revolving basis as requested by MPLX and as
agreed to by MPC Investment. On April 27, 2018, MPLX and MPC Investment entered into an amendment to the
MPC Loan Agreement to increase the borrowing capacity under the MPC Loan Agreement from $500 million to
$1 billion. In connection with the Merger, on July 31, 2019, MPLX and MPC Investment entered into a second
amendment to the MPC Loan Agreement to increase the borrowing capacity under the MPC Loan Agreement to
$1.5 billion in aggregate principal amount of all loans outstanding at any one time. The entire unpaid principal
amount of the loan, together with all accrued and unpaid interest and other amounts (if any), shall become due
and payable on 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 July 31, 2024. Borrowings under the MPC Loan Agreement prior to July 31, 2019 bore
interest at LIBOR plus 1.50 percent, while borrowings as of and after July 31, 2019 will bear interest at LIBOR
plus 1.25 percent or such lower rate as would be applicable to such loans under the MPLX Credit Agreement.
Activity on the MPC Loan Agreement was as follows:
(In millions)
Borrowings
Average interest rate of borrowings
Repayments
Outstanding balance at end of period
December 31,
2019
December 31,
2018
$
$
$
8,540
3.441%
7,946
594
$
$
$
3,962
3.473%
4,347
—
Prior to the Merger, ANDX was also party to a loan agreement with MPC (“ANDX-MPC Loan Agreement”).
This facility was entered into on December 21, 2018, with a borrowing capacity of $500 million. In connection
with the Merger, on July 31, 2019, MPLX repaid the entire outstanding balance and terminated the ANDX-MPC
Loan Agreement. There was no activity on the ANDX-MPC Loan Agreement in 2018. Activity on the agreement
during 2019 prior to the Merger was as follows:
(In millions)
Borrowings
Average interest rate of borrowings
Repayments
Outstanding balance at end of period
Related Party Revenue
December 31, 2019
$
$
$
773
4.249%
773
—
Related party sales to MPC consist of crude oil and refined products pipeline and trucking transportation services
based on tariff/contracted rates; storage, terminal and fuels distribution services based on contracted 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.
137
Revenue received from related parties included on the Consolidated Statements of Income was as follows:
(In millions)
Service revenue
MPC
Rental income
MPC
Product sales(1)
MPC
Other
Total Product sales - related parties
Other income
MPC
Other
2019
2018
2017
$
3,455
$
2,404
$
1,082
1,196
846
279
140
2
142
47
67
87
—
87
41
58
99
$
8
—
8
40
52
92
Total Other income - related parties
$
114
$
(1) There were additional product sales to MPC that 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 2019, 2018 and
2017, these sales totaled $1,120 million, $607 million and $254 million, respectively.
Related Party Expenses
MPC provides executive management services and certain general and administrative services to MPLX under
the terms of our omnibus agreements. Omnibus charges included in “Rental cost of sales - related parties”
primarily relate to services that support MPLX’s rental operations and maintenance of assets available for rent.
Omnibus charges included in “Purchases - related parties” primarily relate to services that support MPLX’s
operations and maintenance activities, as well as compensation expenses. Omnibus charges included in “General
and administrative expenses” primarily relate to services that support MPLX’s executive management,
accounting and human resources activities. MPLX also obtains employee services from MPC under employee
services agreements (“ESA charges”). ESA charges for personnel directly involved in or supporting operations
and maintenance activities related to rental services are classified as “Rental cost of sales - related parties.” ESA
charges for personnel directly involved in or supporting operations and maintenance activities related to other
services are classified as “Purchases - related parties.” ESA charges for personnel involved in executive
management, accounting and human resources activities are classified as “General and administrative expenses.”
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.
Expenses incurred from MPC under the omnibus and employee services agreements as well as other purchases
from MPC included on the Consolidated Statements of Income are as follows:
(In millions)
Rental cost of sales - related parties
Purchases - related parties
MPC
Other
General and administrative expenses
Total
2019
2018
2017
165
$
31
$
2
1,210
21
243
1,639
919
6
199
$
1,155
$
455
—
138
595
$
$
Some charges incurred under the omnibus and ESA 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 2019, 2018 and 2017, these charges totaled $169 million, $152 million and
$42 million, respectively.
138
Related Party Assets and Liabilities
(In millions)
Current assets - related parties
Receivables - MPC
Receivables - Other
Prepaid - MPC
Lease Receivables - MPC
Total
Noncurrent assets - related parties
Long-term receivables - MPC
Right of use assets - MPC
Long-term lease receivables - MPC
Unguaranteed residual asset - MPC
Total
Current liabilities - related parties
Payables - MPC
Payables - Other
Operating lease liabilities - MPC
Deferred revenue - Minimum volume deficiencies - MPC
Deferred revenue - Project reimbursements - MPC
Deferred revenue - Project reimbursements - Other
Total
Long-term liabilities - related parties
Long-term operating lease liabilities - MPC
Long-term deferred revenue - Project reimbursements - MPC
Long-term deferred revenue - Project reimbursements - Other
Total
December 31,
2019
2018
$
$
621
22
9
4
656
21
232
43
7
303
911
37
1
42
16
1
1,008
230
53
7
290
$
$
542
9
5
—
556
24
—
—
—
24
360
76
—
57
9
—
502
—
46
—
46
From time to time, MPLX may also sell to or purchase from related parties assets and inventory at the lesser of
average unit cost or net realizable value. Sales to related parties during the years ended December 31, 2019 and
2018 were $10 million and $6 million, respectively. Purchases from related parties during the years ended
December 31, 2019 and 2018 were approximately $5 million and $8 million, respectively.
7. Net Income/(Loss) Per Limited Partner Unit
Net income/(loss) per unit applicable to common limited partner units is computed by dividing net income/(loss)
attributable to MPLX LP less income/(loss) allocated to participating securities by the weighted average number
of common units outstanding. Additional MPLX common units and MPLX Series B preferred units were issued
on July 30, 2019 as a result of the merger with ANDX as discussed in Note 4. Distributions declared on these
newly issued common and Series B preferred units are a reduction to income available to MPLX common unit
holders due to their participation in distributions of income.
139
Classes of participating securities for 2019, 2018 and 2017 include:
Common Units
Equity-based compensation awards
Series A preferred units
Series B preferred units
General partner units and IDRs
2019
✓
✓
✓
✓
2018
✓
✓
✓
2017
✓
✓
✓
✓
The HST, WHC and MPLXT acquisitions and the Merger were transfers between entities under common control
as discussed in Note 4. 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.
In 2019 and 2018, MPLX had dilutive potential common units consisting of certain equity-based compensation
awards. In 2017, MPLX had dilutive potential common units consisting of certain equity-based compensation
awards and Class B units. Potential common units omitted from the diluted earnings per unit calculation for the
years ended December 31, 2019, 2018 and 2017 were less than 1 million.
(In millions)
2019
2018
2017
Net income attributable to MPLX LP
$
Less: Distributions declared on Series A preferred units(1)
Distributions declared on Series B preferred units(1)
General partner’s distributions declared (includes
IDRs)(1)(2)
Limited partners’ distributions declared on MPLX
common units (including common units of general
partner)(1)
$
$
1,033
81
42
—
1,818
75
—
—
2,635
1,985
794
65
—
328
895
Undistributed net loss attributable to MPLX LP
$
(1,725)
$
(242)
$
(494)
(1) See Note 8 for distribution information.
(2) Distributions declared on January 25, 2018 on general partner common units issued on February 1, 2018 in exchange for
the economic general partner interest, including IDRs, are shown as general partner distributions declared.
140
(In millions, except per unit data)
Basic and diluted net income attributable to MPLX LP per
unit:
Net income attributable to MPLX LP:
Distributions declared
Undistributed net loss attributable to MPLX LP
Net income attributable to MPLX LP(1)
Weighted average units outstanding:
Basic(2)
Diluted(2)
Net income attributable to MPLX LP per limited partner
unit:
Basic
Diluted
2019
Limited
Partners’
Common
Units
Series A
Preferred
Units
Series B
Preferred
Units
Total
$
$
81 $
—
81 $
42
—
42
$
$
2,758
(1,725)
1,033
906
907
$
$
$
$
2,635
(1,725)
910
906
907
1.00
1.00
(In millions, except per unit data)
Basic and diluted net income attributable to MPLX LP per unit:
Net income attributable to MPLX LP:
Distributions declared
Undistributed net loss attributable to MPLX LP
Net income attributable to MPLX LP(1)
Weighted average units outstanding:
Basic
Diluted
Net income attributable to MPLX LP per limited partner unit:
Basic
Diluted
Limited Partners’
Common Units
2018
Series A
Preferred
Units
Total
$
$
$
$
1,985
(242)
1,743
$
$
75 $
—
2,060
(242)
75 $
1,818
761
761
761
761
2.29
2.29
141
(In millions, except per unit data)
Basic and diluted net income attributable to MPLX LP
per unit:
Net income attributable to MPLX LP:
Distribution declared (including IDRs)
Undistributed net loss attributable to MPLX LP
Net income attributable to MPLX LP(1)
Weighted average units outstanding:
Basic
Diluted
Net income attributable to MPLX LP per limited partner
unit:
Basic
Diluted
2017
General
Partner
Limited Partners’
Common Units
Series A
Preferred
Units
Total
$
$
328
(10)
318
$
$
895
(484)
411
$
$
65
—
65
$
$
1,288
(494)
794
8
8
$
$
385
388
1.07
1.06
393
396
(1) Allocation of net income/(loss) attributable to MPLX LP assumes all earnings for the period had been distributed based
on the distribution priorities applicable to the period.
(2) The Series B preferred units and the MPLX common units issued in connection with the Merger were not outstanding
during the entire year. See Notes 4 and 8 for additional information about the treatment of these units.
8. Equity
Units Outstanding – MPLX had 1,058,355,471 common units outstanding as of December 31, 2019. Of that
number, 665,997,540 were owned by MPC, which also owns the non-economic GP interest as described below.
MPLX had 600,000 Series B preferred units outstanding as of December 31, 2019. The sections below describe
activities and events which impacted our unit balances throughout the year.
Merger - In connection with the Merger and as discussed in Note 4, each common unit held by ANDX’s public
unitholders was converted into the right to receive 1.135 MPLX common units while ANDX common units held
by certain affiliates of MPC were converted into the right to receive 1.0328 MPLX common units. This resulted
in the issuance of MPLX common units of approximately 102 million units to public unitholders and
approximately 161 million units to MPC in connection with MPLX’s acquisition of ANDX on July 30, 2019.
Series A Redeemable Preferred Unit Conversions - During 2019, certain holders of Series A preferred units
exercised their rights to convert their Series A preferred units into approximately 1.2 million common units as
discussed in Note 9.
GP/IDR Exchange – On February 1, 2018, MPC cancelled its IDRs and converted its economic GP Interest in
MPLX LP to a non-economic general partner interest in exchange for 275 million newly issued MPLX LP
common units. These units had a fair value of $10.4 billion as of the transaction date as recorded on the
Consolidated Statements of Equity. As a result of this transaction, the general partner units and IDRs were
eliminated, are no longer outstanding, and no longer participate in distributions of cash from MPLX. MPC
continues to own the non-economic GP Interest in MPLX LP. See Note 7 for more information on the net income
per unit calculation.
Class B Conversions - On July 1, 2016 and July 1, 2017, each Class B unit of MPLX LP was converted, in
two equal installments, into 1.09 MPLX LP common units and the right to receive $6.20 in cash. Upon the
conversion of each tranche of the Class B units, the right of the unitholder, M&R MWE Liberty LLC and
certain of its affiliates (“M&R”), to vote as a common unitholder of MPLX was limited to a maximum of five
percent of MPLX’s outstanding common units. Additionally, M&R was given the right with respect to such
converted units to participate in MPLX’s underwritten offerings of our common units including continuous
equity or similar programs in an amount up to 20 percent of the total number of common units offered by
142
MPLX. M&R may freely transfer such converted units, and M&R has the right to demand that MPLX conduct
up to three underwritten offerings beginning in 2017, but restricted to no more than one offering in any
twelve-month period. Following the July 1, 2017 conversion, all MPLX Class B units were eliminated, are no
longer outstanding and no longer participate in distributions of cash from MPLX.
ATM Program – On March 13, 2018, MPLX entered into a Third Amended and Restated Distribution
Agreement, providing for the at-the-market issuances of common units having an aggregate offering price of up
to approximately $1.7 billion, in amounts, at prices and on terms determined by market conditions and other
factors at the time of the offerings (such continuous offering program, or at-the-market program is referred to as
the “ATM Program”). During the years ended December 31, 2019 and 2018, MPLX issued no common units
under the ATM Program. During the year ended December 31, 2017, MPLX issued an aggregate of 13,846,998
common units under the ATM Program generating net proceeds of approximately $473 million. MPLX used the
net proceeds from sales under the ATM Program for general business purposes, including repayment or
refinancing of debt, and funding for acquisitions, working capital requirements and capital expenditures.
The table below summarizes the changes in the number of units outstanding for the years ended December 31,
2017, 2018, and 2019:
(In units)
Common
Class B
General Partner(1)
Total
Balance at December 31, 2016
Unit-based compensation awards
Issuance of units under the ATM
Program
Contribution of HST/WHC/MPLXT
(See Note 4)
Contribution of the Joint-Interest
Acquisition (See Note 4)
Class B Conversion
Balance at December 31, 2017
Unit-based compensation awards
Contribution of Refining Logistics
and Fuels Distribution (See Note 4)
Conversion of GP economic interests
Balance at December 31, 2018
Unit-based compensation awards
Issuance of units in connection with
the Merger
Conversion of Series A preferred
units
357,193,288
268,167
3,990,878
—
7,371,105
5,472
368,555,271
273,639
13,846,998
12,960,376
18,511,134
4,350,057
407,130,020
348,387
111,611,111
275,000,000
794,089,518
288,031
262,829,592
1,148,330
—
—
282,591
14,129,589
264,497
13,224,873
—
(3,990,878)
—
—
—
—
—
—
—
—
—
377,778
7,330
8,308,773
140
2,277,778
(10,586,691)
—
—
—
—
18,888,912
366,509
415,438,793
348,527
113,888,889
264,413,309
794,089,518
288,031
262,829,592
1,148,330
— 1,058,355,471
Balance at December 31, 2019
1,058,355,471
(1) Changes to the number of general partner units outstanding, other than changes due to contributions made to MPC for the
acquisitions of HSM, HST, WHC, MPLXT, the Joint-Interest Acquisition and Refining Logistics and Fuels Distribution,
are the result of cash contributions made by the general partner in order to maintain its two percent GP Interest.
Series B Preferred Units - Prior to the Merger, ANDX issued 600,000 units of 6.875 percent
Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner
interests of ANDX at a price to the public of $1,000 per unit. Upon completion of the Merger, the ANDX
preferred units converted to preferred units of MPLX representing substantially equivalent limited
partnership interests in MPLX (the “Series B preferred units”). The Series B preferred units are pari passu
with the Series A preferred units with respect to distribution rights and rights upon liquidation. Distributions
on the Series B preferred units are payable semi-annually in arrears on the 15th day, or the first business day
thereafter, of February and August of each year up to and including February 15, 2023. After February 15,
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2023, the holders of Series B preferred units are entitled to receive cumulative, quarterly distributions payable in
arrears on the 15th day of February, May, August and November of each year, or the first business day thereafter,
based on a floating annual rate equal to the three-month LIBOR plus 4.652 percent.
The changes in the Series B preferred unit balance from the Merger through December 31, 2019 are summarized
below and are included in the Consolidated Balance Sheets and Consolidated Statements of Equity within
“Equity of Predecessor” for the period prior to the Merger and within “Series B preferred units” for the period
following the Merger. The Series B preferred units are recorded at fair value as of July 30, 2019.
(In millions)
Beginning Balance at the Merger date
Net income allocated
Distributions received by Series B preferred unitholders
Balance at December 31, 2019
Series B
Preferred Units
$
$
615
17
(21)
611
TexNew Mex Units - Prior to the Merger, MPC held 80,000 Andeavor Logistics TexNew Mex units,
representing all outstanding units. At the time of the Merger, each Andeavor Logistics TexNew Mex unit was
automatically converted into TexNew Mex units of MPLX with substantially the same rights and obligations as
the Andeavor Logistics TexNew Mex units. The TexNew Mex units represent the right to receive quarterly
distribution payments in an amount calculated using the distributable cash flow generated by a particular portion
of the TexNew Mex pipeline system, in excess of a base amount and adjusted for previously agreed upon
stipulations and contingencies. No distributions were payable to TexNew Mex unitholders for distributable cash
flow generated during the post-Merger period in 2018. In 2019, distributions of less than $1 million were earned
by the TexNew Mex units, which were declared in January of 2020 and paid in February 2020.
Issuance of Additional Securities – The Partnership Agreement authorizes MPLX to issue an unlimited number
of additional securities for the consideration and on the terms and conditions determined by the general partner
without the approval of the unitholders.
Net Income Allocation – In preparing the Consolidated Statements of Equity, net income attributable to MPLX
LP is allocated to Series A and Series B preferred unitholders first and subsequently allocated to the limited
partner unitholders in accordance with their respective ownership percentages. Prior to 2018, when distributions
related to the IDRs were made, earnings equal to the amount of those distributions were 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, for income statement periods occurring prior to the exchange of the GP economic
interests:
(In millions)
Net income attributable to MPLX LP
Less: Preferred unit distributions
General partner’s IDRs and other
Net income attributable to MPLX LP available to general and limited partners
General partner’s two percent GP Interest in net income attributable to MPLX LP
General partner’s IDRs and other
General partner’s GP Interest in net income attributable to MPLX LP
2017
794
65
310
419
8
310
318
$
$
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 and preferred unitholders will
receive. In accordance with the Partnership Agreement, on January 23, 2020, MPLX declared a quarterly
cash distribution, based on the results of the fourth quarter of 2019, totaling $715 million, or $0.6875 per
common unit. This rate was also received by Series A preferred unitholders. These distributions were paid
144
on February 14, 2020 to unitholders of record on February 4, 2020. Distributions for the fourth quarter of 2018
were $0.6475 per common unit while distributions for the twelve months ended December 31, 2019 and 2018
were $2.6900 and $2.5300 per common unit, respectively. The $715 million of common unit distributions is net
of $12.5 million in quarterly distributions waived by MPC. This waiver was instituted in 2017 under the terms of
ANDX’s historical partnership agreement with Andeavor. The waiver is no longer applicable after 2019 based on
the original term in the waiver agreement.
Additionally, as a result of the Merger, 600,000 ANDX preferred units were converted into 600,000 Series B
preferred units of MPLX. Series B preferred unitholders are entitled to receive, when and if declared by the
board, a fixed distribution of $68.75 per unit, per annum, payable semi-annually in arrears on February 15 and
August 15, or the first business day thereafter, up to and including February 15, 2023. After February 15, 2023,
the holders of Series B preferred units are entitled to receive cumulative, quarterly distributions payable in
arrears on the 15th day of February, May, August and November of each year, or the first business day thereafter,
based on a floating annual rate equal to the three-month LIBOR plus 4.652 percent. MPLX made a cash
distribution to holders of the Series B preferred unitholders on February 15, 2020 for approximately $21 million.
The allocation of total quarterly cash distributions to general, limited, and preferred unitholders is as follows for
the years ended December 31, 2019, 2018 and 2017. 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.
(In millions)
General partner’s distributions:
General partner’s distributions on general partner units
General partner’s distributions on IDRs(1)
Total distribution on general partner units and IDRs
Limited partners’ distributions:
Common unitholders, includes common units of general
partner
Series A preferred unit distributions
Series B preferred unit distribution
Total cash distributions declared
$
$
2019
2018
2017
— $
—
—
— $
—
—
2,635
81
42
2,758
$
1,985
75
—
2,060
$
1,288
25
303
328
895
65
—
(1)
Includes distributions of fourth quarter 2017 income declared on general partner common units issued February 1, 2018
in exchange for the economic general partner interest.
The distribution on common units for the year ended December 31, 2019 includes the impact of the issuance of
approximately 102 million units issued to public unitholders and approximately 161 million units issued to MPC
in connection with the Merger. Due to the timing of the closing, distributions presented in the table above include
second quarter distributions on MPLX common units issued to former ANDX unitholders in connection with the
Merger. Due to the waiver mentioned above, the distributions on common units exclude $12.5 million of waived
distributions for the three months ended December 31, 2019 and $37.5 million of waived distributions for the
year ended December 31, 2019. Also included in the table above is $21 million of distributions earned by the
Series B preferred units for 2019 as well as $21 million of distributions earned on the Series B units prior to the
Merger and declared and paid by MPLX during the third quarter.
9. Series A Preferred Units
Private Placement of Preferred Units – On May 13, 2016, MPLX completed the private placement of
approximately 30.8 million 6.5 percent Series A Convertible preferred units for a cash purchase price of $32.50
per unit. The aggregate net proceeds of approximately $984 million from the sale of the Series A preferred units
were used for capital expenditures, repayment of debt and general business purposes.
Preferred Unit Distribution Rights - The Series A preferred units rank senior to all common units and pari
passu with all Series B preferred units with respect to distributions and rights upon liquidation. The holders of
the Series A preferred units received cumulative quarterly distributions equal to $0.528125 per unit for each
145
quarter prior to the second quarter of 2018. Beginning with the second quarter of 2018, the holders of the
Series A preferred units are entitled to receive, when and if declared by the board, a quarterly distribution
equal to the greater of $0.528125 per unit or the amount of distributions they would have received on an as
converted basis. On January 23, 2020, MPLX declared a quarterly cash distribution of $0.6875 per common
unit for the fourth quarter of 2019. Holders of the Series A preferred units will receive the common unit rate in
lieu of the lower $0.528125 base amount.
The holders may convert their Series A preferred units into common units at any time, in full or in part, subject to
minimum conversion amounts and conditions. After the fourth anniversary of the issuance date, MPLX may
convert the Series A 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 common units is greater than $48.75
for the 20-day trading period immediately preceding the conversion notice date. The conversion rate for the
Series A preferred units shall be the quotient of (a) the sum of (i) $32.50, plus (ii) any unpaid cash distributions
on the applicable preferred unit, divided by (b) $32.50, subject to adjustment for unit distributions, unit splits and
similar transactions. The holders of the Series A preferred units are entitled to vote on an as-converted basis with
the common unitholders and have certain other class voting rights with respect to any amendment to the MPLX
partnership agreement that would adversely affect any rights, preferences or privileges of the preferred units. In
addition, upon certain events involving a change of control, the holders of preferred units may elect, among other
potential elections, to convert their Series A preferred units to common units at the then applicable change of
control conversion rate.
On September 20, 2019, certain holders exercised their right to convert a total of 1.2 million Series A preferred
units into common units. As a result of the transaction, approximately 29.6 million Series A preferred units
remain outstanding as of December 31, 2019.
The changes in the redeemable preferred balance for 2019 and 2018 are summarized below:
(In millions)
Balance at beginning of period
Net income allocated
Distributions received by preferred unitholders
Conversion of preferred units to common units
Balance at end of period
2019
2018
$
$
$
1,004
81
(81)
(36)
968
$
1,000
75
(71)
—
1,004
The Series A preferred units are considered redeemable securities under GAAP due to the existence of
redemption provisions upon a deemed liquidation event, which is outside MPLX’s control. Therefore, they are
presented as temporary equity in the mezzanine section of the Consolidated Balance Sheets. The Series A
preferred units have been recorded at their issuance date fair value, net of issuance costs. Income allocations
increase the carrying value and declared distributions decrease the carrying value of the Series A preferred units.
As the Series A preferred units are not currently redeemable and not probable of becoming redeemable,
adjustment to the initial carrying amount is not necessary and would only be required if it becomes probable that
the Series A preferred units would become redeemable.
10. Segment Information
MPLX’s chief operating decision maker is the chief executive officer (“CEO”) of its general partner. The CEO
reviews MPLX’s discrete financial information, makes operating decisions, assesses financial performance and
allocates resources on a type of service basis. MPLX has two reportable segments: L&S and G&P. Each of these
segments is organized and managed based upon the nature of the products and services it offers.
• L&S – transports, stores, distributes and markets crude oil, asphalt, refined petroleum products and water.
Also includes an inland marine business, terminals, rail facilities, storage caverns and refining logistics.
• G&P – gathers, processes and transports natural gas; gathers, transports, fractionates, stores and markets
NGLs.
146
During the second quarter of 2018, our CEO began to evaluate the performance of our segments using Segment
Adjusted EBITDA. We have modified our presentation of segment performance metrics to be consistent with this
change, including prior periods presented for consistent and comparable presentation. Amounts included in net
income and excluded from Segment Adjusted EBITDA include: (i) depreciation and amortization; (ii) provision/
(benefit) for income taxes; (iii) amortization of deferred financing costs; (iv) extinguishment of debt;
(v) non-cash equity-based compensation; (vi) impairment expense; (vii) net interest and other financial costs;
(viii) income/(loss) from equity method investments; (ix) distributions and adjustments related to equity method
investments; (x) unrealized derivative gains/(losses); (xi) acquisition costs; (xii) noncontrolling interests; and
(xiii) other adjustments as deemed necessary. 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 tied to the operational performance
of the segment.
The tables below present information about revenues and other income, capital expenditures and investments in
unconsolidated affiliates for the years ended December 31, 2019, 2018 and 2017 as well as total assets for our
reportable segments as of December 31, 2019 and 2018:
(In millions)
L&S
Service revenue
Rental income
Product related revenue
Income from equity method investments
Other income
Total segment revenues and other income(1)
Segment Adjusted EBITDA(2)
Capital expenditures
Investments in unconsolidated affiliates
G&P
Service revenue
Rental income
Product related revenue
Income from equity method investments
Other income
Total segment revenues and other income(1)
Segment Adjusted EBITDA(2)
Capital expenditures
Investments in unconsolidated affiliates
2019
2018
2017
$
$
3,765
1,235
91
200
61
5,352
2,748
1,060
289
2,188
349
997
90
65
3,689
1,586
1,203
424
$
$
2,575
856
23
171
47
3,672
2,057
708
3
1,685
342
1,171
76
59
3,333
1,418
1,545
338
$
$
1,200
279
—
36
47
1,562
775
512
533
1,038
277
897
42
51
2,305
1,229
972
228
(1) Within the total segment revenues and other income amounts presented above, third party revenues for the L&S segment
were $660 million, $371 million and $160 million for 2019, 2018 and 2017, respectively. Third party revenues for the
G&P segment were $3,474 million, $3,198 million and $2,246 million for 2019, 2018 and 2017, respectively.
(2) See below for the reconciliation from Segment Adjusted EBITDA to “Net income.”
(In millions)
Segment Assets
Cash and cash equivalents
L&S
G&P
Total assets
147
December 31,
2019
2018
$
$
$
15
20,810
19,605
40,430
$
77
19,963
19,285
39,325
The table below provides a reconciliation between “Net income” and Segment Adjusted EBITDA.
(In millions)
Reconciliation to Net income:
L&S Segment Adjusted EBITDA
G&P Segment Adjusted EBITDA
Total reportable segments
Depreciation and amortization(1)
(Provision)/benefit for income taxes
Amortization of deferred financing costs
Loss on extinguishment of debt
Non-cash equity-based compensation
Impairment expense
Net interest and other financial costs
Income from equity method investments
Distributions/adjustments related to equity method investments
Unrealized derivative gains/(losses)(2)
Acquisition costs
Other
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to Predecessor(3)
2019
2018
2017
$
$
2,748
1,586
4,334
(1,254)
—
(42)
—
(22)
(1,197)
(873)
290
(562)
1
(14)
(1)
32
770
$
2,057
1,418
3,475
(867)
(8)
(55)
(46)
(23)
—
(613)
247
(458)
5
(4)
—
18
335
775
1,229
2,004
(683)
(1)
(53)
—
(15)
—
(301)
78
(231)
(6)
(11)
—
8
47
836
Net income
$
1,462
$
2,006
$
(1) Depreciation and amortization attributable to L&S was $503 million, $308 million and $163 million for the years ended
2019, 2018 and 2017, respectively. Depreciation and amortization attributable to G&P was $751 million, $559 million
and $520 million for 2019, 2018 and 2017, respectively.
(2) MPLX 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.
(3) The Adjusted EBITDA adjustments related to Predecessor are excluded from Adjusted EBITDA attributable to MPLX
LP prior to the acquisition date.
11. Major Customers and Concentration of Credit Risk
The table below shows, by segment, the percentage of operating revenues as well as total revenues and other
income with MPC which is our most significant customer and our largest concentration of credit risk.
Operating revenues(2)
L&S
G&P
Total
Total revenues and other income
L&S
G&P
Total
2019(1)
2018(1)
2017(1)
91%
4%
56%
88%
4%
54%
94%
3%
50%
90%
2%
48%
92%
0%
37%
90%
0%
36%
(1) The percent calculations exclude revenues attributable to volumes shipped by MPC under joint tariffs with third parties,
which are treated as third-party revenue for accounting purposes.
(2) Operating revenues consist of service revenue, service revenue - product related, rental income and product sales.
148
MPLX has a concentration of trade receivables due from customers in the same industry: MPC, integrated oil
companies, independent refining companies and other pipeline companies. These concentrations of customers may
impact MPLX’s overall exposure to credit risk as they may be similarly affected by changes in economic, regulatory
and other factors. MPLX manages its exposure to credit risk through credit analysis, credit limit approvals and
monitoring procedures; and for certain transactions, it may request letters of credit, prepayments or guarantees.
12. Inventories
Inventories consist of the following:
(In millions)
NGLs
Line fill
Spare parts, materials and supplies
Total inventories
13. Property, Plant and Equipment
December 31,
2019
2018
$
$
$
5
10
95
110
$
9
9
80
98
Property, plant and equipment with associated accumulated depreciation is shown below:
(In millions)
Natural gas gathering and NGL transportation pipelines and
facilities
Processing, fractionation and storage facilities
Pipelines and related assets
Barges and towing vessels
Terminals and related assets
Refinery related assets
Land, building, office equipment and other
Construction-in-progress
Total
Less accumulated depreciation
Estimated
Useful Lives
December 31,
2019
2018
$
5 - 40 years
5 - 46 years
2 - 51 years
15 - 20 years
4 - 45 years
13 - 38 years
2 - 45 years
$
7,037
6,410
5,117
739
2,222
1,383
2,554
1,405
26,867
4,722
6,349
6,045
5,111
621
2,757
1,447
1,562
1,321
25,213
3,688
Property, plant and equipment, net
$
22,145
$
21,525
14. Goodwill and Intangibles
Goodwill
MPLX annually evaluates goodwill for impairment as of November 30, as well as whenever events or changes in
circumstances indicate it is more likely than not that the fair value of a reporting unit with goodwill is less than its
carrying amount. As a result of the Merger and subsequent changes to our internal organization structure, the
number of reporting units was reduced from 12 to 6 in conjunction with our annual impairment test, however, this
change in structure did not have an impact on our operating segments. Our reporting units are one level below our
operating segments and are determined based on the way in which segment management operates and reviews each
operating segment. As a result of our change in reporting units, we performed our goodwill impairment assessment
prior to the change in reporting units in addition to performing an impairment assessment immediately following the
change in our reporting units. Significant assumptions used to estimate the reporting units’ fair value include the
discount rate as well as estimates of future cash flows, which are impacted primarily by producer customers’
development plans, which impact future volumes and capital requirements. After performing our evaluations related
to the impairment of goodwill, we recorded an impairment of $1,156 million prior to our change in reporting units
and an additional impairment of $41 million subsequent to our change in reporting units, both within the G&P
149
operating segment. The remainder of the reporting units fair values were in excess of their carrying values. The
impairment was primarily driven by updated guidance related to the slowing of drilling activity which has reduced
production growth forecasts from our producer customers. This resulted in goodwill totaling approximately
$9.5 billion as of December 31, 2019, with all but one of our six reporting units having goodwill.
The fair value of the reporting units for the interim goodwill impairment analysis described above was
determined based on applying both a discounted cash flow or income approach as well as a market approach. The
discounted cash flow fair value estimate is based on known or knowable information at the measurement date.
The significant assumptions that were used to develop the estimates of the fair values under the discounted cash
flow method included management’s best estimates of the expected future results and discount rates, which range
from 9.0 percent to 10.0 percent. Fair value determinations require considerable judgment and are sensitive to
changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and
assumptions made for purposes of the interim goodwill impairment test will prove to be an accurate prediction of
the future. The fair value measurements for the individual reporting units’ overall fair values, and the fair values
of the goodwill assigned thereto, represent Level 3 measurements.
The changes in carrying amount of goodwill were as follows for the periods presented:
(In millions)
Gross goodwill as of December 31, 2017
Accumulated impairment losses
Balance as of December 31, 2017
Acquisitions(1)
Balance as of December 31, 2018
Impairment losses
Acquisitions(1)
Balance as of December 31, 2019
Gross goodwill as of December 31, 2019
Accumulated impairment losses
Balance as of December 31, 2019
L&S
G&P
Total
$
$
162
—
162
7,072
7,234
—
488
7,722
7,722
—
7,722
$
$
2,213
(130)
2,083
699
2,782
(1,197)
229
1,814
3,141
(1,327)
$
1,814
$
2,375
(130)
2,245
7,771
10,016
(1,197)
717
9,536
10,863
(1,327)
9,536
(1) Acquisitions in 2018 are inclusive of the Mt. Airy Terminal acquisition as well as the Merger while acquisitions in 2019
are inclusive of measurement period adjustments related to the previously mentioned transactions.
Intangible Assets
MPLX’s intangible assets are comprised of customer contracts and relationships. The weighted average
amortization period for intangible assets acquired during 2019 was approximately 9 years. Gross intangible
assets with accumulated amortization as of December 31, 2019 and 2018 is shown below:
(In millions)
Useful Life
Gross
December 31, 2019
Accumulated
Amortization(1)
Net
Gross
December 31, 2018
Accumulated
Amortization(1)
L&S
G&P
6 - 8 years
6 - 25 years
$
$
283 $
1,288
1,571 $
(45) $
(256)
(301) $
238
1,032
1,270
$
$
249
1,253
1,502
$
$
(14) $
(129)
(143) $
Net
235
1,124
1,359
(1) Amortization expense attributable to the G&P segment for the years ended December 31, 2019 and 2018 was
$127 million and $49 million, respectively. Amortization expense attributable to the L&S segment for the year ended
December 31, 2019 and 2018 was $31 million and $14 million, respectively.
150
Estimated future amortization expense related to the intangible assets at December 31, 2019 is as follows:
(In millions)
2020
2021
2022
2023
2024
Thereafter
Total
15. Fair Value Measurements
Fair Values – Recurring
$
155
155
155
155
150
500
$
1,270
Fair value measurements and disclosures relate primarily to MPLX’s derivative positions as discussed in Note
16. The following table presents the financial instruments carried at fair value on a recurring basis as of
December 31, 2019 and 2018 by fair value hierarchy level. MPLX has elected to offset the fair value amounts
recognized for multiple derivative contracts executed with the same counterparty.
(In millions)
Assets
Liabilities
Assets
Liabilities
Significant unobservable inputs (Level 3)
Embedded derivatives in commodity contracts
Total carrying value on Consolidated Balance Sheets
$
$
— $
— $
(60)
(60)
$
$
— $
— $
(61)
(61)
December 31,
2019
2018
Level 3 instruments include all NGL transactions and embedded derivatives in commodity contracts. The
embedded derivative liability relates to a natural 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 $0.43 to
$1.23 and (2) the probability of renewal of 94 percent for the first five-year term and 83 percent for the second
five-year term of the gas purchase commitment and related keep-whole processing agreement. Increases or
decreases in the fractionation spread result in an increase or decrease in the fair value of the embedded derivative
liability, respectively. An increase in the probability of renewal would result in an increase in the fair value of the
related embedded derivative liability. Beyond the embedded derivative discussed above, we had no outstanding
commodity contracts as of December 31, 2019 or December 31, 2018.
151
Changes in Level 3 Fair Value Measurements
The following table is a reconciliation of the net beginning and ending balances recorded for net assets and
liabilities classified as Level 3 in the fair value hierarchy.
(In millions)
2019
2018
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
Total gains/(losses) (realized and unrealized) included
in earnings(1)
Settlements
$
Fair value at end of period
— $
(61) $
(2) $
—
—
—
(5)
6
(60)
6
(4)
—
The amount of total losses for the period included in
earnings attributable to the change in unrealized gains
or losses relating to liabilities still held at end of
period
(1) Gains and losses on commodity derivatives classified as Level 3 are recorded in “Product sales” on the
— $
— $
(5) $
$
(64)
(9)
12
(61)
(8)
Consolidated Statements of Income. Gains and losses on derivatives embedded in commodity contracts are
recorded in “Purchased product costs” and “Cost of revenues” on the Consolidated Statements of Income.
Fair Values – Reported
MPLX’s primary financial instruments are cash and cash equivalents, receivables, receivables from related
parties, lease receivables from related parties, accounts payable, payables to related parties and long-term debt.
MPLX’s fair value assessment incorporates a variety of considerations, including (1) the 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. MPLX 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 16).
The fair value of MPLX’s long-term debt is estimated based on recent market non-binding indicative quotes. The
fair value of the SMR liability is estimated using a discounted cash flow approach based on the contractual cash
flows and MPLX’s unsecured borrowing rate. The long-term debt and SMR liability fair values are considered
Level 3 measurements. The following table summarizes the fair value and carrying value of the long-term debt,
excluding finance leases, and SMR liability.
(In millions)
Long-term debt
SMR liability
December 31,
2019
2018
Fair Value
Carrying Value
Fair Value
Carrying Value
$
$
21,054
90
$
$
19,800
80
$
$
18,070
92
$
$
18,511
86
16. Derivative Financial Instruments
As of December 31, 2019, MPLX had no outstanding commodity contracts.
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
2022. The customer has the unilateral option to extend the agreement for two consecutive five-year terms
through December 2032. For accounting purposes, the natural gas purchase commitment and term
extending options have been aggregated into a single compound embedded derivative. The probability of
152
the customer exercising its options is determined based on assumptions about the customer’s potential business
strategy decision points that may 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” on the Consolidated Statements of Income. As of December 31, 2019 and
2018, the estimated fair value of 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 December 31, 2019 and 2018, there
were no derivative assets or liabilities that were offset on the Consolidated Balance Sheets. The impact of
MPLX’s derivative instruments on its Consolidated Balance Sheets is summarized below:
(In millions)
Derivative contracts not designated as hedging instruments and
their balance sheet location
Commodity contracts(1)
Other current assets /Other current liabilities
Other noncurrent assets /Deferred credits and
other liabilities
Total
December 31,
2019
2018
Asset
Liability
Asset
Liability
$
$
— $
—
— $
(5) $
(55)
(60) $
— $
—
— $
(7)
(54)
(61)
(1)
Includes embedded derivatives in commodity contracts as discussed above.
For further information regarding the fair value measurement of derivative instruments, including the effect of
master netting arrangements or collateral, see Note 15. See Note 2 for a discussion of derivatives MPLX may use
and the reasons for them.
The impact of MPLX’s derivative contracts not designated as hedging instruments and the location of gains and
losses recognized on the Consolidated Statements of Income is summarized below:
(In millions)
Product sales
Realized gains/(losses)
Unrealized gains
Total derivative gains/(losses) related to product sales
Purchased product costs
Realized losses
Unrealized gains/(losses)
Total derivative loss related to purchased product costs
Cost of revenues
Realized gains/(losses)
Unrealized gains/(losses)
Total derivative losses related to cost of revenues
2019
2018
2017
$
— $
—
—
4 $
2
6
(6)
1
(5)
—
—
—
(12)
3
(9)
—
—
—
Total derivative losses
$
(5) $
(3) $
(9)
4
(5)
(9)
(10)
(19)
—
—
—
(24)
153
17. Debt
MPLX’s outstanding borrowings at December 31, 2019 and 2018 consisted of the following:
(In millions)
MPLX LP:
Bank revolving credit facility due 2024
Term loan facility due 2021
Floating rate senior notes due September 2021
Floating rate senior notes due September 2022
6.250% senior notes due October 2022
3.500% senior notes due December 2022
3.375% senior notes due March 2023
4.500% senior notes due July 2023
6.375% senior notes due May 2024
4.875% senior notes due December 2024
5.250% senior notes due January 2025
4.000% senior notes due February 2025
4.875% senior notes due June 2025
4.125% senior notes due March 2027
4.250% senior notes due December 2027
4.000% senior notes due March 2028
4.800% senior notes due February 2029
4.500% senior notes due April 2038
5.200% senior notes due March 2047
5.200% senior notes due December 2047
4.700% senior notes due April 2048
5.500% senior notes due February 2049
4.900% senior notes due April 2058
Consolidated subsidiaries:
MarkWest - 4.500% - 4.875% senior notes, due 2023-2025
ANDX - 3.500% - 6.375% senior notes, due 2019-2047
ANDX credit facilities
Financing lease obligations(1)
Total
Unamortized debt issuance costs
Unamortized discount/premium
Amounts due within one year
December 31,
2019
2018
$
— $
1,000
1,000
1,000
266
486
500
989
381
1,149
708
500
1,189
1,250
732
1,250
750
1,750
1,000
487
1,500
1,500
500
23
190
—
19
—
—
—
—
—
—
500
989
—
1,149
—
500
1,189
1,250
—
1,250
750
1,750
1,000
—
1,500
1,500
500
23
3,750
1,245
21
20,119
(106)
(300)
(9)
18,866
(97)
(334)
(513)
Total long-term debt due after one year
$
19,704
$
17,922
(1) See Note 22 for lease information.
The following table shows five years of scheduled debt payments, including payments on finance lease
obligations:
(In millions)
2020
2021
2022
2023
2024
$
$
10
2,002
1,802
1,502
1,601
154
Credit Agreements
MPLX Credit Agreement
Effective July 30, 2019, in connection with the closing of the Merger, MPLX amended and restated its existing
revolving credit facility (the “MPLX Credit Agreement”) to, among other things, increase borrowing capacity to
up to $3.5 billion, extend its term from July 2022 to July 2024, increase the letter of credit issuing capacity to
$300 million and increase the swingline capacity to $150 million. 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.
The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $1 billion,
subject to certain conditions, including the consent of lenders whose commitments would increase. In addition,
the maturity date may be extended, for up to two additional one-year periods, subject to, among other conditions,
the approval of lenders holding the majority of the commitments then outstanding, provided that the
commitments of any non-consenting lenders will terminate on the then-effective maturity date. Borrowings under
the MPLX Credit Agreement bear interest at either the Adjusted LIBOR or the Alternate Base Rate (as defined in
the MPLX Credit Agreement), at our election, plus a specified margin. MPLX is charged various fees and
expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused
portion of the facility and fees with respect to issued and outstanding letters of credit. The applicable margins to
the benchmark interest rates and certain fees fluctuate based on the credit ratings in effect from time to time on
MPLX’s long-term debt.
The MPLX Credit Agreement contains certain representations and warranties, affirmative and restrictive
covenants and events of default that MPLX considers to be usual and customary for an agreement of this type,
including a financial covenant that 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 for up to two fiscal quarters following certain
acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions and dispositions completed
and capital projects undertaken during the relevant period. Other covenants restrict MPLX and/or certain of its
subsidiaries from incurring debt, creating liens on our assets and entering into transactions with affiliates. As of
December 31, 2019, MPLX was in compliance with the covenants contained in the MPLX Credit Agreement.
During the year ended December 31, 2019, MPLX borrowed $5,310 million under the MPLX Credit Agreement,
at a weighted average interest rate of 3.547 percent, and repaid $5,310 million of these borrowings. At
December 31, 2019, MPLX had no outstanding borrowings under the new facility and less than $1 million in
letters of credit outstanding under this facility, resulting in total availability of $3.5 billion, or almost
100.0 percent of the borrowing capacity.
During the year ended December 31, 2018, MPLX borrowed $1,410 million under the MPLX Credit Agreement,
at a weighted average interest rate of 3.464 percent, and repaid $1,915 million of these borrowings. At
December 31, 2018, MPLX had no outstanding borrowings and $3 million in letters of credit outstanding under
this facility, resulting in total availability of $2.2 billion, or 99.9 percent of the borrowing capacity.
ANDX Credit Facilities
Prior to the Merger, ANDX had revolving credit facilities (the “ANDX credit facilities”) totaling $2.1 billion in
borrowing capacity which were set to mature January 29, 2021. The ANDX credit facilities were terminated
upon closing of the Merger and repaid with borrowings under the MPLX revolving credit facility. During the
year ended December 31, 2019, there were borrowings of $864 million under the ANDX credit facilities, at an
average interest rate of 4.129 percent, and repayments of $2.1 billion.
On October 1, 2018, the date on which common control was established, there were outstanding borrowings on
the ANDX credit facilities of $1.1 billion. From October 1, 2018 through December 31, 2018, ANDX borrowed
$760 million at an average interest rate of 4.061 percent and repaid $635 million, resulting in a balance of
$1.2 billion at December 31, 2018.
155
Term Loan Agreement
On September 26, 2019, MPLX entered into a Term Loan Agreement, which provides for a committed term loan
facility for up to an aggregate of $1 billion. Borrowings under the Term Loan Agreement bear interest, at
MPLX’s election, at either (i) the Adjusted LIBO Rate (as defined in the Term Loan Agreement) plus a margin
ranging from 75.0 basis points to 100.0 basis points per annum, depending on MPLX’s credit ratings, or (ii) the
Alternate Base Rate (as defined in the Term Loan Agreement). The proceeds from borrowings under the Term
Loan Agreement are to be used to fund the repayment of MPLX’s existing indebtedness and/or for general
business purposes. Amounts borrowed under the Term Loan Agreement will be due and payable on
September 26, 2021. As of December 31, 2019, MPLX had drawn $1.0 billion on the term loan at an average
interest rate of 2.561 percent.
The Term Loan Agreement contains representations and warranties, affirmative and negative covenants and
events of default that we consider to be customary for an agreement of this type and are substantially similar to
those contained in the MPLX Credit Agreement, including a covenant that requires MPLX’s ratio of
Consolidated Total Debt to Consolidated EBITDA (as both terms are defined in the Term Loan Agreement) for
the four prior fiscal quarters not to exceed 5.0 to 1.0 as of the last day of each fiscal quarter (or during
the six-month period following certain acquisitions, 5.5 to 1.0). Consolidated EBITDA is subject to adjustments
for certain acquisitions completed and capital projects undertaken during the relevant period.
Floating Rate Senior Notes
On September 9, 2019, MPLX issued $2.0 billion aggregate principal amount of floating rate senior notes in a
public offering, consisting of $1.0 billion aggregate principal amount of notes due September 2021 and
$1.0 billion aggregate principal amount of notes due September 2022 (collectively, the “Floating Rate Senior
Notes”). The Floating Rate Senior Notes were offered at a price to the public of 100 percent of par. The Floating
Rate Senior Notes are callable, in whole or in part, at par plus accrued and unpaid interest at any time on or after
September 10, 2020. The net proceeds were used to repay MPLX’s existing indebtedness and/or for general
business purposes. Interest on the Floating Rate Senior Notes is payable quarterly in March, June, September and
December, commencing on December 9, 2019. The interest rate applicable to the floating rate senior notes due
September 2021 is LIBOR plus 0.9 percent per annum. The interest rate applicable to the floating rate senior
notes due September 2022 is LIBOR plus 1.1 percent per annum.
156
Fixed Rate Senior Notes
Interest on each series of MPLX LP, MarkWest and ANDX senior notes is payable semi-annually in arrears,
according to the table below.
Senior Notes
Interest payable semi-annually in arrears
6.250% senior notes due October 2022
3.500% senior notes due December 2022
3.375% senior notes due March 2023
4.500% senior notes due July 2023
6.375% senior notes due May 2024
4.875% senior notes due December 2024
5.250% senior notes due January 2025
4.000% senior notes due February 2025
4.875% senior notes due June 2025
4.125% senior notes due March 2027
4.250% senior notes due December 2027
4.000% senior notes due March 2028
4.800% senior notes due February 2029
4.500% senior notes due April 2038
5.200% senior notes due March 2047
5.200% senior notes due December 2047
4.700% senior notes due April 2048
5.500% senior notes due February 2049
4.900% senior notes due April 2058
April 15th and October 15th
June 1st and December 1st
March 15th and September 15th
January 15th and July 15th
May 1st and November 1st
June 1st and December 1st
January 15th and July 15th
February 15th and August 15th
June 1st and December 1st
March 1st and September 1st
June 1st and December 1st
March 15th and September 15th
February 15th and August 15th
April 15th and October 15th
March 1st and September 1st
June 1st and December 1st
April 15th and October 15th
February 15th and August 15th
April 15th and October 15th
In connection with the Merger, MPLX assumed ANDX’s outstanding senior notes, which had an aggregate
principal amount of $3.75 billion, interest rates ranging from 3.5 percent to 6.375 percent and maturity dates
ranging from 2019 to 2047. On September 23, 2019, $3.06 billion aggregate principal amount of ANDX’s
outstanding senior notes were exchanged for an aggregate principal amount of $3.06 billion unsecured senior
notes (the “Exchange Notes”) issued by MPLX in an exchange offer and consent solicitation undertaken by
MPLX, leaving $690 million aggregate principal of outstanding senior notes issued by ANDX. Of this,
$500 million aggregate principal amount is related to ANDX 5.5 percent senior notes due 2019. The aggregate
principal amount of $500 million and accrued interest of $13.75 million was paid on October 15, 2019 using net
proceeds from the Floating Rate Senior Notes and borrowings under the Term Loan Agreement discussed above
and includes interest through the payoff date.
The Exchange Notes consist of $266 million in aggregate principal amount of 6.25 percent senior notes due
October 2022, $486 million in aggregate principal amount of 3.5 percent senior notes due December 2022,
$381 million in aggregate principal amount of 6.375 percent senior notes due May 2024, $708 million in
aggregate principal amount of 5.25 percent senior notes due January 2025, $732 million in aggregate principal
amount of 4.25 percent senior notes due December 2027 and $487 million in aggregate principal amount of
5.2 percent senior notes due December 2047. Interest on each series of Exchange Notes is payable semi-annually
in arrears according to the table above.
On December 10, 2018, MPLX redeemed all of the $750 million aggregate principal amount of 5.5 percent
senior notes due February 15, 2023, $40 million of which was issued by the MarkWest subsidiary. These notes
were redeemed at 101.833 percent of the aggregate principal amount, which resulted in a payment of $14 million
related to the note premium and the immediate recognition of $46 million of unamortized debt issuance costs.
On November 15, 2018, MPLX issued $2.25 billion aggregate principal amount of senior notes in a public
offering, consisting of $750 million aggregate principal amount of 4.8 percent senior notes due February 2029
157
and $1.5 billion aggregate principal amount of 5.5 percent senior notes due February 2049 (collectively, the
“November 2018 New Senior Notes”). The November 2018 New Senior Notes were offered at a price to the
public of 99.432 percent and 98.031 percent of par, respectively. The net proceeds were used to repay
outstanding borrowings under the MPLX Credit Agreement and the MPC Loan Agreement and to redeem the
$750 million aggregate principal amount of 5.5 percent senior notes due February 2023, as well as for general
business purposes. Interest on each series of notes in the November 2018 New Senior Notes is payable semi-
annually in arrears, commencing on February 15, 2019.
On February 8, 2018, MPLX issued $5.5 billion aggregate principal amount of senior notes in a public offering,
consisting of $500 million aggregate principal amount of 3.375 percent senior notes due March 2023,
$1.25 billion aggregate principal amount of 4.0 percent senior notes due March 2028, $1.75 billion aggregate
principal amount of 4.5 percent senior notes due April 2038, $1.5 billion aggregate principal amount of
4.7 percent senior notes due April 2048, and $500 million aggregate principal amount of 4.9 percent senior notes
due April 2058 (collectively, the “February 2018 New Senior Notes”). The February 2018 New Senior Notes
were offered at a price to the public of 99.931 percent, 99.551 percent, 98.811 percent, 99.348 percent, and
99.289 percent of par, respectively. Also on February 8, 2018, $4.1 billion of the net proceeds from the offering
were used to repay the 364-day term loan facility, which was drawn on February 1, 2018 to fund the cash portion
of the dropdown consideration for Refining Logistics and Fuels Distribution. The remaining net proceeds were
used to repay outstanding borrowings under the MPLX Credit Agreement and the MPC Loan Agreement, as well
as for general business purposes. Interest on each series of notes due in 2023 and 2028 is payable semi-annually
in arrears, commencing on September 15, 2018. Interest on each series of notes due in 2038, 2048 and 2058 is
payable semi-annually in arrears, commencing on October 15, 2018.
SMR Transaction
On September 1, 2009, MarkWest completed the sale of the SMR (the “SMR Transaction”). At that time,
MarkWest had begun constructing the SMR at its Javelina gas processing and fractionation complex in Corpus
Christi, Texas. Under the terms of the agreement, MarkWest received proceeds of $73 million and the purchaser
completed the construction of the SMR. MarkWest and the purchaser also executed a related product supply
agreement under which MPLX will receive the entire product produced by the SMR through 2030 in exchange
for processing fees and the reimbursement of certain other expenses. The processing fee payments began when
the SMR commenced operations in March 2010. MarkWest was deemed to have continuing involvement with
the SMR as a result of certain provisions in the related agreements. Therefore, the transaction is treated as a
financing arrangement under GAAP. MPLX imputes interest on the SMR liability at 6.39 percent annually, its
incremental borrowing rate at the time of the purchase accounting valuation. Each processing fee payment has
multiple elements: reduction of principal of the SMR liability, interest expense associated with the SMR liability
and facility expense related to the operation of the SMR. As part of purchase accounting, the SMR Transaction
has been recorded at fair value. As of December 31, 2019 and 2018, the following amounts related to the SMR
are included in the accompanying Consolidated Balance Sheets:
(In millions)
Assets
Property, plant and equipment, net
Liabilities
Other current liabilities
Deferred credits and other liabilities
December 31,
2019
2018
$
$
46 $
5
75 $
51
5
81
158
18. Revenue
Disaggregation of Revenue
The following table represents a disaggregation of revenue for each reportable segment for the years ended
December 31, 2019 and 2018:
(In millions)
Revenues and other income:
Service revenue
Service revenue - related parties
Service revenue - product related
Product sales(1)
Product sales - related parties
Total revenues from contracts with customers
Non-ASC 606 revenue(2)
Total revenues and other income
(In millions)
Revenues and other income:
Service revenue
Service revenue - related parties
Service revenue - product related
Product sales(1)
Product sales - related parties
Total revenues from contracts with customers
Non-ASC 606 revenue(2)
Total revenues and other income
L&S
2019
G&P
Total
$
$
$
$
$
346
3,419
—
65
26
3,856
$
2,152
36
140
741
116
3,185
L&S
2018
G&P
$
174
2,401
—
12
11
2,598
$
1,682
3
220
870
76
2,851
$
$
$
$
2,498
3,455
140
806
142
7,041
2,000
9,041
Total
1,856
2,404
220
882
87
5,449
1,556
7,005
(1) G&P “Product sales” for the year ended December 31, 2018 was adjusted in the table above by $5 million related to
derivative gains and mark-to-market adjustments. There were no adjustments for the year ended December 31, 2019.
(2) Non-ASC 606 Revenue includes rental income, income from equity method investments, derivative gains and losses,
mark-to-market adjustments, and other income.
Contract Balances
Contract assets typically relate to 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
generally classified as current and included in “Other current assets” on the Consolidated Balance Sheets.
Contract liabilities, which we refer to 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.
“Receivables, net” primarily relate to our commodity sales. Portions of the “Receivables, net” balance are
attributed to the sale of commodity product controlled by MPLX prior to sale while a significant portion of the
159
balance relates to the sale of commodity product on behalf of our producer customers. The sales and related
“Receivables, net” are commingled and excluded from the table below. MPLX remits the net sales price back to
our producer customers upon completion of the sale. Each period end, certain amounts within accounts payable
relate to our payments to producer customers. Such amounts are not deemed material at period end as a result of
when we settle with each producer.
The table below reflects the changes in our contract balances for the years ended December 31, 2019 and 2018:
(In millions)
Contract assets
Deferred revenue
Deferred revenue - related parties
Long-term deferred revenue
Long-term deferred revenue - related parties
(In millions)
Contract assets
Deferred revenue
Deferred revenue - related parties
Long-term deferred revenue
Long-term deferred revenue - related parties
Balance at
December 31,
2018(1)
Additions/
(Deletions)
Revenue
Recognized(2)
Balance at
December 31,
2019
$
$
36 $
13
65
56
52 $
5 $
17
55
34
3 $
(2) $
(7)
(67)
—
— $
39
23
53
90
55
Balance at
January 1, 2018(1)
Additions/
(Deletions)(3)
Revenue
Recognized(2)
Balance at
December 31,
2018
$
$
4 $
5
42
5
43 $
32 $
19
60
51
9 $
— $
(11)
(37)
—
— $
36
13
65
56
52
(1) Balance represents ASC 606 portion of each respective line item.
(2) No significant revenue was recognized related to past performance obligations for the years ended December 31, 2019
and 2018.
Includes opening balances related to the Merger.
(3)
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) at the end of the reporting period.
As of December 31, 2019, the amounts allocated to contract assets and contract liabilities on the Consolidated
Balance Sheets are $220 million and are reflected in the amounts below. This will be recognized as revenue as
the obligations are satisfied, which is expected to occur over the next 24 years. Further, MPLX does not disclose
variable consideration due to volume variability in the table below.
(In millions)
2020
2022
2022
2023
2024 and thereafter
Total revenue on remaining performance obligations(1)(2)(3)
$
$
1,717
1,693
1,640
1,555
5,317
11,922
(1) All fixed consideration from contracts with customers is included in the amounts presented above. Variable consideration
that is constrained or not required to be estimated as it reflects our efforts to perform is excluded.
(2) Arrangements deemed implicit leases are included in “Rental income” and are excluded from this table.
(3) Only minimum volume commitments that are deemed fixed are included in the table above. MPLX has various minimum
volume commitments in processing arrangements that vary based on the actual Btu content of the gas received. These
amounts are deemed variable consideration and are excluded from the table above.
160
We do not disclose information on the future performance obligations for any contract with an original expected
duration of one year or less.
19. Supplemental Cash Flow Information
(In millions)
Cash and cash equivalents
Restricted cash(1)
Cash, cash equivalents and restricted cash
December 31,
2019
2018
$
$
15
—
15
$
$
77
8
85
(1) The restricted cash balance is included within “Other current assets” on the Consolidated Balance Sheets.
(In millions)
2019
2018
2017
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)
Income taxes paid
Cash paid for amounts included in the measurement of lease
liabilities
Payments on operating leases
Interest payment under finance lease obligations
Net cash provided by financing activities included
Principal payments under finance lease obligations
Non-cash investing and financing activities:
Net transfers of property, plant and equipment from materials
and supplies inventories
MPLX terminal lease classification change
ROU assets obtained in exchange for new operating lease
obligations
ROU assets obtained in exchange for new finance lease
obligations
Contribution - fixed assets to joint venture(1)
Contribution - common units issued(2)
$
835 $
1
568 $
1
263
3
85
1
5
2
21
26
—
—
—
2
—
—
—
—
—
6
—
—
4
—
7,722 $
—
—
4,236 $
—
337
1,133
$
(1) Contribution of assets to Sherwood Midstream and Sherwood Midstream Holdings.
(2) For 2017, includes limited and general partner units issued to MPC as consideration in the acquisitions of the joint-
interests, HST, WHC and MPLXT. For 2018, includes limited and general partner units issued to MPC as consideration
in the acquisition of Refining Logistics and Fuels Distribution. For 2019, includes limited partner units issued to MPC
and public unitholders as consideration in the Merger. See Note 4.
At December 31, 2017, “Payables - related parties” per the Consolidated Balance Sheets included an $11 million
payable to MPC for distributions of cash received from Joint-Interest Acquisition entities that did not affect cash.
The Consolidated Statements of Cash Flows exclude changes to the Consolidated Balance Sheets that did not
affect cash. The following is the change of additions to property, plant and equipment related to capital accruals:
(In millions)
2019
2018
2017
Increase/(decrease) in capital accruals
$
(146)
$
135
$
71
161
20. Accumulated Other Comprehensive Loss
MPLX records an accumulated other comprehensive loss on the Consolidated Balance Sheets relating to pension
and other post-retirement benefits provided by LOOP and Explorer to their employees. MPLX is not a sponsor of
these benefit plans. As a transfer between entities under common control, MPLX recorded the Joint-Interest
Acquisition from MPC on the Consolidated Balance Sheets at MPC’s historical basis, which included
accumulated other comprehensive loss. MPLX’s assumption of the accumulated other comprehensive loss
balance had no effect on MPLX’s comprehensive income during the period as the balance was accumulated
while under the ownership of MPC.
The following table shows the changes in “Accumulated other comprehensive loss” by component during the
period December 31, 2017 through December 31, 2019:
(In millions)
Balance at December 31, 2017(1)
Other comprehensive loss - remeasurements(2)
Balance at December 31, 2018(1)
Other comprehensive income - remeasurements(2)
Balance as of December 31, 2019(1)
Pension Benefits
Other Post-
Retirement
Benefits
Total
$
$
(13) $
(1)
(14)
—
(1) $
(1)
(2)
1
(14) $
(1) $
(14)
(2)
(16)
1
(15)
(1) These components of “Accumulated other comprehensive loss” are included in the computation of net periodic benefit
cost by LOOP and Explorer and are therefore included on the Consolidated Statements of Income under the caption
“Income/(loss) from equity method investments.”
(2) Components of other comprehensive loss - remeasurements relate to actuarial gains and losses as well as amortization of
prior service costs. MPLX records an adjustment to “Comprehensive income” in accordance with its ownership interest
in LOOP and Explorer.
21. Equity-Based Compensation
Description of the Plan
Effective March 15, 2018, the MPLX LP 2012 Incentive Compensation Plan (“MPLX 2012 Plan”) was replaced
by the MPLX LP 2018 Incentive Compensation Plan (“MPLX 2018 Plan”). The MPLX 2018 Plan will continue
in effect until February 28, 2028, unless terminated earlier. Subject to customary anti-dilution adjustments, the
MPLX 2018 Plan allows for no more than 16 million common units representing limited partnership interests in
MPLX to be delivered under the plan. The MPLX LP 2012 Plan allowed for no more than 2.75 million MPLX
LP common limited partner units to be delivered.
Consistent with the MPLX 2012 Plan, the MPLX 2018 Plan authorizes the MPLX GP board of directors (the
“Board”) to grant unit options, unit appreciation rights, restricted units and phantom units, distribution equivalent
rights, unit awards, profits interest units, performance units and other unit-based awards to the employees,
officers and directors of the General Partner, MPLX, or any of their affiliates, including MPC. Common units
delivered pursuant to an award granted under the MPLX 2018 Plan may be newly issued common units or
acquired in the open market or from any other person, including an affiliate of MPLX, as determined by the
Board.
Unit-based Awards under the Plan
MPLX expenses all unit-based payments to employees and non-employee directors based on the grant date fair
value of the awards over the requisite service period, adjusted for estimated forfeitures.
Phantom Units – MPLX has granted phantom units under the MPLX 2018 Plan and the MPLX 2012 Plan
to non-employee directors of MPLX LP’s general partner and of MPC. Awards to non-employee directors
are accounted for as non-employee awards. Phantom units granted to non-employee directors vest
immediately at the time of the grant, as they are non-forfeitable, but are not issued until the director’s
departure from the board of directors. Prior to issuance, non-employee directors do not have the right to
162
vote such units and cash distribution equivalents accrue in the form of additional phantom units and will be
issued when the director departs from the board of directors.
MPLX has granted phantom units under the MPLX 2018 Plan and the MPLX 2012 Plan to certain officers and
non-officers of MPLX, MPLX’s general partner and MPC who make significant contributions to our business.
These grants are accounted for as employee awards. In general, these phantom units will vest over a requisite
service period of up to three years. Prior to vesting, these phantom unit recipients will not have the right to vote
such units and cash distributions declared will be accrued and paid upon vesting. The accrued distributions at
December 31, 2019 and 2018 were $6 million and $4 million, respectively.
The fair values of phantom units are based on the fair value of MPLX common units on the grant date.
Performance Units – MPLX has granted performance units under the MPLX 2018 Plan and the MPLX 2012 Plan
to certain officers of the general partner and certain eligible MPC officers who make significant contributions to
our business. Performance units are designed to pay out 75 percent in cash and 25 percent in MPLX common
units. The performance units paying out in cash are accounted for as liability awards and recorded at fair value
with a mark-to-market adjustment made each quarter. The performance units paying out in units are accounted
for as equity awards.
The performance units granted in 2017 are hybrid awards having a three-year performance period 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’s DCF during the last twelve months of the performance period, and a market condition based on
MPLX’s total unitholder return over the entire three-year performance period.
During the first quarter of 2018, a performance award was granted; however, a grant date could not be
established based on the nature of the award terms. Given that a grant date cannot be established, no expense or
units have been recorded. When a grant date is established, the fair value of the award will be recognized over
the remaining service period.
The performance units granted in 2019 are hybrid awards having a three-year performance period of January 1,
2019 through December 31, 2021. 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’s DCF during the performance period and a market condition based on MPLX’s total unitholder return
over the performance period. The market condition was valued using a Monte Carlo valuation, resulting in a
grant date fair value of $0.68 per unit for the 2019 equity-classified performance units. Grant date fair value of
the performance condition is based on potential payouts per unit of up to $2.00 per unit. Compensation cost
associated with the performance condition is based on the grant date fair value of the payout deemed most
probable to occur and is adjusted as the expectation for payout changes.
163
Outstanding Phantom Unit Awards
The following is a summary of phantom unit award activity of MPLX common units in 2019:
Phantom Units
Outstanding at December 31, 2018
Granted
Legacy ANDX phantom units converted to MPLX phantom
units at the Merger
Settled
Forfeited
Outstanding at December 31, 2019
Number
of Units
1,154,335 $
219,488
208,533
(426,451)
(46,337)
1,109,568
Weighted
Average
Fair Value
Aggregate
Intrinsic Value
(In millions)
34.34
32.62
43.64
33.84
33.63
35.97
Vested and expected to vest at December 31, 2019
Non-forfeitable at December 31, 2019(1)
(1) Represents a subset of phantom units held by our non-employee directors and certain of our officers and non-officer
35.98 $
37.32 $
507,471 $
1,104,552
28
13
employees that are generally non-forfeitable and that would be paid out as common units upon the holder’s separation
from service.
The following is a summary of the values related to phantom units:
2019
2018
2017
Phantom Units
Intrinsic Value
of Units Issued
During the
Period (in
millions)
Weighted
Average Grant
Date Fair Value
of Units Granted
During the
Period
$
$
14
18
15
$
$
32.62
33.84
36.26
As of December 31, 2019, unrecognized compensation cost related to phantom unit awards was $9 million,
which is expected to be recognized over a weighted average period of 1.3 years.
Outstanding Performance Unit Awards
The following table presents a summary of the 2019 activity for performance unit awards to be settled in MPLX
common units:
Outstanding at December 31, 2018
Granted
Settled
Forfeited
Outstanding at December 31, 2019
Performance Units
Number of
Units
Weighted
Average
Fair Value
1,941,750 $
987,994
(772,397)
—
2,157,347 $
0.80
0.76
0.63
—
0.84
The number of common units that would be issued upon target vesting, using the closing price of our common
units on December 31, 2019 would be 84,735 common units.
As of December 31, 2019, unrecognized compensation cost related to equity-classified performance unit awards
was $1 million which is expected to be recognized over a weighted average period of 2.0 years.
164
Performance units paying out in MPLX common units have a grant date fair value calculated using a Monte
Carlo valuation model, which requires the input of subjective assumptions. The following table provides a
summary of the weighted average inputs used for these assumptions:
Risk-free interest rate
Look-back period
Expected volatility
Grant date fair value of performance units granted
2019
2.51%
2.84 years
25.01%
$0.76
2018
N/A
N/A
N/A
N/A
2017
1.52%
2.83 years
49.34%
$0.90
The assumption for expected volatility of our unit price reflects the historical volatility of MPLX common units.
The look-back period reflects the remaining performance period at the grant date. The risk-free interest rate for
the remaining performance period as of the grant date is based on the U.S. Treasury yield curve in effect at the
time of the grant. No grant date fair value has been calculated for performance units granted in 2018, since due to
the award terms, a grant date has not yet been established.
Total Unit-Based Compensation Expense
Total unit-based compensation expense for awards settling in MPLX common units was $22 million in 2019,
$24 million in 2018 and $18 million in 2017.
MPC’s Stock-based Compensation
Stock-based compensation expenses charged to MPLX under our employee services agreement with MPC were
$10 million, $8 million and $2 million for 2019, 2018 and 2017, respectively.
22. Leases
Lessee
We lease a wide variety of facilities and equipment under leases from third parties, including land and building
space, office and field equipment, storage facilities and transportation equipment, while our related party leases
primarily relate to ground leases associated with our refining logistics assets. Our remaining lease terms range
from less than one to 59 years. Some long-term leases include renewal options ranging from one to 50 years and,
in certain leases, also include purchase options. Renewal options and termination options were not included in
the measurement of ROU assets and lease liabilities since it was determined they were not reasonably certain to
be exercised.
165
Under ASC 840, operating lease costs were $89 million in 2018 and $64 million in 2017. Under ASC 842, the
components of lease cost were as follows:
(In millions)
Components of lease costs:
Operating lease costs
Finance lease cost:
Amortization of ROU assets
Interest on lease liabilities
Total finance lease cost
Variable lease cost
Short-term lease cost
Total lease cost
Supplemental balance sheet data related to leases were as follows:
(In millions)
Operating leases
Assets
Right of use assets
Liabilities
Operating lease liabilities
Long-term operating lease liabilities
Total operating lease liabilities
Weighted average remaining lease term
Weighted average discount rate
Finance leases
Assets
Property, plant and equipment, gross
Accumulated depreciation
Property, plant and equipment, net
Liabilities
Other current liabilities
Long-term debt
Total finance lease liabilities
Weighted average remaining lease term
Weighted average discount rate
2019
Related Party
Third Party
$
14
$
75
—
—
—
1
—
15
$
5
1
6
11
80
172
$
December 31, 2019
Related Party
Third Party
$
$
232
$
1
230
231
$
365
66
302
368
47.20 years
5.80%
8.59 years
4.38%
$
$
46
19
27
9
10
19
10.16 years
5.87%
As of December 31, 2019, maturities of lease liabilities for operating lease obligations and finance lease
obligations having initial or remaining non-cancellable lease terms in excess of one year are as follows:
166
(In millions)
2020
2021
2022
2023
2024
2025 and thereafter
Gross lease payments
Less: Imputed interest
Total lease liabilities
Related Party
Operating
Leases
Third Party
Operating
Leases
Finance
Leases
$
$
14
14
14
14
14
605
675
444
231
$
$
78
73
63
56
36
139
445
77
368
$
$
10
2
2
2
1
10
27
8
19
Future minimum commitments as of December 31, 2018, for capital lease obligations and for operating lease
obligations having initial or remaining non-cancellable lease terms in excess of one year are as follows:
(In millions)
2019
2020
2021
2022
2023
2024 and thereafter
Total minimum lease payments
Less: imputed interest costs
Present value of net minimum lease payments
Lessor
Operating
Lease
Obligations
Capital
Lease
Obligations
$
90
88
83
76
70
825
$
1,232
$
$
5
8
3
2
2
4
24
3
21
Based on the terms of fee-based transportation and storage services agreements with MPC and third parties ,
MPLX is considered to be the lessor under several operating lease arrangements in accordance with GAAP.
These agreements have remaining terms ranging from less than 1 year to 11 years with renewal options ranging
from 1 year to 5 years, with some agreements having multiple renewal options. We are also considered to be the
lessor under operating lease agreements related to certain fee-based natural gas gathering, transportation and
processing agreements. MPLX’s primary natural gas lease operations relate to a natural gas gathering agreement
in the Marcellus Shale for which it earns a fixed-fee for providing gathering services to a single producer using a
dedicated gathering system. As the gathering system is expanded, the fixed-fee charged to the producer is
adjusted to include the additional gathering assets in the lease. The primary term of the natural gas gathering
arrangement expires in 2038 and will continue thereafter on a year-to-year basis until terminated by either party.
Other significant natural gas implicit leases relate to a natural gas processing agreement in the Marcellus Shale
and a natural gas processing agreement in the Southern Appalachia region for which MPLX earns minimum
monthly fees for providing processing services to a single producer using a dedicated processing plant. The
primary term of these natural gas processing agreements expires during 2023 and 2033, these contracts will
continue thereafter on a year-to-year basis until terminated by either party.
MPLX did not elect to use the practical expedient to combine lease and non-lease components for lessor
arrangements. The tables below represent the portion of the contract allocated to the lease component based on
relative standalone selling price. Lessor agreements are currently deemed operating, as we elected the practical
expedient to carry forward historical classification conclusions. If and when a modification of an existing
agreement occurs and the agreement is required to be assessed under ASC 842, MPLX assesses the amended
agreement and makes a determination as to whether a reclassification of the lease is required.
167
During the year ended December 31, 2019, there was a modification to MPLX terminal agreements with MPC.
Based on the modification, certain terminals within the MPLX terminal agreement were reclassified from
operating leases to sales-type leases. As a result, the underlying assets previously shown on the Consolidated
Balance Sheets associated with the sales-type leases were derecognized and the net investment in the lease (i.e.,
the sum of the present value of the future lease payments and the unguaranteed residual value of the assets) was
recorded as a lease receivable. When determining the net investment in the lease, certain variable payments were
excluded from the total contract consideration, primarily related to fees for which there are no minimum volume
commitments. The difference between the net book value of the underlying assets and the net investment in the
lease has been recorded through equity given that the dropdown of MPLXT was a common control transaction.
During the year, MPLX derecognized approximately $29 million of property, plant and equipment, derecognized
approximately $3 million of existing deferred rent receivable, recorded a lease receivable of approximately
$47 million, recorded an unguaranteed residual asset of approximately $6 million and equity of $21 million.
Under ASC 840, MPLX’s revenue from its implicit lease arrangements, excluding executory costs, totaled
approximately $1,032 million in 2018 and $601 million in 2017. Lease revenues included on the Consolidated
Statements of Income during 2019 were as follows:
(In millions)
Operating leases:
Operating lease revenue(1)
Sales-type leases:
Profit/(loss) recognized at the commencement date
Interest income (Sales-type rental revenue- fixed minimum)
Interest income (Revenue from variable lease payments)
(1) These amounts are presented net of executory costs.
2019
Related Party
Third Party
$
1,020
$
257
—
6
1
$
N/A
N/A
N/A
The following is a schedule of minimum future rental revenue on the non-cancellable operating leases as of
December 31, 2019:
(In millions)
2020
2021
2022
2023
2024
2025 and thereafter
Total minimum future rentals
Related Party
Third Party
Total
$
$
1,134 $
1,130
1,127
1,074
1,015
2,699
8,179 $
186 $
179
177
170
167
1,072
1,951 $
1,320
1,309
1,304
1,244
1,182
3,771
10,130
The following is a schedule of minimum future rental revenue on the non-cancellable operating leases as of
December 31, 2018:
(In millions)
2019
2020
2021
2022
2023
2024 and thereafter
Total minimum future rentals
Related Party
Third Party
Total
$
$
1,277 $
1,275
1,146
1,143
1,094
3,786
9,721 $
171 $
163
154
151
145
1,114
1,898 $
1,448
1,438
1,300
1,294
1,239
4,900
11,619
168
The following is a schedule of minimum future revenue on the sales-type leases with MPC as of December 31,
2019:
(In millions)
2020
2021
2022
2023
2024
2025 and thereafter
Total minimum future rentals
Less: present value discount
Lease receivable
Related Party
$
$
14
14
14
15
15
20
92
45
47
The following schedule summarizes MPLX’s investment in assets held for operating lease by major classes as of
December 31, 2019 and 2018:
(In millions)
Natural gas gathering and NGL transportation pipelines and facilities
Processing, fractionation and storage facilities
Pipelines and related assets
Barges and towing vessels
Terminals and related assets
Refinery related assets
Land, building, office equipment and other
Total
Less accumulated depreciation
Property, plant and equipment, net
23. Commitments and Contingencies
December 31,
2019
2018
$
1,120 $
2,176
362
738
1,232
1,083
236
6,947
2,355
$
4,592 $
964
1,670
376
619
1,415
981
187
6,212
2,074
4,138
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 MPLX has not recorded an accrued liability, MPLX is
unable to estimate a range of possible losses for the reasons discussed in more detail below. However, the
ultimate resolution of some of these contingencies could, individually or in the aggregate, be material.
Environmental Matters – 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 December 31, 2019 and 2018, accrued liabilities for remediation totaled $19 million and $20 million,
respectively. However, it is not presently possible to estimate the ultimate amount of all remediation costs that
might be incurred or the penalties, if any, which may be imposed. At December 31, 2019 and 2018, there were no
balances with MPC for indemnification of environmental costs.
MarkWest Liberty Midstream, Ohio Fractionation and MarkWest Utica EMG, together with other
MarkWest affiliates, agreed to pay a penalty of approximately $0.9 million, undertake certain monitoring
and emission reduction projects at certain facilities with an estimated cost of approximately $3.3 million,
and implement certain process enhancements for its and its affiliates’ leak detection and repair programs at
169
its gas processing and fractionation sites. On November 1, 2018, MPLX and 11 of its subsidiaries entered into a
Consent Decree with the EPA, the State of Oklahoma, the Pennsylvania Department of Environmental Protection
and the State of West Virginia resolving these issues. The Consent Decree was approved by the court on
January 8, 2019 and the penalty has been paid.
MPLX is involved in environmental enforcement matters arising in the ordinary course of business. While the
outcome and impact on MPLX 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 – MPLX, MarkWest, MarkWest Liberty Midstream, MarkWest Liberty Bluestone, L.L.C., Ohio
Fractionation and MarkWest Utica EMG (collectively, the “MPLX Parties”) were parties to various lawsuits with
Bilfinger Westcon, Inc. (“Westcon”) that were instituted in 2016 and 2017 in the Court of Common Pleas in
Butler County, Pennsylvania, the Circuit Court in Wetzel County, West Virginia, and the Court of Common
Pleas in Harrison County, Ohio. The lawsuits related to disputes regarding construction work performed by
Westcon at the Bluestone, Mobley and Cadiz processing complexes in Pennsylvania, West Virginia and Ohio,
respectively, and the Hopedale fractionation complex in Ohio. As previously disclosed in our Quarterly Report
on Form 10-Q for the quarter ended June 30, 2019, in July 2019, Westcon and the MPLX Parties reached an
agreement to resolve the disputes among those parties relating to the Bluestone processing complex in
Pennsylvania. In the quarter ended December 31, 2019, Westcon and the MPLX Parties reached agreements to
resolve the remaining disputes among those parties relating to the Mobley and Cadiz processing complexes in
West Virginia and Ohio, respectively, and the Hopedale fractionation complex in Ohio. The settlements will not
have a material adverse effect on MPLX’s consolidated financial position, results of operations or cash flows.
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. 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.
Guarantees – Over the years, MPLX has sold various assets in the normal course of its business. Certain 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
require MPLX to perform upon the occurrence of a triggering event or condition. These guarantees and
indemnifications are part of the normal course of selling assets. MPLX is typically not able to calculate the
maximum potential amount of future 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.
In connection with our approximate 9 percent indirect interest in a joint venture that owns and operates the
Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects, collectively referred to as the Bakken
Pipeline system, we have entered into a Contingent Equity Contribution Agreement whereby MPLX LP, along
with the other joint venture owners in the Bakken Pipeline system, have 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 construction of Bakken Pipeline system. At December 31, 2019, our
maximum potential undiscounted payments under the Contingent Equity Contribution Agreement was
approximately $230 million.
Contractual Commitments and Contingencies – At December 31, 2019, MPLX’s contractual
commitments to acquire property, plant and equipment totaled $753 million. These commitments were
primarily related to G&P plant expansion, terminal, pipeline and refining logistics projects. In addition,
from time to time and in the ordinary course of business, MPLX and its affiliates provide guarantees of
MPLX’s subsidiaries payment and performance obligations in the G&P segment. Certain natural gas
170
processing and gathering arrangements require 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
December 31, 2019, management does not believe there are any indications that 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.
Other Contractual Obligations – MPLX executed transportation and terminalling agreements that obligate us to
minimum volume, throughput or payment commitments over the terms of the agreements, which range from four
to 20 years. After the minimum volume commitments are met in the transportation and terminalling agreements,
MPLX pays additional amounts based on throughput. There are escalation clauses in the transportation and
terminalling agreements, which are based on Consumer Price Index adjustments. The minimum future payments
under these agreements as of December 31, 2019 are as follows:
(In millions)
2020
2021
2022
2023
2024
2025 and thereafter
Total
$
2,246
2,222
2,199
2,200
1,753
191
$
10,811
SMR Transaction – On September 1, 2009, MarkWest entered into a product supply agreement creating a long-
term contractual obligation for the payment of processing fees in exchange for the entire product processed by
the SMR. See Note 17 for additional discussion. The product received under this agreement is sold to a refinery
customer pursuant to a corresponding long-term agreement. The minimum amounts payable annually under the
product supply agreement, excluding the potential impact of inflation adjustments per the agreement, are as
follows:
(In millions)
2020
2021
2022
2023
2024
2024 and thereafter
Total minimum payments
Less: Services element
Less: Interest
Total SMR liability
Less: Current portion of SMR liability
Long-term portion of SMR liability
171
$
$
17
17
17
17
17
92
177
68
29
80
5
75
Select Quarterly Financial Data (Unaudited)
(In millions, except per unit data)
1st Qtr.(1)
2nd Qtr.(1)
3rd Qtr.
4th Qtr.
2019
Total revenues and other income
Income from operations
Net income
Net income attributable to MPLX LP
Net income attributable to MPLX LP per limited
partner unit:
Common - basic
Common - diluted
Cash distributions declared per limited partner common
unit
Distributions declared:
Limited partner units - Public
Limited partner units - MPC
Series A preferred units
Series B preferred units
Total distributions declared
(In millions, except per unit data)
Total revenues and other income
Income from operations
Net income
Net income attributable to MPLX LP
Net income attributable to MPLX LP per limited
partner unit:
Common - basic
Common - diluted
Cash distributions declared per limited partner common
unit
Distributions declared:
Limited partner units - Public
Limited partner units - MPC
Series A preferred units
Total distributions declared
$
$
$
$
$
$
2,235
912
689
503
0.61
0.61
$
2,210
885
657
482
0.56
0.55
2,280
926
689
629
0.61
0.61
2,316
(346)
(573)
(581)
(0.58)
(0.58)
0.6575
0.6675
0.6775
0.6875
191
332
20
—
543
$
261
431
21
21
734
$
2018
266
438
20
10
734
$
270
446
20
11
747
1st Qtr.
2nd Qtr.
3rd Qtr.
4th Qtr.(1)
$
1,420
557
423
421
0.61
0.61
$
$
1,578
608
456
453
0.55
0.55
1,712
672
516
510
0.62
0.62
2,295
891
611
434
0.52
0.52
0.6175
0.6275
0.6375
0.6475
179
288
16
483
$
181
316
20
517
$
185
322
19
526
$
187
327
20
534
(1) As discussed in Note 1, MPLX’s acquisition of ANDX is considered a transfer between entities under common control
due to MPC’s prior relationship with ANDX. Transfers of businesses between entities under common control require
prior periods to be retrospectively adjusted for those dates that the entity was under common control. Accordingly, the
tables above include the historical results of ANDX beginning October 1, 2018. Amounts shown for the fourth quarter of
2018 as well as the first and second quarters of 2019 are different than amounts previously reported for Total revenues
and other income, Income from operations and Net income as a results of this retrospective adjustment for ANDX. Total
revenues and other income originally reported for the fourth quarter of 2018 and the first and second quarters of 2019
was $1,715 million, $1,646 million and $1,629 million, respectively. Income from operations originally reported for the
fourth quarter of 2018 and the first and second quarters of 2019 was $666 million, $678 million and $659 million,
respectively. Net income originally reported for the fourth quarter of 2018 and the first and second quarters of 2019 was
$439 million, $509 million and $488 million, respectively.
172
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
None
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
MPLX’s management, under the supervision and with the participation of the Chief Executive Officer and Chief
Financial Officer, performed an evaluation of the effectiveness of the design and operation of our disclosure
controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 Act, as
amended, as of December 31, 2019. Based on this evaluation, MPLX’s management, including our Chief
Executive Officer and Chief Financial Officer, concluded that as of December 31, 2019, our disclosure controls
and procedures were effective to provide reasonable assurance that information required to be disclosed by us in
the reports that we file or submit under the Securities Exchange Act of 1934 Act, as amended, is recorded,
processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and to
provide reasonable assurance that such information is accumulated and communicated to our management,
including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions
regarding required disclosures.
Internal Control Over Financial Reporting and Changes in Internal Control Over Financial Reporting
During the three months ended December 31, 2019, 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. See Item 8. Financial Statements and Supplementary Data – Management’s Report on
Internal Control over Financial Reporting.
Limitations on Controls
Management has designed our disclosure controls and procedures and internal control over financial reporting to
provide reasonable assurance of achieving their objectives as specified above. Management does not expect,
however, that our disclosure controls and procedures or our internal control over financial reporting will prevent
or detect all error and fraud. Any control system, no matter how well designed and operated, is based upon
certain assumptions and can provide only reasonable, not absolute, assurance that its objectives will be met.
Further, no evaluation of controls can provide absolute assurance that misstatements due to error or fraud will not
occur or that management has detected all control issues and instances of fraud, if any, within MPLX.
Item 9B. Other Information
None
Part III
Item 10. Directors, Executive Officers and Corporate Governance
MANAGEMENT OF MPLX LP
MPLX GP LLC, our general partner, is a wholly-owned subsidiary of MPC. Our general partner manages our
operations and activities through its directors and executive officers. Our unitholders do not nominate candidates
for, or vote for the election of, the directors of our general partner. Through its indirect ownership of all of the
membership interests in our general partner, MPC elects all members of our general partner’s board of directors
(the “Board”). Directors are elected by the sole member of our general partner and hold office until their
successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Our
general partner’s executive officers are appointed by, and serve at the discretion of, the Board.
173
References in this Part III to our “Board,” “directors” or “officers” refer to the Board, directors and officers of
our general partner.
Neither we nor our subsidiaries directly employ any employees. Our general partner has the sole responsibility
for providing the employees and other personnel necessary to conduct our operations. All of the employees who
conduct our business are directly employed by affiliates of our general partner, but we sometimes refer to these
individuals as our employees for ease of reference.
DIRECTORS AND EXECUTIVE OFFICERS OF MPLX GP LLC
The following table shows information for our directors, and executive and corporate officers as of January 31,
2020.
Name
Age
Position with MPLX GP LLC
Gary R. Heminger
Michael J. Hennigan
Pamela K.M. Beall
Michael L. Beatty
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
Frank M. Semple
J. Michael Stice
John P. Surma
Donald C. Templin
Gregory S. Floerke
John S. Swearingen
Suzanne Gagle
Raymond L. Brooks*
Rick D. Hessling*
Brian K. Partee*
David L. Whikehart*
Timothy J. Aydt*
Molly R. Benson*
Peter Gilgen*
C. Kristopher Hagedorn
Kristina A. Kazarian*
Shawn M. Lyon*
*
Corporate officer
66
60
63
72
65
68
71
68
60
65
56
56
60
54
59
53
46
60
56
53
63
43
37
52
Chairman of the Board of Directors
Director, President and Chief Executive Officer
Director, Executive Vice President and Chief Financial Officer
Director
Director
Director
Director
Director
Director
Director
Director
Executive Vice President, Gathering and Processing
Executive Vice President, Logistics and Storage
General Counsel
Senior Vice President
Senior Vice President
Senior Vice President
Senior Vice President
Vice President, Business Development
Vice President, Chief Securities, Governance & Compliance Officer
and Corporate Secretary
Vice President and Treasurer
Vice President and Controller
Vice President, Investor Relations
Vice President, Operations
Mr. Heminger has served as Chairman of the Board since June 2012 and as Chief Executive Officer from June
2012 through October 2019. He has served as MPC’s Chairman of the Board since April 2016, as its Chief
Executive Officer since June 2011, and as its President from 2011 to 2017. Mr. Heminger began his career with
Marathon in 1975 and has served in roles in finance and administration, auditing, marketing and commercial, and
business development, including as President of Marathon Pipe Line Company; Manager, Business Development
and Joint Interest of Marathon Oil Company; and Vice President and Senior Vice President, Business
Development, Marathon Ashland Petroleum LLC. In 2001, he was named Executive Vice President, Supply,
Transportation and Marketing, and was appointed President of Marathon Petroleum Company LLC and
Executive Vice President-Downstream of Marathon Oil Corporation later that year. Mr. Heminger has announced
his plans to retire from the Board and from MPC effective April 29, 2020.
174
Mr. Heminger serves on the boards of directors and executive committees of the American Petroleum Institute
(API) and the American Fuel & Petrochemicals Manufacturers (AFPM), and is a member of the Oxford Institute
for Energy Studies. He is Chair of The Ohio State University Board of Trustees and past Chair of the Tiffin
University Board of Trustees. Mr. Heminger holds a bachelor’s degree in accounting from Tiffin University and
a master’s degree in business administration from the University of Dayton, and he is a graduate of the Wharton
School Advanced Management Program at the University of Pennsylvania.
Qualifications: Mr. Heminger brings to the Board energy industry expertise, extensive knowledge of all aspects
of our business and a breadth of transactional experience. As our former Chief Executive Officer, he leverages
that expertise in advising on our strategic direction and apprising the Board on issues of significance to our
industry and to us.
Other Public Company Directorships: Marathon Petroleum Corporation (since 2011); Tesoro Logistics GP, LLC
(2018-2019); Fifth Third Bancorp (since 2006); PPG Industries, Inc. (since 2017)
Mr. Hennigan was appointed Chief Executive Officer effective November 2019 and has served as President
since June 2017. He has also served on the Board of Directors since June 2017. Prior to joining us in 2017,
Mr. Hennigan was President, Crude, NGL and Refined Products of the general partner of Energy Transfer
Partners L.P., an energy service provider. He was President and Chief Executive Officer of Sunoco Logistics
Partners L.P., an oil and gas transportation, terminalling and storage company, from 2012 to 2017, President and
Chief Operating Officer beginning in 2010, and Vice President, Business Development beginning in 2009.
Mr. Hennigan holds a bachelor’s degree in chemical engineering from Drexel University.
Qualifications: Mr. Hennigan brings to the Board a unique perspective and valued guidance gained from more
than 38 years of industry experience, including as the president and chief executive officer of a successful
growth-oriented master limited partnership.
Other Public Company Directorships: Tesoro Logistics GP, LLC (2018-2019); Sunoco Partners LLC (2010-
2017); Niska Gas Storage Partners LLC (2014-2016)
Ms. Beall was appointed Executive Vice President and Chief Financial Officer effective 2016, and was elected a
member of the Board in January 2014. Ms. Beall began her career with Marathon in 1978 as an auditor. She then
served as General Manager, Treasury Services, at USX Corporation; Vice President and Treasurer at
NationsRent, Inc. and OHM Corporation; and as a member of the boards of directors of System One Services,
Inc. and Boyle Engineering. Ms. Beall rejoined Marathon in 2002, serving in areas of increasing responsibility,
including as Director, Corporate Affairs; Organizational Vice President, Business Development - Downstream;
Vice President of Global Procurement, Marathon Oil Company; and Vice President of Products, Supply &
Optimization. She served as MPC’s Vice President, Investor Relations and Government & Public Affairs from
2011 to 2014, when she was named President of MPLX GP. Ms. Beall was also named Executive Vice President,
Corporate Planning and Strategy of MPLX GP in 2016. She serves on the University of Findlay Board of
Trustees and is a member of the Ohio Society of CPAs. Ms. Beall holds a bachelor’s degree in accounting from
the University of Findlay and a master’s degree in business administration from Bowling Green State University,
and she has attended the Oxford Institute for Energy Studies. She is licensed as a certified public accountant in
Ohio.
Qualifications: Ms. Beall brings to the Board extensive energy industry experience, specifically in the areas of
finance and accounting, business development, risk management, procurement, investor relations and
government affairs. In addition, her service as a senior executive in the environmental remediation and industrial
product rental sectors equips her to contribute valuable insight into our business and operations.
Other Public Company Directorships: Tesoro Logistics GP, LLC (2018-2019); National Retail Properties, Inc.
(since 2016)
Mr. Beatty was elected a member of the Board in December 2015, at the time of the MarkWest Merger.
Mr. Beatty served on the board of directors of MarkWest’s general partner from 2008 to 2015, and prior to that,
on the board of directors of MarkWest Hydrocarbon. Mr. Beatty is a former Chairman of the law firm of
Beatty & Wozniak, P.C., with a practice focused exclusively on energy, including oil and gas exploration,
175
regulatory affairs, public lands, litigation and title. He began his career in the energy industry as in-house counsel
for Colorado Interstate Gas Company, and ultimately became Executive Vice President, General Counsel and
Director of The Coastal Corporation. He also served as Chief of Staff to Governor Roy Romer of Colorado.
Mr. Beatty holds an undergraduate degree from the University of California, Berkeley and a juris doctor degree
from Harvard Law School. He also serves on the board of directors of the Cystic Fibrosis Foundation.
Qualifications: Mr. Beatty brings to the Board extensive experience in the oil and gas industry, including
significant experience in energy policy and energy regulation gained through his experience as a director, officer
and legal counsel of various energy companies, as well as extensive historical knowledge of MarkWest.
Other Public Company Directorships: Denbury Resources Inc. (2007-2015); MarkWest Energy GP, L.L.C.
(2008-2015)
Mr. Helms was elected a member of the Board effective October 2012. Mr. Helms is President and Chief
Executive Officer of US Shale Management Company, a wholly-owned subsidiary of US Shale Energy Advisors
LLC. Mr. Helms is the co-founder of US Shale Energy Advisors LLC, a privately owned entity engaged in the
development, ownership and operation of midstream energy assets. He also serves on the board of directors of
TRC Companies, L.L.C. From 2005 until his retirement in 2011, Mr. Helms served in various capacities with
NiSource Inc. and its affiliate, NiSource Gas Transmission and Storage, including as Executive Vice President
and Group Chief Executive Officer. He was Group President, Pipeline of NiSource Inc. from 2005 to 2008,
where he was also a member of the Executive Council and the Corporate Risk Management Committee. He
served as Chief Executive Officer and Executive Director of NiSource Gas Transmission and Storage from 2008
to 2011. At NiSource, Mr. Helms was responsible for leading the company’s interstate gas transmission, storage
and midstream businesses. Prior to joining NiSource, Mr. Helms held senior executive positions with CMS
Energy Corporation, and subsidiaries of Duke Energy Corporation and PanEnergy Corp. from 1990 to 2005.
Mr. Helms holds a bachelor’s degree from Southern Illinois University at Edwardsville and a juris doctor degree
from the Tulane University School of Law.
Qualifications: Mr. Helms brings to the Board considerable midstream energy expertise, particularly in
operations and business combinations, as well as experience in finance, accounting, compliance, strategic
planning and risk oversight. His background also includes overseeing joint ventures and mergers and acquisitions
within the midstream energy sector and supervising financial reporting functions.
Other Public Company Directorships: Range Resources Corporation (2014-2019); Questar Corporation (2013-
2016)
Mr. Peiffer was elected a member of the Board in June 2012, and served as our President from 2012 until his
retirement in January 2014. He also served as MPC’s Executive Vice President, Corporate Planning and
Investor & Government Relations from 2011 until his retirement. He is a member of the board of directors of the
Fifth Third Bank (Northwestern Ohio). Mr. Peiffer is also a member of the boards of trustees of the Blanchard
Valley Health System and the Findlay-Hancock County Community Foundation and serves on the Blanchard
Valley Port Authority Board. He began his career with Marathon in 1974, where he held a variety of
management positions with increasing responsibility, including as Supervisor of Employee Savings and
Retirement Plans, Controller of Speedway Petroleum Corporation and numerous other marketing and logistics
positions. In 1987, Mr. Peiffer was appointed to the President’s Commission on Executive Exchange serving for
a year in the Pentagon as Special Assistant to the Assistant Secretary of Defense for Production and Logistics. In
1988, he returned to Marathon and was named Vice President of Finance and Administration for Emro Marketing
Company. He served as Assistant Controller, Refining, Marketing and Transportation beginning in 1992. He was
named Senior Vice President of Finance and Commercial Services for Marathon Ashland Petroleum LLC in
1998 and Executive Vice President of MPC in 2011. Mr. Peiffer holds a bachelor’s degree in accounting from
Bowling Green State University and passed the certified public accountant exam in Ohio.
Qualifications: As the retired President of our general partner and retired Executive Vice President,
Corporate Planning and Investor & Government Relations of MPC, Mr. Peiffer brings to the Board
extensive experience in the energy industry gained from his roles at MPC and its affiliates. His significant
176
career accomplishments include leading us through the initial public offering process and our first year of
operations, leading finance organizations, successfully realizing several joint ventures and corporate
reorganizations and implementing new information technology solutions.
Other Public Company Directorships: None within the last five years
Mr. Sandman was elected a member of the Board effective October 2012. Mr. Sandman is an adjunct professor
at The Ohio State University Moritz College of Law, where he has taught corporate governance law since 2007.
He serves on the CONSOL Coal Resources GP LLC Board of Directors and has served on the board of directors
of Roppe Corporation, a privately held company, since 1987. Additionally, Mr. Sandman serves on the boards of
directors of the Carnegie Science Center, the Carnegie Hero Commission and Grove City College. He has served
as a court-appointed mediator of commercial cases pending in U.S. federal courts and has lectured on corporate
governance law at Oxford University. Mr. Sandman began his career with Marathon in 1973, serving in various
legal positions of increasing responsibility, ultimately being named General Counsel and Secretary of Marathon
in 1986. In 1993, he was named General Counsel and Secretary of USX Corporation. Upon the spinoff of United
States Steel Corporation from USX in 2002, Mr. Sandman was named Vice Chairman of the Board of Directors
and Chief Legal and Administrative Officer of United States Steel, where he served until his retirement in 2007.
During his time with United States Steel, Mr. Sandman was also responsible at various times for management
and oversight of aspects of Human Resources, Executive Compensation, Public Relations, Environmental and
Government Affairs, the Law Organization and the Corporate Secretary’s office. Mr. Sandman holds a bachelor’s
degree from The Ohio State University and a juris doctor degree from The Ohio State University College of Law,
and he attended the Stanford Executive Program in 1989.
Qualifications: Mr. Sandman brings to the Board considerable experience in legal and business affairs,
transactional law, regulatory compliance and corporate governance, ethics and risk management matters, as well
as an energy industry background.
Other Public Company Directorships: CONSOL Coal Resources GP LLC (since 2017)
Mr. Semple was elected a member of the Board effective December 2015, at the time of the MarkWest Merger.
He was appointed our Vice Chairman at the close of the MarkWest Merger and served in that position until his
retirement in October 2016. He also served on the MPC Board of Directors from December 2015 until October
2018. Prior to joining us, Mr. Semple served as President and Chief Executive Officer of MarkWest beginning in
2003, and as Chairman of the Board beginning in 2008. Prior to his time at MarkWest, he served 22 years with
The Williams Companies, Inc. and WilTel Communications, including as Chief Operating Officer of WilTel
Communications, Senior Vice President/General Manager of Williams Natural Gas Company, Vice President of
Operations and Engineering for Northwest Pipeline Company and division manager for Williams Pipe Line
Company. Prior to joining Williams, Mr. Semple served in the United States Navy. He holds a bachelor’s degree
in mechanical engineering from the United States Naval Academy and has completed the Program for
Management Development at Harvard Business School.
Qualifications: Mr. Semple brings to the Board proven leadership ability in managing a complex business and a
deep understanding of the midstream sector gained from his experience as Chairman and Chief Executive Officer
of MarkWest, as well as significant experience regarding operations, strategic planning, finance and corporate
governance matters.
Other Public Company Directorships: Tortoise Acquisition Corp (since 2019); Tesoro Logistics GP, LLC (2018-
2019); Marathon Petroleum Corporation (2015-2018); MarkWest Energy GP, L.L.C. (2003-2015)
Mr. Stice was elected a member of the Board effective April 2018, and as a member of the MPC Board of
Directors in February 2017. He has served as the Dean of the Mewbourne College of Earth & Energy at The
University of Oklahoma since August 2015. Mr. Stice retired as the Chief Executive Officer of Access
Midstream Partners L.P., a gathering and processing master limited partnership, in 2014 and from its board
of directors in 2015. He had served as Chief Executive Officer of Access Midstream and previously,
Chesapeake Midstream Partners, L.P., since 2009, and as President and Chief Operating Officer of
Chesapeake Midstream Development, L.P. and Senior Vice President of natural gas projects of Chesapeake
177
Energy Corporation since 2008. Mr. Stice began his career in 1981 with Conoco, serving in a variety of positions
of increasing responsibility. He was named President of ConocoPhillips Qatar in 2003. Mr. Stice holds a
bachelor’s degree in chemical engineering from the University of Oklahoma, a master’s degree in business from
Stanford University and a doctorate in education from George Washington University.
Qualifications: Mr. Stice brings to the Board extensive experience with MLPs, including as Chief Executive
Officer of one of the largest publicly traded gathering and processing MLPs, and previously served on the board
of directors of MarkWest, which we acquired in 2015. He has 35 years of experience in the upstream and
midstream gas businesses.
Other Public Company Directorships: Marathon Petroleum Corporation (since 2017); U.S. Silica Holdings, Inc.
(since 2013); Spartan Energy Acquisition Corporation (since 2018); Access Midstream Partners GP, L.L.C.
(2012-2015); MarkWest Energy GP, L.L.C. (2015); SandRidge Energy, Inc. (2015-2016); Williams Partners GP
LLC (2015)
Mr. Surma was elected a member of the Board effective October 2012, and as a member of the MPC Board of
Directors in July 2011. He retired as the Chief Executive Officer and Executive Chairman of United States Steel
Corporation, an integrated steel producer, in 2013. Prior to joining United States Steel, Mr. Surma served in
several executive positions with Marathon, including as Senior Vice President, Finance & Accounting of
Marathon Oil Company in 1997; President, Speedway SuperAmerica LLC in 1998; Senior Vice President,
Supply & Transportation of Marathon Ashland Petroleum LLC in 2000; and President of Marathon Ashland
Petroleum in 2001. Prior to joining Marathon, Mr. Surma worked for Price Waterhouse LLP, becoming a partner
in 1987. In 1983, Mr. Surma participated in the President’s Executive Exchange Program in Washington, D.C.,
serving as Executive Staff Assistant to the Federal Reserve Board’s Vice Chairman. Mr. Surma is on the board of
the University of Pittsburgh Medical Center, and formerly chaired the boards of the Federal Reserve Bank of
Cleveland and the National Safety Council. He was appointed by President Barack Obama to the President’s
Advisory Committee for Trade Policy and Negotiations, serving from 2010 to 2014, including as Vice Chairman.
Mr. Surma holds a bachelor’s degree in accounting from Pennsylvania State University.
Qualifications: Mr. Surma brings to the Board a broad range of experience as the retired chairman and chief
executive officer of a large industrial firm and provides valuable input on our strategic direction and operations.
He also has significant experience in public accounting and in executive leadership in the energy and steel
industries.
Other Public Company Directorships: Marathon Petroleum Corporation (since 2011); Concho Resources Inc.
(since 2014); Ingersoll-Rand plc (since 2013); Public Service Enterprise Group Inc. (since 2019); United States
Steel Corporation (2001-2013)
Mr. Templin was elected a member of the Board in June 2012. He was appointed Executive Vice President and
Chief Financial Officer of MPC effective July 2019. Prior to this appointment, he served as President, Refining,
Marketing and Supply of MPC beginning in October 2018, President of MPC beginning in 2017, President of
MPLX GP and Executive Vice President of MPC beginning in 2016, Executive Vice President, Supply,
Transportation and Marketing of MPC beginning in 2015, Vice President and Chief Financial Officer of MPLX
GP beginning in 2012, and Senior Vice President and Chief Financial Officer of MPC beginning in 2011. Prior to
joining MPC, Mr. Templin was a managing partner of the audit practice of PricewaterhouseCoopers LLP with
more than 25 years of providing auditing and advisory services to a wide variety of private, public and
multinational companies. He is a member of the Grove City College Board of Trustees and past Chairman of the
Downstream Committee of API. Mr. Templin is a graduate of Grove City College, a certified public accountant,
a member of the American Institute of Certified Public Accountants and has attended the Oxford Institute for
Energy Studies.
Qualifications: Mr. Templin brings to the Board direct insight into all aspects of our business, from an
operational and commercial perspective, and in the areas of accounting, audit and financial management. His
long and successful background in public accounting for energy sector clients affords him insight into public
company financial reporting requirements and related matters.
178
Other Public Company Directorships: Tesoro Logistics GP, LLC (2018-2019); Calgon Carbon Corporation
(2013-2018)
Mr. Floerke was appointed Executive Vice President, Gathering and Processing effective 2018. Prior to this
appointment, he served as Executive Vice President and Chief Operating Officer, MarkWest Operations
beginning in July 2017, and Executive Vice President and Chief Commercial Officer, MarkWest Assets
beginning in December 2015, at the time of the MarkWest Merger. Before joining us, Mr. Floerke was Executive
Vice President and Chief Commercial Officer at MarkWest beginning in 2015, and Senior Vice President,
Northeast region at MarkWest beginning in 2013. Previously, Mr. Floerke held senior management positions at
Access Midstream Partners, L.P., a gathering and processing master limited partnership, from 2011 until 2013.
Mr. Swearingen was appointed Executive Vice President, Logistics and Storage effective July 2017. Prior to
this appointment, he served as Vice President, Crude Oil and Refined Products Pipelines and Chief Operating
Officer, Pipeline Operations and as MPC’s Senior Vice President, Transportation and Logistics beginning in
March 2015. He previously served in various leadership positions with MPC and its affiliates, including as
MPC’s Vice President, Health, Environment, Safety and Security beginning in 2011 and President of Marathon
Pipe Line LLC beginning in 2009.
Ms. Gagle was appointed General Counsel effective October 2017, and General Counsel of MPC effective
March 2016. Prior to this appointment, she served as MPC’s Assistant General Counsel, Litigation and Human
Resources beginning in April 2011, Senior Group Counsel, Downstream Operations beginning in 2010, and
Group Counsel, Litigation beginning in 2003.
Mr. Brooks was appointed Senior Vice President effective February 2018, and MPC’s Executive Vice President,
Refining effective October 2018. Prior to this appointment, he served as MPC’s Senior Vice President, Refining
beginning in March 2016, General Manager of MPC’s Galveston Bay, Texas refinery beginning in February
2013, General Manager of MPC’s Robinson, Illinois refinery beginning in 2010, and General Manager of MPC’s
St. Paul Park, Minnesota refinery beginning in 2006.
Mr. Hessling was appointed Senior Vice President, and MPC’s Senior Vice President, Crude Oil Supply and
Logistics effective October 2018. Prior to this appointment, he served as MPC’s Manager, Crude Oil & Natural
Gas Supply and Trading beginning in September 2014, and Crude Oil Logistics & Analysis Manager beginning
in July 2011.
Mr. Partee was appointed Senior Vice President, and MPC’s Senior Vice President, Marketing effective October
2018. Prior to this appointment, he served as MPC’s Vice President, Business Development beginning in
February 2018, Director of Business Development beginning in January 2017, Manager of Crude Oil Logistics
beginning in September 2014, and Vice President, Business Development and Franchise at Speedway beginning
in November 2012.
Mr. Whikehart was appointed Senior Vice President, and MPC’s Senior Vice President, Light Products, Supply
and Logistics effective October 2018. Prior to this appointment, he served as MPC’s Vice President,
Environment, Safety and Corporate Affairs beginning in February 2016, Vice President, Corporate Planning,
Government & Public Affairs beginning in January 2016, and Director, Product Supply and Optimization
beginning in March 2011.
Mr. Aydt was appointed Vice President, Business Development effective November 2018. Prior to this
appointment, he served as Vice President, Operations and President of Marathon Pipe Line LLC beginning in
January 2017, MPC’s Terminal, Transport and Rail General Manager beginning in 2013, and Project Director for
the Detroit Heavy Oil Upgrade Project beginning in 2008.
Ms. Benson was appointed Vice President, Chief Compliance Officer and Corporate Secretary for MPC and us
effective March 2016, and Chief Securities and Governance Officer of MPC and us effective June 2018. Prior to
her 2016 appointment, Ms. Benson was MPC’s Assistant General Counsel, Corporate and Finance beginning in
April 2012, and Group Counsel, Corporate and Finance beginning in 2011.
179
Mr. Gilgen was appointed Vice President and Treasurer effective February 2017. Prior to that, he was our
Assistant Treasurer beginning in 2012 and the Assistant Treasurer of MPC beginning in 2011.
Mr. Hagedorn was appointed Vice President and Controller effective October 2017. Prior to this appointment,
he was Vice President and Controller at CONSOL Energy Inc., a Pennsylvania-based coal producer and exporter,
beginning in 2015, Assistant Controller beginning in 2014 and Director, Financial Accounting beginning in 2012.
He was Chief Accounting Officer for CONE Midstream Partners LP, a publicly traded master limited partnership
with gathering assets in the Appalachian Basin, from 2014 to 2015. Previously, Mr. Hagedorn served in positions
of increasing responsibility with PricewaterhouseCoopers LLP beginning in 1998.
Ms. Kazarian was appointed Vice President, Investor Relations for MPC and us effective April 2018. Prior to
this appointment, she was Managing Director and head of the MLP, Midstream and Refining Equity Research
teams at Credit Suisse, a global investment bank and financial services company, beginning in September 2017.
Previously, Ms. Kazarian was Managing Director of MLP, Midstream and Natural Gas Equity Research at
Deutsche Bank, a global investment bank and financial services company, beginning in September 2014, and an
analyst specializing on various energy industry subsectors with Fidelity Management & Research Company, a
privately held investment manager, beginning in 2005.
Mr. Lyon was appointed Vice President, Operations and President, Marathon Pipe Line LLC effective
November 2018. Prior to that, he was Vice President of Operations for Marathon Pipe Line LLC beginning in
2011.
GOVERNANCE FRAMEWORK
Our Governance Principles provide the functional framework of our Board. They address, among other things,
the primary roles, responsibilities and oversight functions of the Board and its committees, director
independence, committee composition, the process for director selection and director qualifications, director
compensation and director retirement and resignation.
Our Code of Business Conduct, which applies to all of our directors, officers and employees, defines our
expectations for ethical decision-making, accountability and responsibility. Our Code of Ethics for Senior
Financial Officers, which is specifically applicable to our Chief Executive Officer, Chief Financial Officer,
Controller, and other leaders performing similar roles, affirms the principle that the honesty, integrity and sound
judgment of our senior executives with responsibility for preparation and certification of our financial statements
are essential to the proper functioning and success of our company. Printed copies of these documents are
available upon request to our Corporate Secretary. We would post on our website any amendments to, or waivers
from, either of these codes requiring disclosure under applicable rules within four business days following any
such amendment or waiver.
Our Whistleblowing as to Accounting Matters Policy establishes procedures for the receipt, retention and
treatment of complaints we receive regarding accounting, internal accounting controls or auditing matters, and
provides for the confidential, anonymous submission of concerns by employees or others regarding questionable
accounting or auditing matters.
Copies of the Governance Principles, the Code of Business Conduct, the Code of Ethics for Senior Financial
Officers, and the Whistleblowing as to Accounting Matters Policy are available on the “Corporate Governance”
page of our website at www.mplx.com/Investors/Corporate-Governance.
DIRECTOR INDEPENDENCE
The Board currently consists of eleven directors. The NYSE does not require a publicly traded limited
partnership like us to have a majority of independent directors on our Board. We are, however, required to
have an Audit Committee comprised of at least three independent directors. The Board considered all relevant
facts and circumstances including, without limitation, transactions between the director directly or
organizations with which the director is affiliated and us, any service by the director on the board of a
company with which we conduct business, and the frequency and dollar amounts associated with these
transactions, and has determined that each of Messrs. Beatty, Helms, Peiffer, Sandman, Semple, Stice and
Surma meets the independence standards in our Governance Principles, has no material relationship with us
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other than as a director, and satisfies the independence requirements of the NYSE and applicable SEC rules.
BOARD LEADERSHIP STRUCTURE
Our Governance Principles provide the Board with the flexibility to determine from time to time the optimal
leadership for the Board depending upon our particular needs and circumstances. The Board has determined that
Mr. Heminger is in the best position at this time to serve as Chairman due to his extensive knowledge of all
aspects of our business, as well as our continued relationship with MPC.
When the CEO or another management director is elected Chairman, the Board has appointed an independent
director as “Lead Director” to provide independent director oversight and preside over executive sessions of the
Board or other Board meetings when the Chairman is absent.
Mr. Sandman, an independent director, currently serves as Lead Director of the Board. The Board believes that
this leadership structure is in the best interests of our unitholders and us at this time because it strikes an effective
balance between management and independent director participation in the Board process.
COMMITTEES OF THE BOARD
Our Board has a standing Audit Committee and Conflicts Committee, and may have such other committees as
the Board shall determine from time to time. Each committee operates under a written charter, which is available
on the “Corporate Governance” page of our website at www.mplx.com/Investors/Corporate-Governance. Each
charter requires the applicable committee to annually assess and report to the Board on the adequacy of the
charter.
We have additionally established an executive committee of the board, comprised of Messrs. Heminger and
Sandman, to address matters that may arise between meetings of the Board. This executive committee may
exercise the powers and authority of the Board subject to specific limitations consistent with applicable law.
Because we are a limited partnership, we are not required to have a compensation committee or a nominating/
corporate governance committee.
Audit Committee
Our Audit Committee assists the Board in its oversight of the integrity of our financial statements, and our
compliance with legal and regulatory requirements and our disclosure controls and procedures. Our Audit
Committee has the sole authority to retain and terminate our independent registered public accounting firm,
approve all auditing services and related fees and the terms thereof and pre-approve any non-audit services to be
rendered by our independent registered public accounting firm. Our Audit Committee also is responsible for
confirming the independence and objectivity of our independent registered public accounting firm. Our
independent registered public accounting firm has unrestricted access to our Audit Committee.
Our Audit Committee is comprised of Messrs. Peiffer (Chair), Beatty, Helms and Sandman. The Board has
determined that each member of the Audit Committee meets the independence requirements of the NYSE and the
SEC, as applicable, and that each is financially literate. The Board also has determined that Mr. Peiffer qualifies
as an “audit committee financial expert,” as defined by SEC rules, based on the attributes, education and
experience further described in his biography under “Directors and Executive Officers of MPLX GP LLC,”
above.
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Audit Committee Report
The Audit Committee has reviewed and discussed MPLX’s audited financial statements and its report on internal
control over financial reporting for 2019 with the management of MPLX GP LLC, MPLX’s general partner. The
Audit Committee discussed with the independent auditors, PricewaterhouseCoopers LLP, the matters required to
be discussed by the applicable requirements of the Public Company Accounting Oversight Board and the SEC.
The Audit Committee has received the written disclosures and the letter from PricewaterhouseCoopers LLP
required by the applicable requirements of the Public Company Accounting Oversight Board regarding
PricewaterhouseCoopers LLP’s communications with the Audit Committee concerning independence, and has
discussed with PricewaterhouseCoopers LLP its independence. Based on the review and discussions referred to
above, the Audit Committee recommended to the Board that the audited financial statements and the report on
internal control over financial reporting for MPLX LP be included in MPLX’s Annual Report on Form 10-K for
the year ended December 31, 2019, for filing with the SEC.
Garry L. Peiffer, Chair
Michael L. Beatty
Christopher A. Helms
Dan D. Sandman
Conflicts Committee
Our Conflicts Committee reviews specific matters that may involve conflicts of interest in accordance with the
terms of our Partnership Agreement. Any matters approved by our Conflicts Committee in good faith will be
deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe
our unitholders or us. The members of our Conflicts Committee may not be officers or employees of our general
partner or directors, officers or employees of its affiliates, and must meet the independence and experience
standards established by the NYSE and the SEC to serve on an audit committee. In addition, the members of our
Conflicts Committee may not own any interest in our general partner or any interest in us, our subsidiaries or our
affiliates other than common units or awards under our incentive compensation plan.
Our Conflicts Committee is comprised of Messrs. Helms (Chair), Beatty and Sandman. The Board has
determined that each member of the Conflicts Committee meets the independence requirements of the NYSE and
the SEC, as applicable.
COMMUNICATING WITH THE BOARD
All interested parties, including unitholders, may communicate directly with the Board, the Chairs of the Board’s
standing committees and the independent directors as follows:
Mail: Attn: Corporate Secretary, MPLX GP LLC, 200 East Hardin Street, Findlay, OH 45840.
Independent Directors (individually or as a group): non-managedirectors@mplx.com
Email:
•
• Audit Committee Chair: auditchair@mplx.com
• Conflicts Committee Chair: conflictschair@mplx.com
Our Corporate Secretary will forward to the directors all communications that, in her judgment, are appropriate
for consideration by the directors. Examples of communications that would not be considered appropriate include
commercial solicitations and matters not relevant to the Partnership’s affairs.
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Item 11. Executive Compensation
EXECUTIVE COMPENSATION DISCUSSION AND ANALYSIS
This Executive Compensation Discussion and Analysis (“CD&A”) provides an overview of our compensation
philosophy and objectives and explains how and why 2019 compensation decisions were made for our named
executive officers (our “NEOs”). We recommend that this section be read together with the tables and related
disclosures in the “Executive Compensation Tables” section of this Item 11.
NAMED EXECUTIVE OFFICERS
This CD&A focuses on the compensation for our NEOs, which for 2019 included our Chairman and former
Chief Executive Officer (“CEO”), current CEO, Chief Financial Officer, and three other most highly
compensated executive officers serving at the end of 2019. Our NEOs for 2019 were:
Name
Gary R. Heminger
Michael J. Hennigan
Pamela K.M. Beall
John S. Swearingen
Suzanne Gagle
Gregory S. Floerke
Title
Chairman
President and Chief Executive Officer MPLX
Executive Vice President and Chief Financial Officer
Executive Vice President, Logistics and Storage
General Counsel
Executive Vice President, Gathering and Processing
Mr. Heminger has served as our Chairman since June 2012 and as CEO from June 2012 through October 31,
2019. Mr. Hennigan was appointed President and CEO effective November 1, 2019, having previously served as
President since June 2017.
COMPENSATION DECISIONS AND ALLOCATION
We do not directly employ any of the personnel responsible for managing and operating our business, including
our NEOs. Instead, we contract with MPC to provide the necessary personnel, all of whom are directly employed
by MPC or one of its affiliates. Under the terms of an omnibus agreement, described in Item 8. Financial
Statements and Supplementary Data, Note 6 of this report, we pay MPC a fixed amount in return for these
services, including services provided by our NEOs, which totaled approximately $10.3 million for 2019. The
only direct compensation we provide our NEOs is in the form of long-term incentive awards of our equity, which
are shown in the “2019 Grants of Plan-Based Awards” table and accompanying narrative below.
Compensation Decisions
We have adopted the MPLX LP 2018 Incentive Compensation Plan (the “MPLX 2018 Plan”) for the benefit of
eligible officers, employees and directors of our general partner and its affiliates, including MPC, who provide
services to our business. The Compensation and Organization Development Committee of MPC’s board of
directors (“MPC’s Compensation Committee”), currently comprised of five independent directors, recommends
awards under the MPLX 2018 Plan for our NEOs, subject to approval by our Board, which typically considers
such awards on an annual basis. Our Board makes all final determinations with respect to awards under this plan.
All other compensation decisions for our NEOs are made by MPC’s Compensation Committee and are not
subject to approval by our Board or us.
Compensation Allocation
Mr. Heminger, our Chairman, is also CEO and Chairman of MPC, and is generally compensated by MPC
for the services he provides to MPC and its affiliates, including us. Mr. Heminger devotes less than a
majority of his total business time to us, and we reimburse MPC a fixed amount under our omnibus
agreement in return for his services to us. We disclose in this CD&A the amount we reimburse MPC for
Mr. Heminger’s services, as well as the long-term incentive awards we have granted him. Together, these
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represent all of the material elements of Mr. Heminger’s compensation attributable to the services he provides to
our business.
As Ms. Beall and Messrs. Hennigan and Floerke devoted most of their total business time to us in 2019, this
CD&A discloses all components of their compensation. This CD&A discloses all components of
Mr. Swearingen’s compensation, with the non-equity elements generally prorated at 75% to reflect the portion of
his time allocated to us for 2019 under our omnibus agreement, and all components of Ms. Gagle’s
compensation, with the non-equity elements generally prorated at 50% to reflect the portion of her time allocated
to us for 2019 under our omnibus agreement.
Compensation Consultant
Our Board does not have a standing compensation committee and has not hired its own compensation consultant.
MPC’s Compensation Committee has engaged Pay Governance, LLC to provide compensation consulting
services and comparative compensation information. This information is typically shared with our Board for use
in making certain compensation decisions for our NEOs.
EXECUTIVE COMPENSATION PROGRAM
Base Salary
MPC pays our NEOs a base salary for their services to MPC and its affiliates, including us. In setting base salary,
MPC’s Compensation Committee evaluates peer group and other market data, each individual’s experience,
contribution and demonstrated performance, MPC’s current and future succession needs, business results and
external competitiveness. Taking these matters into consideration, MPC’s Compensation Committee made the
following adjustments to our NEOs’ base salaries for 2019:
Name
Hennigan
Beall
Swearingen
Gagle
Floerke
Previous Base
Salary ($)
Base Salary
Effective
Apr. 1, 2019 ($)
Increase (%)
900,000
545,000
393,750
287,500
525,000
950,000
560,000
405,000
312,500
540,000
5.6%
2.8%
2.9%
8.7%
2.9%
The MPC Compensation Committee’s decisions to increase Mr. Hennigan’s and Ms. Gagle’s base salaries in
particular were based on each NEO’s continued strong performance and the MPC Compensation Committee’s
determination to bring each NEO closer to the market median for his or her position. Mr. Hennigan’s base salary
was further increased to $1,050,000 (a 10.5% increase) effective November 1, 2019, in recognition of the
additional responsibilities he assumed upon his appointment as CEO of MPLX effective on that date. The
decisions to increase the base salaries of Ms. Beall, Mr. Swearingen and Mr. Floerke reflect annual merit
program increases to maintain market competitiveness.
As noted above in “Compensation Decisions and Allocation,” the non-equity elements, including base salary, of
Mr. Swearingen’s and Ms. Gagle’s compensation are reflected in this table and in the “2019 Summary
Compensation Table” below at 75% and 50%, respectively, to reflect the portions of their time allocated to us for
2019 under our omnibus agreement.
As noted above in “Compensation Decisions and Allocation,” we reimburse MPC a fixed amount in return for
Mr. Heminger’s services to us. For 2019, this amount was $1,490,000, which is reflected under “Salary” in the
“2019 Summary Compensation Table” below.
Annual Cash Bonus Program
Our NEOs were eligible to participate in MPC’s 2019 Annual Cash Bonus (“ACB”) program, which MPC’s
Compensation Committee approved in February 2019, as part of their compensation for the services they
provide to MPC and its affiliates, including us. MPC determines awards to our NEOs under the ACB program
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without input from our Board or us. Under our omnibus agreement, no portion of any bonus paid to our NEOs
under the ACB is charged back to us. Awards under the ACB program for our NEOs are calculated as follows:
Year-End Base Salary
×
Bonus Target
×
Performance
=
Final Award
Bonus Target is a percentage of each NEO’s base salary. MPC’s Compensation Committee generally approves target bonus
opportunities for our NEOs based on analysis of market-competitive data for MPC’s compensation peer group, while also
taking into consideration each executive’s experience, relative scope of responsibility and potential, other market data, and
any other information MPC’s Compensation Committee deems relevant in its discretion.
Performance metrics are established by MPC’s Compensation Committee at the beginning of the performance year. Once the
performance year has ended, MPC’s Compensation Committee reviews and assesses company performance against the
performance metrics, as well as other factors MPC’s Compensation Committee deems relevant in its discretion, including
each NEO’s organizational and individual performance.
Payout results may be above or below target based on actual company and individual performance
and are capped at 200% of each NEO’s target award.
There is no guaranteed minimum ACB payout.
2019 MPC Company Metrics and Performance
MPC’s Compensation Committee believes it is important for the ACB program to emphasize pre-established
financial and operational (including environmental and safety) performance measures, and has determined to
collectively weight these measures at 70%. The following table provides the goals for each metric, target
weighting and MPC’s performance achieved in 2019 ($ in millions):
Category
Financial
Performance
Metric
Threshold
50%
Payout
Target
100%
Payout
Maximum
200%
Payout
Operating Income Per
Barrel
Synergy Capture
5th or 6th
Position
$240
3rd or 4th
Position
$480
1st or 2nd
Position
$960
Distributable Cash
Flow at MPLX LP
EBITDA
$3,797
$4,219
$4,430
$6,500
$10,800
$12,850
Operational Mechanical
Availability
Marathon Safety
Performance Index
Process Safety Events
Rate
Designated
Environmental
Incidents
Quality Incidents
94.5%
95.5%
96.5%
1.00
0.55
180
0.65
0.37
145
0.40
0.25
110
$0.8
$0.4
$0.2
Result
3rd Position
(100% of target)
$1,404
(200% of target)
$4,100
(85.9% of target)
$10,351
(94.78% of target)
96.7%
(200% of target)
0.67
(97.14% of target)
0.32
(141.67% of target)
85
(200% of target)
$0.055
(200% of target)
Target
Weighting
Performance
Achieved
15%
10%
10%
5%
10%
5%
5%
5%
5%
15%
20%
8.59%
4.74%
20%
4.86%
7.08%
10%
10%
Total
70%
100.27%
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Operating Income per Barrel of crude oil throughput compared to a group of MPC’s peer companies: BP p.l.c.; Chevron
Corporation; Exxon Mobil Corporation; HollyFrontier Corporation; PBF Energy Inc.; Phillips 66; and Valero Energy
Corporation.
Synergy Capture tracks annualized ongoing enhanced revenue or margin, cost savings and avoided planned capital outlays
realized in connection with MPC’s acquisition of Andeavor.
Distributable Cash Flow at MPLX is a non-GAAP measure reflecting cash flow available to be paid to our common
unitholders, as disclosed in our consolidated financial statements. See Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations – Non-GAAP Financial Information for more information about this
non-GAAP measure. This metric also includes distributable cash flow at ANDX, which we acquired by merger effective
July 30, 2019.
EBITDA is a non-GAAP performance metric derived from MPC’s consolidated financial statements. It is calculated as
MPC’s earnings before interest and financing costs, interest income, income taxes, depreciation and amortization expense,
adjusted for certain items, including impairment expenses, inventory market valuation adjustments, effects of acquisitions and
divestitures, and certain other non-cash charges and credits.
Mechanical Availability measures the availability of the processing equipment in MPC’s refineries and the critical
equipment in MPC’s midstream assets.
Marathon Safety Performance Index measures MPC’s success and commitment to employee safety. Goals are set annually
at best-in-class industry performance, focusing on continual improvement and include common industry metrics.
Process Safety Events Rate measures MPC’s ability to identify, understand and control certain process hazards.
Designated Environmental Incidents measures certain internal environmental performance metrics.
Quality Incidents measures the impact of product quality incidents and cumulative costs to MPC.
The performance levels for each metric were established for 2019 by evaluating factors such as performance
achieved in the prior year(s), anticipated challenges for 2019, MPC’s business plan and MPC’s overall strategy. At
the time the performance levels were set, the threshold levels were viewed as likely achievable, the target levels
were viewed as challenging but achievable, and the maximum levels were viewed as extremely difficult to achieve.
The remaining 30% of MPC company performance is evaluated by MPC’s Compensation Committee based upon
a number of discretionary factors, including business results in light of opportunities and challenges encountered
during the year and adjustments due to the volatility in petroleum-related commodity prices throughout the year,
which makes it difficult to establish reliable, pre-determined goals and individual performance achievements.
Key factors considered for 2019 included:
• MPC achieved full-year earnings for 2019 of $2.6 billion.
• MPC’s sustained focus on shareholder returns, with $3.3 billion returned to shareholders through dividends
and share repurchases.
•
•
Successful integration of Andeavor into MPC, with the synergies realized well over first-year target.
Successful merger of ANDX into MPLX.
2019 NEO Individual Performance
In addition to an evaluation of MPC company performance, MPC’s Compensation Committee reviews the
NEOs’ performance, both collectively as a team and individually, in executing MPC’s and our business
objectives. As a team, our NEOs focused on enhancing value for MPC’s shareholders and our unitholders in the
following general categories:
• Enhancement of MPC shareholder and MPLX unitholder value through return of capital and unlocking
midstream asset value.
•
Successful integration of Andeavor and ANDX into MPC and MPLX operations.
• Excellence in environmental, personal safety and process safety improvement.
• Talent development, retention, succession and acquisition.
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•
System integration, optimization and removing bottlenecks.
• Growth through organic expansion and acquisition opportunities.
• Growth of market share for gasoline and diesel.
•
Progress on diversity and inclusion initiatives.
In addition to these areas of general team focus, MPC’s Compensation Committee evaluated our NEOs based
upon their responsibility for certain strategic projects and initiatives and their contribution to the successful
execution of MPC’s and our business objectives.
ACB Payments for 2019
In February 2020, MPC’s Compensation Committee certified the results under the performance metrics for the
2019 ACB program and, taking into consideration MPC’s performance relative to the pre-established metrics, the
key factors discussed above and each NEO’s organizational and individual performance, awarded the following
amounts under the ACB program to our NEOs for 2019:
Name
Hennigan
Beall
Swearingen
Gagle
Floerke
2019 Year-End
Base Salary ($)
Bonus Target
as a % of
Base Salary
1,050,000
560,000
405,000
312,500
540,000
125
70
70
70
70
Target
Bonus ($)
1,112,000 *
392,000
283,500
218,750
378,000
Final Award
as a % of
Target
Final Award
($)
180
172
164
171
164
2,000,000
675,000
465,000
375,000
620,000
* Mr. Hennigan’s Target Bonus amount was adjusted to reflect his change in base salary and bonus target as he
transitioned from his role as our President to service as our President and CEO.
As noted above in “Compensation Decisions and Allocation,” the non-equity elements, including base salary and
ACB payouts, of Mr. Swearingen’s and Ms. Gagle’s compensation are reflected in this table and in the “2019
Summary Compensation Table” below at 75% and 50%, respectively, to reflect the portions of their time
allocated to us for 2019 under our omnibus agreement.
MPLX Long-Term Incentive Compensation Program
Our long-term incentive (“LTI”) compensation program is designed to promote achievement of our long-term
business objectives by linking our NEOs’ compensation directly to long-term company and equity performance,
thereby strengthening alignment between our NEOs’ interests and our unitholders’ interests. Awards to our
NEOs under our LTI program are granted by a committee of our Board comprised of the independent directors
(the “MPLX Committee”) following a recommendation by MPC’s Compensation Committee. For 2019, the
MPLX Committee determined that our NEOs would receive 50% of their MPLX LTI award in the form of
performance units and 50% in the form of phantom units.
MPLX Performance Units align our NEOs’ long-term interests with the long-term interests of our unitholders
by conditioning payout on the performance of our total unitholder return and distributable cash flow relative to
that of our peers over a three-year period.
MPLX Phantom Units promote our NEOs’ ownership of our common units, strengthening alignment between
our NEOs’ interests and the interests of our unitholders, and help them comply with our unit ownership
guidelines.
See the “2019 Grants of Plan-Based Awards” table and accompanying narrative below for more information
about the specific awards granted to our NEOs in 2019.
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2017 MPLX Performance Unit Payouts
The 2017 performance units, awarded in February 2017 to certain of our NEOs as part of our 2017 LTI program,
were based 50% on our total unitholder return (“TUR”) relative to a peer group of midstream companies and
50% on a metric that measures the growth of our distributable cash flow (“DCF”), in each case measured over a
three-year performance cycle. The MPLX Committee believes the relative TUR and DCF metrics are important
indicators of performance as they are commonly used by unitholders to measure a master limited partnership’s
performance against others within the same industry.
TUR Calculation
(Ending Unit Price - Beginning Unit Price) + Cumulative Cash Distributions
Beginning Unit Price
The beginning and ending unit price is the average of each company’s closing unit
price for the 20 trading days immediately preceding each applicable date.
Measurement Periods
First 12 months
Second 12 months
Third 12 months
Entire 36-month period
Andeavor Logistics LP*
Buckeye Partners, L.P.*
Enbridge Energy Partners, L.P.**
Energy Transfer Partners, L.P.**
2017 MPLX Performance Unit Peer Group
Enterprise Products Partners L.P.
Magellan Midstream Partners, L.P.
Phillips 66 Partners LP
Plains All American Pipeline, L.P.
Valero Energy Partners LP*
Western Midstream Operating, LP
Williams Partners L.P.**
*Removed effective January 1, 2019 due to industry consolidation.
**Removed effective January 1, 2018 due to industry consolidation.
Our relative TUR performance percentile was measured for each measurement period, with the payout for
performance between quartiles determined using linear interpolation:
TUR Percentile
Payout (% of Target)
Below 25th*
0%
25th*
50%
50th
100%
100th (Highest)
200%
*Increased to the 30th percentile for awards granted in 2018 and thereafter.
The DCF metric threshold, target and maximum levels were calculated by applying 8%, 10% and 12%
compound annual growth rates, respectively, over the DCF per MPLX common unit at December 31, 2016
($2.35), with the payout for performance between quartiles determined using linear interpolation:
DCF per common unit at 12/31/2019
Payout (% of Target)
Below $2.96
0%
$2.96
50%
$3.12
100%
$3.30
200%
In January 2020, the MPLX Committee certified the final relative TUR and DCF results for the 2017 MPLX
performance units:
TUR Measurement Period
Actual TUR (%)
1/1/2017 - 12/31/2017
1/1/2018 - 12/31/2018
1/1/2019 - 12/31/2019
1/1/2017 - 12/31/2019
17.5
(4.2)
(13.8)
(0.7)
Position
1st of 12
6th of 9
5th of 6
4th of 6
Percentile Ranking
(%)
TUR Payout
Percentage
(% of Target)
100.00
37.50
20.00
40.00
Average:
200.00
75.00
—
80.00
88.75
DCF per common unit at 12/31/2019
DCF Payout Percentage (% of Target)
Below
Threshold
Below $2.96
0%
188
Threshold Target Maximum
Actual DCF
2.96
50%
3.12
100%
3.30
200%
$3.71
200%
Each MPLX performance unit had a target value of $1.00, and the actual payout could vary from $0.00 to $2.00
(0% to 200% of target). The 2017 MPLX performance units final payout percentage was determined by
averaging the TUR payout percentage and the DCF payout percentage. Based on the resulting average, each
MPLX performance unit granted was multiplied by 144.38%, and the MPLX Committee approved the following
payouts to our participating NEOs:
Target Number of MPLX 2017 Performance Units
Payout ($)
1,200,000
1,732,560
340,000
490,892
250,000
360,950
120,000
173,256
320,000
462,016
Heminger
Beall
Swearingen Gagle
Floerke
The 2017 MPLX performance units settled 25% in MPLX common units and 75% in cash. MPLX performance
units granted to our NEOs in 2018 and 2019 remain outstanding. See the “Outstanding Equity Awards at 2019
Fiscal Year-End” table below for additional information about these awards.
MPC Long-Term Incentive Compensation Program
As part of their total equity package, our NEOs also receive LTI awards from MPC. For 2019, MPC’s
Compensation Committee determined that our NEOs would receive 50% of their MPC LTI award in the form of
MPC performance units, 30% in the form of MPC stock options and 20% in the form of MPC restricted stock.
MPC Performance Units align our NEOs’ long-term interests with MPC’s shareholders’ long-term interests by
conditioning payout on the performance of MPC’s total shareholder return relative to that of MPC’s peers over a
three-year period. The percentage shown does not include a special grant in 2019 of additional synergy
performance units intended to promote the capture of synergies following MPC’s acquisition of Andeavor in
October 2018. These awards are discussed in more detail below.
MPC Stock Options drive behaviors and actions that enhance long-term MPC shareholder value and are
inherently performance-based, as MPC’s stock price must increase before the NEO can recognize any benefit.
MPC Restricted Stock/Restricted Stock Units (“RSUs”) promote our NEOs’ ownership of MPC’s common
stock, aid in retention, and help our NEOs comply with MPC’s stock ownership guidelines.
In addition to the annual awards described above, in 2019 MPC’s Compensation Committee made a special grant
of MPC synergy performance units designed to promote the capture of synergies following MPC’s acquisition of
Andeavor in 2018. These awards are discussed in more detail below. See the “2019 Grants of Plan-Based
Awards” table and the accompanying narrative below for more information about the specific awards granted to
our NEOs in 2019.
2017 MPC Performance Unit Payouts
The 2017 MPC performance units, awarded by MPC’s Compensation Committee in February 2017 to certain of
our NEOs as part of MPC’s 2017 LTI program, evaluated MPC’s total shareholder return (“TSR”) relative to a
peer group of petroleum industry competitors and a market index over a 36-month performance cycle. This
relative evaluation recognizes the cyclical nature of MPC’s business and commodity prices and prevents
volatility from directly advantaging or disadvantaging the payout percentage.
189
TSR Calculation
(Ending Stock Price - Beginning Stock Price) + Cumulative Cash Dividends
Beginning Stock Price
Measurement Periods
First 12 months
Second 12 months
The beginning and ending stock price is the average of each company’s closing stock
price for the 20 trading days immediately preceding each applicable date.
Third 12 months
Entire 36-month period
Andeavor*
Chevron Corporation
HollyFrontier Corporation
2017 MPC Performance Unit Peer Group
PBF Energy Inc.
Phillips 66
Valero Energy Corporation
S&P 500 Energy Index
*Removed effective January 1, 2018 due to industry consolidation.
MPC’s relative TSR performance percentile was measured for each measurement period, with the payout for
performance between quartiles determined using linear interpolation:
TSR Percentile
Payout (% of Target)
Below 25th*
0%
25th*
50%
50th
100%
100th (Highest)
200%
*Increased to 30th percentile for awards granted in 2018 and thereafter.
In January 2020, MPC’s Compensation Committee certified the final TSR results for the 2017 MPC performance
units:
TSR Measurement Period
Actual TSR (%)
Position
1/1/2017 - 12/31/2017
1/1/2018 - 12/31/2018
1/1/2019 - 12/31/2019
1/1/2017 - 12/31/2019
34.6
(4.6)
3.2
32.4
3rd of 8
4th of 7
4th of 7
4th of 7
Percentile Ranking
(%)
TSR Payout
Percentage
(% of Target)
71.43
50.00
50.00
50.00
Average:
142.86
100.00
100.00
100.00
110.72
Each MPC performance unit had a target value of $1.00, and the actual payout could vary from $0.00 to $2.00
(0% to 200% of target). Based on the resulting average, each performance unit granted was multiplied by
110.72%, and MPC’s Compensation Committee approved the following payouts to our participating NEOs:
Target Number of 2017 MPC Performance Units
Payout ($)
Beall
Swearingen Gagle
Floerke
68,000
75,290
200,000
221,440
384,000
425,165
64,000
70,861
The 2017 MPC performance units settled 25% in MPC common stock and 75% in cash. MPC performance units
granted to our NEOs in 2018 and 2019 remain outstanding. See the “Outstanding Equity Awards at 2019 Fiscal
Year-End” table below for additional information about these awards.
MPC Synergy Performance Unit Payouts
In January 2019, MPC’s Compensation Committee awarded our NEOs synergy performance units under a new
performance unit incentive program intended to promote MPC’s realization of annual run-rate synergies in
connection with the integration of Andeavor, which MPC acquired October 1, 2018. The MPC synergy
performance units are payable in cash upon the achievement of the following performance targets during each
applicable performance period, with the payout for performance between levels determined using linear
interpolation.
190
October 1, 2018 through
December 31, 2019
Performance Period
January 1, 2020 through
December 31, 2020
January 1, 2021 through
December 31, 2021
Synergy Capture
Performance
$960 million
Payout
Percentage
200%
Synergy Capture
Performance
$1,420 million
Payout
Percentage
200%
Synergy Capture
Performance
$2,000 million
Payout
Percentage
200%
$480 million
$288 million
100%
60%
$710 million
$426 million
100%
60%
$1,000 million
$600 million
100%
60%
$240 million
50%
$355 million
50%
$500 million
50%
Below $288
million
Below $240
million
0%
0%
Below $426
million
Below $355
million
0%
0%
Below $600
million
Below $500
million
0%
0%
Performance
Level
Maximum
Target
Threshold (MPC
CEO)
Threshold (Other
NEOs)
Below threshold
(MPC CEO)
Below threshold
(Other NEOs)
The MPC synergy performance units generally vest and are payable following completion of each performance
period. Earlier vesting may occur in the event of a participant’s death or termination of employment, a change in
control or if the captured synergies reach $2.0 billion prior to the completion of the final performance period.
Each MPC synergy performance unit had a target value of $1.00, and the actual payout could vary from $0.00 to
$2.00 (0% to 200% of target). In February 2020, MPC’s Compensation Committee certified the final synergy
capture performance for the October 1, 2018 through December 31, 2019 performance period at $1,404 million,
which was above the maximum performance level, and approved the following payouts:
Target Number of MPC Synergy Performance Units for 2019
Payout ($)
Hennigan
583,333
1,166,666
Beall
166,666
333,332
Swearingen Gagle
133,333
266,666
125,000
249,999
Floerke
166,666
333,332
As noted above in “Compensation Decisions and Allocation,” the non-equity elements, including the MPC
synergy performance unit payouts, of Mr. Swearingen’s and Ms. Gagle’s compensation are reflected in this table
and in the “2019 Summary Compensation Table” below at 75% and 50%, respectively, to reflect the portions of
their time allocated to us for 2019 under our omnibus agreement.
The MPC synergy performance units for the January 1, 2020 through December 31, 2020 and January 1, 2021
through December 31, 2021 performance periods remain outstanding. See the “Outstanding Equity Awards at
2019 Fiscal Year-End” table below for additional information about these awards.
OTHER BENEFITS
We do not sponsor any benefit plans, programs or policies such as healthcare, life insurance, income protection
or retirement benefits for our NEOs, and we do not provide perquisites. However, those types of benefits are
generally provided to our NEOs by MPC. MPC makes all determinations with respect to such benefits without
input from our Board or us. MPC bears the full cost of these programs, and no portion is charged back to us. We
have summarized the material elements of these programs below.
Retirement Benefits
Retirement benefits provided to our NEOs are designed by MPC to be consistent in value and aligned with
benefits offered by the other companies with which MPC competes for talent. Benefits under MPC’s qualified
and nonqualified plans are described in more detail in “Post-Employment Benefits for 2019” and “2019
Nonqualified Deferred Compensation.”
Severance Benefits
We and MPC maintain change in control plans designed to (i) preserve executives’ economic motivation to
consider a business combination that might result in job loss and (ii) compete effectively in attracting and
retaining executives in an industry that features frequent mergers, acquisitions and divestitures. Our change in
control benefits are described further in “Potential Payments upon Termination or Change in Control.”
191
Perquisites
Our NEOs receive limited perquisites, which are consistent with those offered by MPC’s peer group companies.
Tax and Financial Planning Services
MPC generally reimburses our NEOs for certain tax, estate and financial planning services up to $15,000 per year while
serving as an executive officer and $3,000 in the year following retirement or death.
Health and Well-being
Under MPC’s enhanced annual physical health program, our senior management, including our NEOs, are eligible for a
comprehensive physical (generally in the form of a one-day appointment), with procedures similar to those available to all
other employees under MPC’s health program.
Reportable values for these perquisite programs, based on the incremental costs to MPC, are included in the “All
Other Compensation” column of the “2019 Summary Compensation Table.”
COMPENSATION GOVERNANCE
Unit Ownership Guidelines
Our unit ownership guidelines align our executive officers’ long-term interests with those of our unitholders.
These guidelines require the executive officers in the positions shown below to hold a specified level of MPLX
common units. The targeted levels vary depending upon the executive’s position and responsibilities:
Position
Chairman of the Board
President and Chief Executive Officer
Executive Vice Presidents
General Counsel
Senior Vice Presidents
Vice Presidents
Number of Units to Be Held
25,000
25,000
15,000
10,000
10,000
5,000
Each executive is expected to meet these guidelines within five years of his or her assumption of the applicable
position. The guidelines also require that these officers hold all common units distributed in settlement of
phantom units or performance units for a minimum of one year following the vesting date. Compliance with
these guidelines is assessed annually. As of the most recent assessment in February 2020, all of our NEOs had
met their unit ownership guidelines.
Prohibition on Derivatives and Hedging
Under our policy on trading of securities, none of our directors, officers, including our NEOs, or certain MPC
employees designated under the policy may purchase or sell any financial instrument, including but not limited to
put or call options, the price of which is affected in whole or in part by changes in the price of our securities,
unless such financial instrument was issued by us to such director, officer or covered employee. Further, no
director, officer or covered employee may participate in any hedging transaction related to our securities. This
policy ensures that our directors, officers and covered employees bear the full risk of MPLX common unit
ownership.
192
Recoupment/Clawback Policy
MPC’s ACB and LTI programs provide for recoupment in the case of certain forfeiture events. In addition, our
incentive compensation plans provide that all awards granted thereunder will be subject to clawback or
recoupment in the case of certain forfeiture events. If the SEC or our Audit Committee requires us to prepare a
material accounting restatement due to noncompliance with any financial reporting requirement under applicable
securities laws as a result of misconduct, the Audit Committee may determine that a forfeiture event has occurred
based on an assessment of whether an executive officer: (i) knowingly engaged in misconduct; (ii) was grossly
negligent with respect to misconduct; (iii) knowingly failed or was grossly negligent in failing to prevent
misconduct; or (iv) engaged in fraud, embezzlement or other similar misconduct materially harmful to us.
If it is determined that a forfeiture event has occurred, an executive officer’s unvested phantom units and
performance units would be subject to immediate forfeiture. If a forfeiture event occurred either while the
executive officer was employed, or within three years after termination of employment, and the executive officer
has received any payment in settlement of performance units, we may recoup an amount in cash or units up to the
amount paid in settlement of the performance units.
These recoupment provisions are in addition to any clawback provisions under Section 304 of the Sarbanes-
Oxley Act of 2002, the Dodd-Frank Wall Street Reform and Consumer Protection Act, NYSE listing standards
and other applicable law.
Compensation-Based Risk Assessment
Our Chairman and the independent directors of our Board review our policies and practices in compensating our
service providers (including both executive officers and non-executives, if any) as they relate to our risk
management profile. Our Chairman and the independent directors of our Board completed their review of our
2019 programs in February 2020, and concluded that any risks arising from our compensation policies and
practices were not reasonably likely to have a material adverse effect on our financial statements.
Compensation Committee Interlocks and Insider Participation
Compensation matters are determined by Mr. Heminger, our Chairman, and the independent directors of our
Board. See “Director Independence” in Item 10. Directors, Executive Officers and Corporate Governance for
more information about our independent directors. Mr. Heminger is also an executive officer and director of
MPC. During 2019, none of our other executive officers served as a member of a compensation committee or
board of directors of another entity that has an executive officer serving as a member of our Board.
COMPENSATION COMMITTEE REPORT
Our Chairman and independent directors have reviewed and discussed the Executive Compensation Discussion
and Analysis for 2019 with management and, based on such review and discussions, recommended to the Board
that the Executive Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for
the year ended December 31, 2019.
Gary R. Heminger, Chairman
Michael L. Beatty
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
J. Michael Stice
John P. Surma
193
EXECUTIVE COMPENSATION TABLES
2019 SUMMARY COMPENSATION TABLE
The following table provides information regarding compensation for our 2019 NEOs for the years shown:
Name and
Principal
Position
Salary
($)
Bonus
($)
Year
Stock
Awards
($)
Option
Awards
($)
Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings
Non-Equity
Incentive
Plan
Compensation
All Other
Compensation
($)
($)
($)
Total
($)
Gary R. Heminger 2019 1,490,000
— 2,112,700
Chairman
2018 1,350,000
— 1,512,459
2017 1,310,000
— 2,282,185
—
—
—
—
—
—
—
—
—
— 3,602,700
— 2,862,459
— 3,592,185
Michael J.
Hennigan
President and Chief
Executive Officer
MPLX
2019
954,167
— 2,215,393 888,005
3,166,666
245,801
186,835
7,656,867
2018
875,000
— 1,949,566 525,008
1,600,000
152,366
161,740
5,263,680
2017
429,589 1,000,000 5,000,052
— 800,000
126,322
157,086
7,513,049
Pamela K.M. Beall 2019
556,250
— 598,772 240,009
1,008,332
197,733
98,844
2,699,940
Executive Vice
President and Chief
Financial Officer
John S.
Swearingen
Executive Vice
President, Logistics
and Storage
2018
540,000
— 557,058 150,007
670,000
178,266
96,657
2,191,988
2017
525,000
— 743,215
68,010
670,000
245,643
88,828
2,340,696
2019
402,188
— 598,772 240,009
714,999
783,720
63,084
2,802,772
2018
389,063
— 557,058 150,007
457,500
—
61,608
1,615,236
Suzanne Gagle
2019
306,250
— 1,077,758 432,007
641,666
218,049
61,176
2,736,906
General Counsel
Gregory S. Floerke 2019
536,250
— 598,772 240,009
953,332
125,985
87,453
2,541,801
Executive Vice
President, Gathering
and Processing
2018
506,250
— 557,058 150,007
610,000
93,153
84,350
2,000,818
2017
442,500
— 699,511
64,009
600,000
78,750
67,633
1,952,403
Salary shows the actual amount earned during the year. With respect to Mr. Heminger, amounts reflect the
annualized fixed fee we pay MPC for his services under an omnibus agreement. With respect to Mr. Swearingen
and Ms. Gagle, amounts are shown at 75% and 50%, respectively, to reflect the portions of their time allocated to
us under our omnibus agreement for each applicable year. With respect to the other NEOs, amounts reflect actual
salary earned during each applicable year. Compensation is reviewed after the end of each year, and salary
increases, if any, are generally effective April 1 of the following year. See the base salary overview in the CD&A
for additional information on base salaries for 2019.
Stock Awards and Option Awards reflect the aggregate grant date fair value of LTI awarded in the
applicable year calculated in accordance with Financial Accounting Standards Board Accounting Standards
Codification 718, Compensation—Stock Compensation (“FASB ASC Topic 718”). See Item 8. Financial
Statements and Supplementary Data, Note 21 of this report and Note 24 to MPC’s financial statements
194
included in its Annual Report on Form 10-K for the year ended December 31, 2019 for assumptions used to
determine the values of these awards.
Performance Units granted in 2019 are included in the Stock Awards column for 2019. Their maximum value,
assuming the highest level of performance achieved, is:
MPLX Performance Units ($)
MPC Performance Units ($)
2,800,000
740,000
— 2,960,000
200,000
800,000
200,000
800,000
360,000
1,440,000
200,000
800,000
Heminger Hennigan
Beall
Swearingen
Gagle
Floerke
Non-Equity Incentive Plan Compensation reflects the total ACB award earned for the year indicated, paid the
following year. Amounts for 2019 also include payouts under the synergy performance units for the performance
period from October 1, 2018 through December 31, 2019. ACB and synergy performance unit amounts for
Mr. Swearingen and Ms. Gagle reflect 75% and 50%, respectively, of the total value of their awards to reflect the
portions of their time allocated to us under the omnibus agreement.
Change in Pension Value and Nonqualified Deferred Compensation Earnings reflects the annual change in
actuarial present value of accumulated benefits under the MPC retirement plans. See “Post-Employment Benefits
for 2019” for more information about the defined benefit plans and the assumptions used to calculate these
amounts. No deferred compensation earnings are reported as our nonqualified deferred compensation plans do
not provide above-market or preferential earnings. For Mr. Swearingen and Ms. Gagle, these amounts are shown
at 75% and 50%, respectively, to reflect the portions of their time allocated to us under the omnibus agreement.
All Other Compensation aggregates contributions to defined contribution plans and the limited perquisites
MPC offers to our NEOs, which are described in more detail in the perquisites overview in the CD&A.
Name
Heminger
Hennigan
Beall
Swearingen
Gagle
Floerke
Company
Physicals ($)
Tax and
Financial
Planning ($)
Company Contributions
to Defined Contribution
Plans ($)
Other ($)
Total All Other
Compensation ($)
—
3,827
3,827
3,827
3,827
3,827
—
—
8,975
—
11,347
3,200
—
178,835
86,042
59,257
46,002
80,426
—
4,173
—
—
—
—
—
186,835
98,844
63,084
61,176
87,453
Company Contributions to Defined Contribution Plans reflect MPC’s contributions under our tax-qualified
retirement plans and related nonqualified deferred compensation plans. For Mr. Swearingen and Ms. Gagle, these
amounts are shown at 75% and 50%, respectively, to reflect the portions of their time allocated to us for 2019
under the omnibus agreement. See “Post-Employment Benefits for 2019” and “2019 Nonqualified Deferred
Compensation” for more information.
Other reflects reimbursement for the following amounts in connection with Mr. Hennigan’s 2017 move to our
headquarters in Findlay, Ohio: $2,323 in reimbursement for relocation expenses and $1,851 in reimbursement for
taxes due on the relocation reimbursement. The 2018 amount in the Summary Compensation Table for
Mr. Hennigan includes $10,000 in reimbursement for relocation expenses and $7,968 in reimbursement for taxes
due on the relocation reimbursement that were not previously reported in our Annual Report on Form 10-K for
the year ended December 31, 2018.
195
2019 GRANTS OF PLAN-BASED AWARDS
The following table provides information regarding all MPLX plan-based awards granted by the MPLX
Committee to our NEOs in 2019, as well as all MPC plan-based awards, including cash-based incentive awards
and equity-based awards, granted by MPC’s Compensation Committee to our NEOs in 2019.
Estimated Future Payouts
Under Non-Equity Incentive
Plan Awards
Estimated Future Payouts
Under Equity Incentive Plan
Awards
Type of Award
Grant
Date
Threshold
($)
Target
($)
Maximum
($)
Threshold
($)
Target
($)
Maximum
($)
All
Other
Stock
Awards:
Number
of
Shares
of Stock
or Units
(#)
42,195
11,152
9,445
3,014
2,553
3,014
2,553
5,425
4,595
3,014
2,553
All Other
Option
Awards:
Number of
Securities
Underlying
Options
(#)
Exercise
or Base
Price of
Option
Awards
($/Sh)
Grant
Date Fair
Value of
Stock and
Option
Awards
($)
1,400,030
712,670
370,023
188,349
61,925
62.68
888,005
592,013
1,065,008
100,005
50,905
16,737
62.68
240,009
160,022
287,840
100,005
50,905
16,737
62.68
240,009
160,022
287,840
180,002
91,629
30,126
62.68
432,007
288,015
518,112
100,005
50,905
240,009
160,022
287,840
16,737
62.68
87,500 1,400,000 2,800,000
23,125
370,000
740,000
185,000 1,480,000 2,960,000
6,250
100,000
200,000
50,000
400,000
800,000
6,250
100,000
200,000
50,000
400,000
800,000
11,250
180,000
360,000
90,000
720,000 1,440,000
6,250
100,000
200,000
50,000
400,000
800,000
Name
Heminger
Hennigan
MPLX Phantom Units 3/1/2019
MPLX Performance Units 3/1/2019
MPLX Phantom Units 3/1/2019
MPLX Performance Units 3/1/2019
MPC Stock Options 3/1/2019
MPC Restricted Stock 3/1/2019
MPC Performance Units 3/1/2019
MPC Synergy Performance Units 2/1/2019
MPC Annual Cash Bonus
—
—
1,750,000 3,500,000
1,112,000 2,224,000
Beall
MPLX Phantom Units 3/1/2019
MPLX Performance Units 3/1/2019
MPC Stock Options 3/1/2019
MPC Restricted Stock 3/1/2019
MPC Performance Units 3/1/2019
MPC Synergy Performance Units 2/1/2019
MPC Annual Cash Bonus
Swearingen
—
—
500,000 1,000,000
392,000
784,000
MPLX Phantom Units 3/1/2019
MPLX Performance Units 3/1/2019
MPC Stock Options 3/1/2019
MPC Restricted Stock 3/1/2019
MPC Performance Units 3/1/2019
MPC Synergy Performance Units 2/1/2019
MPC Annual Cash Bonus
—
—
375,000
750,000
283,500
567,000
Gagle
MPLX Phantom Units 3/1/2019
MPLX Performance Units 3/1/2019
MPC Stock Options 3/1/2019
MPC Restricted Stock 3/1/2019
MPC Performance Units 3/1/2019
MPC Synergy Performance Units 2/1/2019
MPC Annual Cash Bonus
—
—
400,000
800,000
218,750
437,500
Floerke
MPLX Phantom Units 3/1/2019
MPLX Performance Units 3/1/2019
MPC Stock Options 3/1/2019
MPC Restricted Stock 3/1/2019
MPC Performance Units 3/1/2019
MPC Synergy Performance Units 2/1/2019
MPC Annual Cash Bonus
—
—
500,000 1,000,000
378,000
756,000
196
Approval Dates. The MPC awards granted on February 1, 2019 and March 1, 2019 were approved by MPC’s
Compensation Committee on January 26, 2019 and February 26, 2019, respectively. The MPLX awards granted
on March 1, 2019 were approved by the MPLX Committee on February 27, 2019.
MPC Stock Options generally vest in equal installments on the first, second and third anniversaries of the grant
date and expire 10 years after the grant date. The exercise price is generally equal to the closing price of MPC’s
common stock on the grant date. Option holders do not have voting rights or receive dividends on the underlying
stock.
MPC Restricted Stock generally vests in equal installments on the first, second and third anniversaries of the
grant date. Unvested restricted stock awards accrue dividends, which are paid on the scheduled vesting dates.
Holders of unvested restricted stock have voting rights.
MPC Performance Units generally vest following a 36-month performance period and are settled 25% in MPC
common stock and 75% in cash. Unvested performance units do not receive dividends and do not have voting
rights. The target amounts shown reflect the number of performance units granted, each of which has a target
value of $1.00. The threshold, which is the minimum possible payout, is achieved when the payout percentage is
50% for one TSR measurement period and 0% for the other three TSR measurement periods, resulting in an
average payout percentage of 12.5%. The maximum payout is 200% of target.
MPC Synergy Performance Units vest upon completion of each performance period and are settled in cash.
Earlier vesting may occur in the event of a participant’s death or termination of employment, a change in control,
or if the captured synergies reach $2.0 billion prior to the completion of the final performance period. The
performance periods are described in our CD&A. The target amounts shown reflect the number of performance
units granted, at $1.00 per unit. No threshold amount is disclosed as MPC’s Compensation Committee has
discretion to award nothing under the synergy performance units. The maximum payout is 200% of target.
MPLX Phantom Units generally vest in equal installments on the first, second and third anniversaries of the
grant date and are settled in MPLX common units. Distribution equivalents accrue on the phantom unit awards
and are paid on the scheduled vesting dates. Holders of unvested phantom units have no voting rights.
MPLX Performance Units generally vest following a 36-month performance period and are settled 25% in
MPLX common units and 75% in cash. Unvested performance units do not receive cash distributions or have
voting rights. The target amounts shown reflect the number of performance units granted, each of which has a
target value of $1.00. The threshold, which is the minimum possible payout, is achieved when the payout
percentage is 0% for the DCF metric, 50% for one TUR measurement period and 0% for the other three TUR
measurement periods, resulting in an average payout percentage of 6.25%. The maximum payout is 200% of
target.
Modified Vesting Dates. To promote the retention of Messrs. Hennigan, Swearingen and Floerke and Mses.
Beall and Gagle, their award agreements for MPC stock options, MPC restricted stock, MPC performance units,
MPLX phantom units and MPLX performance units granted in 2017, 2018 and 2019 were amended such that any
such unvested awards now become non-forfeitable on the earlier of December 31, 2020 or the date of such
executive’s involuntary termination by MPC.
Grant Date Fair Value reflects the total grant date fair value of each equity award calculated in accordance with
FASB ASC Topic 718, as discussed further in Note 21 to our financial statements included in Item 8. Financial
Statements and Supplementary Data and in Note 24 to MPC’s financial statements included in its Annual Report
on Form 10-K for the year ended December 31, 2019. The Black-Scholes value used for the MPC stock options
was $14.34 per share. The MPC restricted stock value was based on the MPC common stock closing price of
$62.68 on the grant date. The MPC performance units have a grant date fair value of $0.7196 per unit, using a
Monte Carlo valuation model. The MPLX phantom unit value was based on the MPLX common unit closing
price of $33.18 on the grant date. The portion (50%) of the MPLX performance units attributable to the TUR
metric has a grant date fair value of $0.6848 per unit using a Monte Carlo valuation model, and the portion (50%)
attributable to the DCF metric has grant date fair values of $1.00, $0.00 and $0.00 for the respective 2019, 2020
and 2021 performance years.
197
OUTSTANDING EQUITY AWARDS AT 2019 FISCAL YEAR-END
The following table provides information regarding the outstanding equity awards held by our NEOs as of
December 31, 2019.
Option Awards
Stock Awards
Name
Heminger
Hennigan
Beall
Swearingen
Gagle
Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable
Number of
Securities
Underlying
Unexercised
Options (#)
Unexercis-
able
Option
Exercise
Price
($)
Option
Expiration
Date
Equity
Incentive
Plan Awards:
Number of
Unearned
Shares, Units
or Other
Rights that
Have Not
Vested (#)
Equity
Incentive Plan
Awards:
Market or
Payout Value
of Unearned
Shares, Units
or Other
Rights that
Have Not
Vested ($)
Number
of Shares
or Units
of Stock
That
Have Not
Vested
(#)
MPLX
Market
Value of
Shares or
Units of
Stock That
Have Not
Vested ($)
77,852 1,982,112 2,750,000
5,500,000
10,075
20,150 64.79
3/1/2028 MPLX
—
61,925 62.68
3/1/2029
113,543 2,890,805 1,245,000
2,490,000
10,075
82,075
MPC
26,858 1,618,195 2,355,000
4,710,000
21,874
20,150
17,052
3,184
2,878
—
65,138
40,750
33,614
16,610
17,372
20,150
32,097
9,363
2,878
—
— 41.69
3/1/2024
— 50.89
3/1/2025
— 34.63
3/1/2026
1,592 50.99
3/1/2027 MPLX
5,758 64.79
3/1/2028
10,773
274,281
350,000
700,000
16,737 62.68
3/1/2029 MPC
24,087
3,806
229,312
650,000
1,300,000
— 22.36 5/25/2021
— 20.78
3/1/2022
— 41.37 2/27/2023
— 41.69
3/1/2024
— 50.89
3/1/2025
— 34.63
3/1/2026
4,682 50.99
3/1/2027 MPLX
5,758 64.79
3/1/2028
9,984
254,193
350,000
700,000
16,737 62.68
3/1/2029 MPC
172,834
27,177
4,237
255,279
650,000
1,300,000
8,080
1,310
4,210
2,370
3,006
4,120
25,678
17,978
4,605
— 22.36 5/25/2021
— 17.20 12/5/2021
— 21.72
4/2/2022
— 44.92
4/1/2023
— 44.77
4/1/2024
— 50.88
4/1/2025
— 34.63
3/1/2026
8,989 50.99
3/1/2027 MPLX
9,212 64.79
3/1/2028
14,122
359,546
580,000
1,160,000
—
30,126 62.68
3/1/2029 MPC
71,357
48,327
7,498
451,755 1,120,000
2,240,000
198
Grant
Date
3/1/2018
3/1/2019
3/1/2014
3/1/2015
3/1/2016
3/1/2017
3/1/2018
3/1/2019
5/25/2011
2/29/2012
2/27/2013
3/1/2014
3/1/2015
3/1/2016
3/1/2017
3/1/2018
3/1/2019
5/25/2011
12/5/2011
4/2/2012
4/1/2013
4/1/2014
4/1/2015
3/1/2016
3/1/2017
3/1/2018
3/1/2019
Name
Floerke
Option Awards
Stock Awards
Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable
Number of
Securities
Underlying
Unexercised
Options (#)
Unexercis-
able
Option
Exercise
Price
($)
Option
Expiration
Date
Number
of Shares
or Units
of Stock
That
Have Not
Vested
(#)
Market
Value of
Shares or
Units of
Stock That
Have Not
Vested ($)
Equity
Incentive
Plan Awards:
Number of
Unearned
Shares, Units
or Other
Rights that
Have Not
Vested (#)
Equity
Incentive Plan
Awards:
Market or
Payout Value
of Unearned
Shares, Units
or Other
Rights that
Have Not
Vested ($)
2,996
2,878
1,499
5,758
—
16,737
50.99
64.79
62.68
3/1/2027 MPLX
3/1/2028
47,074 1,198,504
350,000
700,000
3/1/2029 MPC
5,874
23,994
3,793
228,528
650,000
1,300,000
Grant
Date
3/1/2017
3/1/2018
3/1/2019
MPC Stock Options generally vest in equal installments on the first, second and third anniversaries of the grant
date and expire 10 years after the grant date; however, to promote the retention of Messrs. Hennigan, Swearingen
and Floerke and Mses. Beall and Gagle, their award agreements for the 2017, 2018 and 2019 MPC stock options
shown in this table were amended such that any such unvested awards now become non-forfeitable on the earlier
of December 31, 2020 or the date of such executive’s involuntary termination by MPC. The stock option exercise
price is generally equal to the closing price of MPC’s common stock on the grant date. Option holders do not
have voting rights or receive dividends on the underlying stock.
Unvested Shares and Units reflect the number of unvested MPLX phantom units and shares of MPC restricted
stock held on December 31, 2019. Phantom units and restricted stock generally vest in one-third increments on
the first, second and third anniversaries of the grant date; however to promote the retention of Messrs. Hennigan,
Swearingen and Floerke and Mses. Beall and Gagle, their award agreements for the 2017, 2018 and 2019 MPLX
phantom units and MPC restricted stock awards shown in the following table were amended such that any such
unvested awards now become non-forfeitable on the earlier of December 31, 2020 or the date of such executive’s
involuntary termination by MPC. The table below reflects the original vesting dates of these awards as they
remain subject to distribution on their original vesting dates.
MPLX LP Phantom Units
MPC Restricted Stock
Name
Heminger
Hennigan
Beall
Swearingen
Grant Date
3/1/2017
3/1/2018
12/20/2018
3/1/2019
7/1/2017
7/1/2017
3/1/2018
3/1/2019
3/1/2017
3/1/2018
3/1/2019
3/1/2017
3/1/2018
3/1/2019
Number
of
Unvested
Units
10,098
24,759
2,496
40,499
77,852
15,577
70,094
16,720
11,152
113,543
2,981
4,778
3,014
10,773
2,192
4,778
3,014
9,984
Vesting Dates
Grant Date
3/1/2020
3/1/2020, 3/1/2021
3/1/2020, 3/1/2021
3/1/2020, 3/1/2021, 3/1/2022
7/1/2020
7/1/2020
3/1/2020, 3/1/2021
3/1/2020, 3/1/2021, 3/1/2022
7/1/2017
7/1/2017
3/1/2018
3/1/2019
3/1/2020
3/1/2020, 3/1/2021
3/1/2020, 3/1/2021, 3/1/2022
3/1/2017
3/1/2018
3/1/2019
3/1/2020
3/1/2020, 3/1/2021
3/1/2020, 3/1/2021, 3/1/2022
3/1/2017
3/1/2018
3/1/2019
199
Number
of
Unvested
Shares
Vesting Dates
7/1/2020
7/1/2020
3/1/2020, 3/1/2021
3/1/2020, 3/1/2021, 3/1/2022
3/1/2020
3/1/2020, 3/1/2021
3/1/2020, 3/1/2021, 3/1/2022
3/1/2020
3/1/2020, 3/1/2021
3/1/2020, 3/1/2021, 3/1/2022
2,511
11,300
3,602
9,445
26,858
223
1,030
2,553
3,806
654
1,030
2,553
4,237
Name
Gagle
Floerke
MPLX LP Phantom Units
MPC Restricted Stock
Grant Date
3/1/2017
3/1/2018
3/1/2019
12/18/2015
3/1/2017
3/1/2018
3/1/2019
Number
of
Unvested
Units
1,053
7,644
5,425
14,122
36,476
2,806
4,778
3,014
47,074
Vesting Dates
3/1/2020
3/1/2020, 3/1/2021
3/1/2020, 3/1/2021, 3/1/2022
Grant Date
3/1/2017
3/1/2018
3/1/2019
Upon termination without cause
3/1/2020
3/1/2020, 3/1/2021
3/1/2020, 3/1/2021, 3/1/2022
3/1/2017
3/1/2018
3/1/2019
Number
of
Unvested
Shares
1,256
1,647
4,595
7,498
210
1,030
2,553
3,793
Vesting Dates
3/1/2020
3/1/2020, 3/1/2021
3/1/2020, 3/1/2021, 3/1/2022
3/1/2020
3/1/2020, 3/1/2021
3/1/2020, 3/1/2021, 3/1/2022
MPLX phantom unit and MPC restricted stock awards generally provide for full vesting upon termination of
employment due to our general policy that our officers retire on the first day of the month after they reach age
65. Mr. Heminger became eligible for such retirement on October 1, 2018. Under applicable tax rules, this
retirement eligibility caused him to “vest” in his phantom unit awards for payroll tax purposes, and in his MPC
restricted stock awards for income tax and payroll tax (e.g., FICA taxes) purposes, notwithstanding that he
continues to be employed, because there is no longer any substantial risk of forfeiture for these awards. While
these awards continue to be reflected in this table, the portion used to pay the associated taxes has been excluded
from this table, and is instead included in the “Option Exercises and Units Vested in 2019” table below.
Market Value of Unvested Shares reflects the aggregate value of all unvested MPLX phantom units and MPC
restricted stock held on December 31, 2019, using the MPLX closing unit price of $25.46 and the MPC closing
stock price of $60.25 on that date.
Unvested Equity Incentive Plan Awards reflect the number of unvested MPLX performance units and MPC
performance units held on December 31, 2019.
Name
Heminger
Hennigan
Beall
Swearingen
Gagle
Grant Date
3/1/2018
3/1/2019
3/1/2018
3/1/2019
3/1/2018
3/1/2019
3/1/2018
3/1/2019
3/1/2018
3/1/2019
MPLX Performance Units
MPC Performance Units
Number of
Unvested Units
Performance Cycle
Grant Date
Number of
Unvested Units
Performance Cycle
1,350,000
1,400,000
1/1/2018 - 12/31/2020
1/1/2019 - 12/31/2021
2,750,000
875,000
370,000
1/1/2018 - 12/31/2020
1/1/2019 - 12/31/2021
3/1/2018
3/1/2019
875,000
1,480,000
1/1/2018 - 12/31/2020
1/1/2019 - 12/31/2021
1,245,000
250,000
100,000
350,000
250,000
100,000
350,000
400,000
180,000
580,000
1/1/2018 - 12/31/2020
1/1/2019 - 12/31/2021
3/1/2018
3/1/2019
1/1/2018 - 12/31/2020
1/1/2019 - 12/31/2021
3/1/2018
3/1/2019
2,355,000
250,000
400,000
650,000
250,000
400,000
650,000
1/1/2018 - 12/31/2020
1/1/2019 - 12/31/2021
1/1/2018 - 12/31/2020
1/1/2019 - 12/31/2021
1/1/2018 - 12/31/2020
1/1/2019 - 12/31/2021
3/1/2018
3/1/2019
400,000
720,000
1/1/2018 - 12/31/2020
1/1/2019 - 12/31/2021
1,120,000
200
Name
Floerke
MPLX Performance Units
MPC Performance Units
Grant Date
3/1/2018
3/1/2019
Number of
Unvested Units
250,000
100,000
350,000
Performance Cycle
Grant Date
1/1/2018 - 12/31/2020
1/1/2019 - 12/31/2021
3/1/2018
3/1/2019
Number of
Unvested Units
250,000
400,000
650,000
Performance Cycle
1/1/2018 - 12/31/2020
1/1/2019 - 12/31/2021
The MPLX performance units awarded in 2018 and 2019 have a 36-month performance cycle and settle 25% in
MPLX common units and 75% in cash. Each performance unit has a target value of $1.00. Payout may vary from
$0.00 to $2.00 per unit. Fifty percent of the payout will be determined based on MPLX’s TUR as compared to
the applicable peer group, which for 2018 and 2019 was: Andeavor Logistics LP (removed effective January 1,
2019), Buckeye Partners, L.P. (removed effective January 1, 2019), Enterprise Products Partners LP, Magellan
Midstream Partners, L.P., Phillips 66 Partners LP, Plains All American Pipeline, L.P., Valero Energy Partners LP
(removed effective January 1, 2019), and Western Midstream Operating, LP. The other 50% is based on a
DCF-per-MPLX-common-unit metric, which measures the growth of MPLX’s full-year DCF over the 36-month
performance cycle. Performance units generally vest following a 36-month performance period; however, to
promote the retention of Messrs. Hennigan, Floerke and Swearingen and Mses. Beall and Gagle, their award
agreements for the 2018 and 2019 MPLX performance units shown in the table were amended such that any such
unvested awards now become non-forfeitable on the earlier of December 31, 2020 or the date of such executive’s
involuntary termination by MPC. The performance cycles for these awards remain unchanged.
The MPC performance units awarded in March 2018 and 2019 have 36-month performance cycles and settle
25% in MPC common stock and 75% in cash. Each performance unit has a target value of $1.00. Payout may
vary from $0.00 to $2.00 per unit and is tied to MPC’s TSR as compared to the applicable peer group. The 2018
peer group was: Andeavor (removed effective January 1, 2018), Chevron Corporation, HollyFrontier
Corporation, PBF Energy, Phillips 66, Valero Energy Corporation and the S&P 500 Energy Index. The 2019
performance unit peer group added BP p.l.c. and Exxon Mobil Corporation. Performance units generally vest
following a 36-month performance period; however, to promote the retention of Messrs. Hennigan, Swearingen
and Floerke and Mses. Beall and Gagle, their award agreements for the 2018 and 2019 MPC performance units
shown in the table were amended such that any such unvested awards now become non-forfeitable on the earlier
of December 31, 2020 or the date of such executive’s involuntary termination by MPC. The performance cycles
for these awards remain unchanged.
Market Value of Unvested Equity Incentive Plan Awards. Amounts shown for MPLX reflect the aggregate
value of all MPLX performance units held on December 31, 2019, assuming payouts of 200.00% and 200.00%
per unit for the 2018 and 2019 awards, respectively, which is the next higher performance achievement that
exceeds the performance for these awards’ measurement period ended December 31, 2019. Amounts shown for
MPC reflect the aggregate value of all MPC performance units held on December 31, 2019, assuming payouts of
200.00% and 200.00% per unit for the 2018 and 2019 awards, respectively, which is the next higher performance
achievement that exceeds the performance for these awards’ measurement period ended December 31, 2019.
OPTION EXERCISES AND UNITS VESTED IN 2019
The following table provides information regarding MPC stock options exercised by our NEOs in 2019, as well
as MPLX phantom units, MPLX performance units, MPC restricted stock and MPC performance units that
vested in 2019.
201
Name
Heminger
Hennigan
Beall
Swearingen
Gagle
Floerke
MPLX
MPLX
MPC
MPLX
MPC
MPLX
MPC
MPLX
MPC
MPLX
MPC
Option Awards
Stock Awards
Number of Shares
Acquired on
Exercise (#)
Value Realized on
Exercise ($)
Number of Units/
Shares Acquired
on Vesting (#)
—
—
—
—
—
—
—
—
18,302
451,565
—
—
—
—
—
—
—
—
—
—
—
—
39,998
23,935
4,312
8,039
1,555
5,837
2,709
5,879
3,311
5,194
723
Value Realized on
Vesting ($)
1,329,534
780,958
253,592
267,216
97,436
194,022
169,746
195,418
207,467
172,649
45,303
Value Realized on Exercise reflects the actual pre-tax gain realized by our NEOs upon exercise of stock
options, which is the fair market value of the shares at exercise less the per share grant price.
Number of Shares Acquired on Vesting for Mr. Heminger include 1,696 MPLX phantom units used to pay the
taxes associated with the vesting of certain awards due to his retirement eligibility, as discussed further under
“Outstanding Equity Awards at 2019 Fiscal Year-End.”
Value Realized on Vesting reflects the actual pre-tax gain realized upon vesting of MPLX phantom units,
MPLX performance units, MPC restricted stock and MPC performance units, which is the fair market value of
the units/shares on the vesting date.
POST-EMPLOYMENT BENEFITS FOR 2019
2019 Pension Benefits
MPC provides tax-qualified retirement benefits to its employees, including our NEOs, under the MPC
Retirement Plan. In addition, MPC sponsors the MPC Excess Benefit Plan for the benefit of a select group of
management or highly compensated employees.
The following table reflects the actuarial present value of accumulated benefits payable to our NEOs under the
MPC Retirement Plan and the defined benefit portion of the MPC Excess Benefit Plan as of December 31, 2019.
These values have been determined using actuarial assumptions consistent with those used in MPC’s financial
statements.
202
Name
Hennigan
Plan Name
MPC Retirement Plan
MPC Excess Benefit Plan
Beall
MPC Retirement Plan
MPC Excess Benefit Plan
Swearingen
MPC Retirement Plan
MPC Excess Benefit Plan
Gagle
MPC Retirement Plan
MPC Excess Benefit Plan
Floerke
MPC Retirement Plan
MPC Excess Benefit Plan
Number of Years
Credited Service
(#)
2.58
2.58
17.67
17.67
38.58
38.58
26.67
26.67
4.00
4.00
Present Value of
Accumulated
Benefit
($)
76,203
448,286
889,075
1,798,128
1,663,139
2,792,957
577,285
286,752
101,358
259,377
Payments
During Last
Fiscal Year
($)
—
—
—
—
—
—
—
—
—
—
Dollar values for Mr. Swearingen and Ms. Gagle are shown at 75% and 50%, respectively, to reflect the portions
of their time allocated to us for 2019 under our omnibus agreement.
Number of Years Credited Service shows the number of years the NEO has participated in the plan. Plan
participation service used to calculate each participant’s benefit under the MPC Retirement Plan legacy final
average pay formula was frozen as of December 31, 2009.
Present Value of Accumulated Benefit for the MPC Retirement Plan was calculated assuming a weighted
average discount rate of 3.20%, the RP2000 mortality table for lump sums, a 90% lump sum election rate and
retirement at age 62 (or current age, if later). Under the MPC Retirement Plan provisions and actuarial
assumptions, the discount rate for lump sum calculations was 0.25%. See “MPC Retirement Plan” below for
more detail on the formulas.
MPC Retirement Plan
In general, our NEOs are eligible to participate in the MPC Retirement Plan, which is a tax-qualified defined
benefit retirement plan primarily designed to provide participants with income after retirement. The plan has both
a “legacy” retirement benefit and a “cash balance” retirement benefit. Prior to 2010, the monthly benefit was
determined under the MPC legacy benefit formula.
MPC Legacy Benefit Formula
1.6% ×
Monthly Final
Average Pay
— 1.33% ×
Monthly Estimated
Primary Social
Security Benefit
Monthly Benefit
×
×
Years of
Participation
Years of
Participation
Effective January 1, 2010, the formula was amended to (i) cease future accruals of additional participation years,
and (ii) as applied to eligible NEOs, cease further compensation updates. No more than 37.5 participation years
may be recognized under the formula. Eligible earnings include, but are not limited to, pay for hours worked, pay
for allowed hours, military leave allowance, commissions, 401(k) contributions to the MPC Thrift Plan and
incentive compensation bonuses. Age continues to be updated under the formula.
203
Starting in 2010, benefit accruals are determined under a cash balance formula.
MPC Cash Balance Formula
Annual
Compensation ×
Pay Credit
Percentage
× Interest Credit
Rate
+
Account
Balance
Cash Balance Benefit
Participants receive pay credit percentages based on the sum of
their age and cash balance service:
Participant
Points
Pay Credit
Percentage
Fewer than 50
Points
50-69 Points
70 Points or
More
7%
9%
11%
Participants in the plan become fully vested upon completing three years of vesting service. Normal retirement
age under the plan is 65. However, retirement-eligible participants are able to retire and receive an unreduced
benefit under the MPC legacy benefit formula after reaching age 62.
Available benefits include various annuity options and a lump sum distribution option. Participants are eligible
for early retirement upon reaching age 50 and completing 10 years of vesting service. If an employee retires
between the ages of 50 and 62 with sufficient vesting service, the amount of benefit under the MPC legacy
benefit formula is reduced as follows:
Age at Retirement
Early Retirement Factor
61
62
56
100% 97% 94% 91% 87% 83% 79% 75% 71% 67% 63% 59% 55%
50
51
55
60
53
58
57
52
59
54
Of our NEOs providing a majority of their services to our business, only Mses. Beall and Gagle and
Mr. Swearingen have accrued a benefit under the MPC legacy benefit formula. Mses. Beall and Gagle and
Mr. Swearingen are currently eligible for early retirement benefits under the MPC legacy benefit formula.
Under the cash balance formula, plan participants receive pay credits based on age and cash balance service. For
2019, Mses. Beall and Gagle and Mr. Swearingen received pay credits equal to 11% of compensation, which is
the highest level of pay credit available under the plan. Messrs. Hennigan and Floerke received pay credits equal
to 9% of compensation. There are no early retirement subsidies under the cash balance formula.
MPC Excess Benefit Plan (Defined Benefit Portion)
The MPC Excess Benefit Plan is an unfunded, nonqualified deferred compensation plan maintained for the
benefit of a select group of management or highly compensated employees. This plan generally provides benefits
that participants, including our NEOs, would have otherwise received under the tax-qualified MPC Retirement
Plan were it not for Internal Revenue Code limitations. For our NEOs, eligible earnings under the plan include
the items listed above, excluding bonuses, for the MPC Retirement Plan, as well as deferred compensation
contributions, for the highest consecutive 36-month period over the 10-year period up to December 31, 2012.
This plan also provides an enhancement for executive officers using the three highest bonuses earned over the
10-year period up to December 31, 2012, instead of the consecutive bonus formula in place for non-officers.
MPC believes this enhancement is appropriate in light of the greater volatility of executive officer bonuses. As
Messrs. Hennigan and Floerke have not accrued a benefit under the Marathon legacy benefit formula, they are
not eligible for this enhancement.
MPC Thrift Plan
The MPC Thrift Plan is a tax-qualified, defined contribution retirement plan. In general, all of MPC’s employees,
including our NEOs, are immediately eligible to participate in the plan. The purpose of the plan is to assist
employees in maintaining a steady program of savings to supplement their retirement income and to meet other
financial needs.
The MPC Thrift Plan allows eligible employees, such as our NEOs, to make elective deferral contributions
to their plan accounts on a pre-tax or after-tax “Roth” basis from 1% to a maximum of 75% of their plan-
considered gross pay, with such gross pay limited to the applicable Internal Revenue Code annual
compensation limit ($280,000 for 2019). Beginning in 2020, eligible employees who are “highly
compensated employees” as determined under the Internal Revenue Code, such as our NEOs, may
additionally make after-tax contributions to their plan accounts from 1% to 2% of their plan-considered
204
gross pay limited to the applicable Internal Revenue Code annual compensation limit ($285,000 for 2020).
Employer matching contributions are made on such elective deferrals at a rate of 117% up to a maximum of 6%
of an employee’s plan-considered gross pay. All employee elective deferrals and after-tax contributions, and all
employer matching contributions made, are fully vested.
2019 NONQUALIFIED DEFERRED COMPENSATION
The following table provides information regarding MPC’s nonqualified savings and deferred compensation
plans.
Name
Heminger
Plan
MPLX LP 2012 Incentive
Compensation Plan
Executive
Contributions
in Last Fiscal
Year
($)
MPC
Company
Contributions
in Last Fiscal
Year
($)
Aggregate
Earnings in
Last Fiscal
Year
($)
—
—
—
Aggregate
Withdrawals/
Distributions
($)
148,161
Hennigan
MPC Deferred Compensation Plan
509,500
159,179
311,741
Beall
MPC Excess Benefit Plan
MPC Deferred Compensation Plan
Swearingen MPC Excess Benefit Plan
MPC Deferred Compensation Plan
Gagle
MPC Excess Benefit Plan
MPC Deferred Compensation Plan
Floerke
MPC Deferred Compensation Plan
—
—
—
—
—
—
—
—
3,151
66,386
167,903
—
44,515
—
36,174
60,770
3,127
56,672
1,176
19,036
51,351
—
—
—
—
—
—
—
—
Aggregate
Balance at
Last Fiscal
Year-End
($)
88,822
1,728,834
142,479
1,173,041
141,375
355,697
53,151
106,061
248,224
Amounts for Mr. Swearingen and Ms. Gagle are shown at 75% and 50%, respectively, to reflect the portions of
their time allocated to us for 2019 under our omnibus agreement.
Executive Contributions are also included in the “Salary” and “Non-Equity Incentive Plan Compensation”
columns of the “2019 Summary Compensation Table.”
Company Contributions are also included in the “All Other Compensation” column of the “2019 Summary
Compensation Table.”
Aggregate Withdrawals/Distributions represent the payment of distribution equivalents accrued on
non-forfeitable awards.
Aggregate Balance at Last Fiscal Year-End. Of the amounts shown, the following amounts have been reported
in our “Summary Compensation Table” for previous years:
MPC Deferred Compensation Plan
Hennigan
791,567
Beall
175,298
Swearingen
43,361
Floerke
133,004
MPC Excess Benefit Plan (Defined Contribution Portion)
Certain highly compensated non-officer employees (and, prior to January 1, 2006, executive officers who elected
not to participate in the MPC Deferred Compensation Plan), are eligible for the MPC Excess Benefit Plan’s
defined contribution portion. Participants receive employer matching contributions equal to the amount they
would have otherwise received under the tax-qualified MPC Thrift Plan were it not for Internal Revenue Code
limitations.
Defined contribution accruals in the MPC Excess Benefit Plan are credited with interest equal to that paid
in a specified investment option of the MPC Thrift Plan, which was 2.23% for the year ended
December 31, 2019. All plan distributions are paid in a lump sum following the participant’s separation
205
from service. Our NEOs no longer participate in the defined contribution portion of the MPC Excess Benefit
Plan. All nonqualified employer matching contributions for our NEOs now accrue under the MPC Deferred
Compensation Plan.
MPC Deferred Compensation Plan
The MPC Deferred Compensation Plan is an unfunded nonqualified deferred compensation plan maintained for
the benefit of a select group of management or highly compensated employees, including our NEOs. Participants
may defer up to 20% of their salary and bonus each year in a tax-advantaged manner. Deferral elections are made
in December of each year for amounts to be earned in the following year and are irrevocable. The plan credits
matching contributions on a participant’s deferrals equal to the match under the MPC Thrift Plan (currently
117%) plus an amount equal to the matching contributions the participant would have received, but for Internal
Revenue Code limitations and compensation limits, under the MPC Thrift Plan. Participants are fully vested in
their deferrals and matching contributions. Participants may make notional investments of their notional plan
accounts from among certain investment options offered under the MPC Thrift Plan, and participants’ notional
plan accounts are credited with notional earnings and losses based on the result of those investment elections.
Participants generally receive payment of their plan benefits in a lump sum following separation from service.
Section 409A Compliance
All of MPC’s nonqualified deferred compensation plans in which our NEOs participate are intended to comply
with, or be exempt from, Section 409A of the Internal Revenue Code. As a result, distribution of amounts subject
to Section 409A may be delayed for six months following retirement or other separation from service where the
participant is considered a “specified employee” for purposes of Section 409A. All of our NEOs are “specified
employees” for purposes of Section 409A.
POTENTIAL PAYMENTS UPON A TERMINATION OR CHANGE IN CONTROL
The following table provides information regarding the amount of compensation payable to each of our NEOs
under the specified termination scenarios, assuming that the applicable termination event occurred on
December 31, 2019, based on the plans and agreements in place on that date. The actual payments to which an
NEO would be entitled may only be determined based upon the actual occurrence and circumstances surrounding
the termination.
206
Name
Heminger
Hennigan
Beall
Scenario
Retirement
Resignation
Involuntary Termination without
Cause or with Good Reason
Involuntary Termination for Cause
Change in Control with Qualified
Termination
Death
Retirement
Resignation
Involuntary Termination without
Cause or with Good Reason
Involuntary Termination for Cause
Change in Control with Qualified
Termination
Death
Retirement
Resignation
Involuntary Termination without
Cause or with Good Reason
Involuntary Termination for Cause
Change in Control with Qualified
Termination
Death
Swearingen Retirement
Resignation
Involuntary Termination without
Cause or with Good Reason
Involuntary Termination for Cause
Change in Control with Qualified
Termination
Death
Gagle
Floerke
Retirement
Resignation
Involuntary Termination without
Cause or with Good Reason
Involuntary Termination for Cause
Change in Control with Qualified
Termination
Death
Retirement
Resignation
Involuntary Termination without
Cause or with Good Reason
Involuntary Termination for Cause
Change in Control with Qualified
Termination
Death
Additional
Pension
Benefits
($)
Acceler-
ated
Options
($)
Severance
($)
Acceler-
ated
Restricted
Stock
($)
Acceler-
ated
Perform-
ance Units
($)
Other
Benefits
($)
Total
($)
—
—
—
—
—
—
—
—
—
—
7,950,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 1,982,112
—
—
7,250,000
—
— 9,232,112
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 1,982,112
—
7,250,000
—
—
— 9,232,112
—
—
—
—
—
—
—
—
—
—
— 4,509,000
—
—
4,766,667
—
— 9,275,667
—
—
— 4,509,000
— 4,509,000
4,766,667
4,766,667
58,830
17,284,497
— 9,275,667
— 14,742
—
—
—
—
—
—
—
—
14,742
—
— 14,742
—
—
503,593
—
1,333,334
—
— 1,851,669
—
—
2,010,323
—
2,478,689
14,742
— 14,742
503,593
503,593
1,333,334
1,333,334
48,295
6,388,976
— 1,851,669
—
—
—
—
— 43,355
—
—
—
—
—
—
—
—
43,355
—
— 43,355
—
—
509,472
—
1,333,334
—
— 1,886,161
—
—
3,450,000
—
7,111,487
43,355
— 43,355
509,472
509,472
1,333,334
1,333,334
48,102
12,495,750
— 1,886,161
—
—
—
—
— 83,238
—
—
—
—
—
—
—
—
83,238
—
— 83,238
—
—
811,301
—
2,233,334
—
— 3,127,873
—
—
3,975,000
—
8,075,567
83,238
— 83,238
811,301
811,301
—
928,679
2,233,334
2,233,334
64,355
15,242,795
— 3,127,873
—
—
—
—
—
928,679
—
—
—
—
— 13,881
—
—
1,427,032
—
1,333,334
—
— 2,774,247
—
—
3,450,000
—
13,881
— 13,881
1,427,032
1,427,032
1,333,334
1,333,334
53,910
6,278,157
— 2,774,247
—
—
—
—
Severance. Under the MPLX LP Executive Change in Control Severance Benefits Plan, as further described
below, cash severance will only be paid upon a change in control if the NEO experiences a Qualified
Termination (as defined below). If the Qualified Termination occurs within three years prior to the date the NEO
reaches age 65, the NEO’s benefit will be limited to a pro rata portion of the benefit. As Mr. Heminger has
207
reached age 65, his cash severance benefits have been reduced to zero. Ms. Beall’s benefit has been reduced as
she is within three years of reaching age 65.
Pension Benefits for our NEOs are reflected in the “2019 Pension Benefits Table” above. Amounts in this table
represent additional pension benefits attributable solely to the final average pay formula in the applicable plans.
The incremental retirement benefits included in these amounts were calculated using the following assumptions:
individual life expectancies using the RP2000 Combined Healthy Table weighted 75% male and 25% female; a
discount rate of 0.25% for NEOs who are retirement eligible (taking into account the additional three years of
age and service credit) and 0.25% for our NEOs who are not retirement eligible; the current lump-sum interest
rate for the relevant plans; and a lump-sum form of benefit. Only Mses. Beall and Gagle and Mr. Swearingen are
eligible for this enhanced benefit.
Accelerated Options. Vesting of MPC stock options is accelerated upon retirement or a change in control with a
Qualified Termination. In addition, unvested MPC stock options granted in 2017, 2018 and 2019 to Messrs.
Hennigan, Swearingen and Floerke and Mses. Beall and Gagle now become non-forfeitable on the earlier of
December 31, 2020 or the date of such executive’s involuntary termination by MPC. Amounts shown reflect the
value realized if accelerated stock options were exercised on December 31, 2019, taking into account the spread
(if any) between the options’ exercise prices and the closing price of MPC’s common stock ($60.25) on
December 31, 2019.
Accelerated Restricted Stock. Vesting of MPC restricted stock and MPLX phantom units is accelerated upon a
change in control with a Qualified Termination. In addition, unvested MPC restricted stock and MPLX phantom
units granted in 2017, 2018 and 2019 to Messrs. Hennigan, Swearingen and Floerke and Mses. Beall and Gagle
now become non-forfeitable on the earlier of December 31, 2020 or the date of such executive’s involuntary
termination by MPC. Amounts shown reflect the value realized if MPC restricted stock/stock units and MPLX
phantom unit awards vested on December 31, 2019, taking into account the closing price of MPC’s common
stock ($60.25) and MPLX common units ($25.46) on December 31, 2019. In the event of Mr. Floerke’s
termination of employment for any reason other than for cause, the unvested MPLX phantom units he received as
part of his retention award in 2015 will vest and become payable.
Accelerated Performance Units. In the event of a change in control and a Qualified Termination, unvested
MPC performance units and MPLX performance units will vest and be paid out based on actual performance for
the period from the grant date to the change in control date, and target performance for the period from the
change in control date to the end of the performance cycle. In addition, unvested MPC performance units and
MPLX performance units granted in 2017, 2018 and 2019 to Messrs. Hennigan, Swearingen and Floerke and
Mses. Beall and Gagle now become non-forfeitable on the earlier of December 31, 2020 or the date of such
executive’s involuntary termination by MPC. Unvested MPC synergy performance units will vest and be paid out
at the greater of target or actual synergy capture performance. Amounts reflect the MPC performance unit,
MPLX performance unit and MPC synergy performance unit target amounts payable in a change in control
scenario, with each performance unit having a target value of $1.00.
Other Benefits include 36 months of continued health, dental and life insurance coverage. In the event of death, life
insurance would be paid out to the estates of our NEOs in the following amounts: Mr. Hennigan, $1.8 million;
Ms. Beall, $1.09 million; Mr. Swearingen, $1.05 million; Ms. Gagle $1.15 million; Mr. Floerke, $1.05 million.
Retirement
MPC’s employees, including our NEOs, generally are eligible for retirement once they reach age 50 and have at
least 10 years of vesting service with MPC or its subsidiaries. As of December 31, 2019, Messrs. Heminger and
Swearingen and Mses. Beall and Gagle were retirement eligible. If an NEO retires on or after July 1 of the
performance year, eligibility for a bonus under MPC’s ACB program is at the discretion of MPC’s Compensation
Committee. Upon retirement, our NEOs are entitled to receive their vested benefits that have accrued under
MPC’s employee and executive benefit programs. For more information about these retirement and deferred
compensation programs, see “2019 Pension Benefits” and “2019 Nonqualified Deferred Compensation.”
208
In addition, upon retirement, our NEOs’ unvested MPC stock options become exercisable according to the grant
terms. Unvested MPC restricted stock and MPLX phantom units are forfeited upon retirement (except in the case
of a mandatory retirement at age 65, when they vest in full). If an NEO has worked more than nine months of the
performance cycle, performance awards may vest on a prorated basis at the discretion of the MPLX Committee
(MPC’s Compensation Committee, in the case of MPC performance units). In the case of mandatory retirement,
performance units will fully vest; however, payout will occur following the full performance cycle based on its
certified results.
Other Termination
Neither MPC nor we generally enter into employment or severance agreements with our NEOs. An NEO whose
employment is terminated without cause, or who terminates his employment with good reason, is eligible for the
same termination allowance plan available to all other MPC employees, which would pay an amount between
eight and 62 weeks of salary based either on service or salary level, in each case, at the discretion of MPC’s
Compensation Committee.
Upon an NEO’s voluntary termination, or involuntary termination for cause, unvested LTI awards, including
vested but unexercised MPC stock options, generally are forfeited unless provided otherwise in the applicable
award agreement. Upon involuntary termination of an NEO without cause, vested MPC options are exercisable
for 90 days following termination. To promote the retention of Messrs. Hennigan, Swearingen and Floerke and
Mses. Beall and Gagle, their award agreements for MPLX phantom units, MPLX performance units, MPC stock
options, MPC restricted stock and MPC performance units granted in 2017, 2018 and 2019 were amended such
that any such unvested awards now become non-forfeitable on the earlier of December 31, 2020 or the date of
such executive’s involuntary termination by MPC.
Death
In the event of death or disability, our NEOs (or their beneficiaries) are entitled to the vested benefits they have
accrued under MPC’s employee benefits programs. In the event of the death of an NEO during the ACB
performance period, unless otherwise determined by MPC’s Compensation Committee, a target bonus will be
paid. LTI awards immediately vest in full upon death, with performance units vesting at the target level.
Change in Control Plans
Our NEOs participate in two change in control severance plans: the MPC Amended and Restated Executive
Change in Control Severance Benefits Plan (“MPC CIC Plan”) and the MPLX Executive Change in Control
Severance Benefits Plan (“MPLX CIC Plan”). Benefits under each plan are payable only upon a change in
control and a Qualified Termination. In the event of a change in control and Qualified Termination under both
plans, our NEOs would receive benefits under only one plan: whichever provides the greater benefits at that time.
Generally occurs when an NEO’s employment with our affiliates and us ends in connection with, or within two years after,
a change in control. Exceptions include:
Qualified Termination
Š
Š
Š
Š
Separation due to death or disability
Termination for cause
Voluntary termination without good reason (which includes a material reduction in roles, responsibilities, pay or
benefits, or being required to relocate more than 50 miles from one’s current location)
Termination after age 65
209
The following table shows the benefits for which our NEOs would be eligible upon a change in control of MPC
or MPLX and a Qualified Termination with the applicable entity:
Change in Control of MPC
Change in Control of MPLX
A cash payment of up to three times the sum of the NEO’s current annualized base salary plus three times the highest bonus
paid in the three years before the termination or change in control
Life and health insurance benefits for up to 36 months after
termination at the lesser of the current cost or the active
employee cost
Life and health insurance benefits for up to 36 months
after termination at the active employee cost
An additional three years of service credit and three years of age credit for purposes of retiree health and life insurance
benefits
A cash payment equal to the actuarial equivalent of the difference between amounts receivable by the NEO under the final
average pay formula in our pension plans and those payable if: (i) the NEO had an additional three years of participation
service credit; (ii) the NEO’s final average pay were the higher of the NEO’s salary at the time of the change in control event
or Qualified Termination plus the NEO’s highest annual bonus from the preceding three years (for purposes of determining
early retirement commencement factors, the NEO is credited with three additional years of vesting service and three
additional years of age); and (iii) the NEO’s pension had been fully vested
A cash payment equal to the difference between amounts receivable under our tax-qualified and nonqualified defined
contribution type retirement and deferred compensation plans and amounts that would have been received if the NEO’s
defined contribution plan account had been fully vested
Accelerated vesting of all outstanding MPC LTI awards
Accelerated vesting of all outstanding MPLX LTI awards
The MPLX CIC Plan also provides that NEOs who don’t technically incur a Qualifying Termination but separate
from service with MPLX as a result of an MPLX change in control (in other words, where the NEO remains
employed with MPC but no longer provides services to MPLX) will become fully vested in all outstanding
MPLX LTI awards. NEOs who receive an offer for comparable employment from an acquirer or successor entity
in an MPLX change in control will not be eligible to receive benefits under the MPLX CIC Plan.
CEO PAY RATIO
We do not determine the total compensation of our CEO or of any of the other personnel responsible for
managing and operating our business, all of whom are employed by MPC and not by our general partner or us.
Because we do not directly employ any employees and do not determine or pay total compensation to the
employees of MPC who manage and operate our business, we do not have a median employee whose total
compensation can be compared to the total compensation of our CEO.
DIRECTOR COMPENSATION
Officers or employees of our general partner or MPC who also serve as our directors do not receive additional
compensation for their service as our director. Directors who are not officers or employees of our general partner
or MPC receive compensation as “non-employee directors.”
Compensation Program for Non-Employee Directors
Following is the compensation package established for our non-employee directors for 2019:
210
Role
Lead Director
Audit Committee Chair
Conflicts Committee Chair
MLP Representative Board
Observer
All Other Directors
Cash
Retainer
($)
90,000
90,000
90,000
90,000
Deferred
Phantom Unit
Equity Award
($)
Lead
Director
Retainer
($)
Committee
Chair
Retainer
($)
MLP
Representative
Retainer
($)
110,000
110,000
110,000
110,000
15,000
—
—
—
—
15,000
15,000
—
62,500
90,000
110,000
—
—
Total
($)
215,000
215,000
215,000
262,500
200,000
The cash retainer, lead director retainer and committee chair retainers are paid in equal installments on a
quarterly basis. Members of the Conflicts Committee also receive a meeting fee of $1,500 for each Conflicts
Committee meeting attended in excess of six meetings per year.
The equity retainer, in the form of phantom units, is granted in equal installments on a quarterly basis.
Directors receive MPLX distribution equivalents in the form of additional MPLX phantom units. The phantom
units, including those received as distribution equivalents, are deferred, payable in common units only upon a
director’s departure from the Board.
Under MPC’s matching gifts program, non-employee directors may elect to have MPC match up to $10,000 of
their contributions to certain tax-exempt educational institutions each year. The annual limit is applied based on
the date of the director’s gift to the institution. Due to processing delays, the actual amount paid out on behalf of
a director may exceed $10,000 in a given year.
2019 Director Compensation Table
The following table shows compensation earned by or paid to our non-employee directors during 2019.
Name
Michael L. Beatty
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
Frank M. Semple
J. Michael Stice
John P. Surma
Fees Earned or Paid
in Cash
($)
Unit Awards
($)
All Other
Compensation
($)
135,000
150,000
105,000
150,000
177,500
90,000
90,000
110,000
110,000
110,000
110,000
110,000
110,000
110,000
10,000
—
2,500
10,000
—
—
—
Total
($)
255,000
260,000
217,500
270,000
287,500
200,000
200,000
Fees Earned or Paid in Cash reflect (i) cash retainers earned for Board service in 2019, (ii) for each of Messrs.
Beatty, Helms, and Sandman, $45,000 in meeting fees for Conflicts Committee meetings held during 2019, (iii)
for Mr. Semple, $62,500 in compensation for service as our Representative Observer, in which role he attends
certain MPC Board and committee meetings as a liaison between the MPC Board and us, and $25,000 for his
service in the same capacity with respect to an MPC Board special committee.
Unit Awards reflect the aggregate grant date fair value of phantom units, calculated in accordance with FASB
ASC Topic 718. Non-employee directors generally received grants each quarter of phantom units valued at
$27,500 based on the closing price of our common units on each grant date. The aggregate number of phantom
units in respect of Board service outstanding for each non-employee director as of December 31, 2019 is: Messrs.
Helms, Sandman, and Surma, 19,192; Mr. Peiffer, 16,091; Mr. Beatty, 12,942; Mr. Semple, 10,190; and
Mr. Stice, 5,726.
All Other Compensation reflects contributions to educational institutions under MPC’s matching gifts program.
211
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Security Ownership of Directors and Executive Officers
The following table sets forth the number of our common units and shares of MPC common stock beneficially
owned as of January 31, 2020 by each director and NEO, and by all directors and executive officers as a group.
The address for each person named below is c/o MPLX LP, 200 East Hardin Street, Findlay, Ohio 45840. Unless
otherwise indicated, to our knowledge, each person or member of the group listed has sole voting and investment
power with respect to the securities shown, and none of the shares or units shown is pledged as security. As of
January 31, 2020, there were 1,058,401,784 MPLX common units outstanding (including 665,997,540 common
units held by MPC and its affiliates) and 649,486,869 shares of MPC common stock outstanding.
Amount and Nature of Beneficial Ownership
MPLX Common Units MPC Common Stock MPLX
Name of Beneficial Owner
Pamela K.M. Beall
Michael L. Beatty
Gregory S. Floerke
Suzanne Gagle
Christopher A. Helms
Gary R. Heminger
Michael J. Hennigan
Garry L. Peiffer
Dan D. Sandman
Frank M. Semple
J. Michael Stice
John P. Surma
John S. Swearingen
Donald C. Templin
All current Directors and
Executive Officers as a group
(15 individuals)
40,201
41,374
81,828
23,242
31,253
316,810
137,305
85,650
100,883
588,540
9,197
31,502
24,247
102,111
1,623,068
112,560
—
32,631
115,050
—
3,141,178
82,845
63,394
—
4,892
7,713
47,412
236,601
640,716
4,491,141
Percent of Total
Outstanding (%)
MPC
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
Less than 1% of common units or common shares outstanding, as applicable.
MPLX Common Unit ownership amounts include:
•
•
•
Phantom unit awards, which settle in common units upon a director’s retirement from service on the Board,
as follows: Mr. Beatty, 14,004; Mr. Helms, 20,253; Mr. Peiffer, 17,153; Mr. Sandman, 20,253; Mr. Semple,
12,246; Mr. Stice, 8,497; Mr. Surma, 24,002.
Phantom unit awards, which may be forfeited under certain conditions, as follows: Ms. Beall, 10,773;
Mr. Floerke, 47,074; Ms. Gagle, 14,122; Mr. Hennigan, 113,543; Mr. Swearingen, 9,984; Mr. Templin,
30,221; all other executives, 4,613.
For Mr. Heminger, 77,852 phantom unit awards, which are no longer subject to forfeiture because
Mr. Heminger has reached mandatory retirement age.
• Common units indirectly beneficially held in trust as follows: Ms. Beall, 10,000; Mr. Heminger, 174,515;
Mr. Peiffer, 68,497; Mr. Semple, 527,517; Mr. Stice, 700.
•
For Messrs. Semple and Templin, common units held by or with spouse, with spouse as co-trustee or by trust
for the benefit of spouse.
212
MPC Common Stock ownership amounts include:
• All stock options exercisable within 60 days of January 31, 2020 as follows: Ms. Beall, 75,188; Mr. Floerke,
15,831; Ms. Gagle, 94,994; Mr. Heminger, 2,541,680; Mr. Hennigan, 40,791; Mr. Swearingen, 185,974;
Mr. Templin, 541,751; all other executive officers, 4,106. Includes 359,773 stock options exercisable by the
applicable executive officers but not in the money as of January 31, 2020.
•
•
Shares of common stock indirectly beneficially held in trust as follows: Ms. Beall, 32,208; Mr. Heminger,
206,202; Mr. Peiffer, 63,394; Mr. Surma, 10,000.
For Messrs. Surma and Templin, shares of common stock held by or with spouse, with spouse as co-trustee or
by trust for the benefit of spouse.
• Restricted stock unit awards, which vest upon the director’s retirement from service on the MPC Board or
observer status, as follows: Mr. Semple, 4,892; Mr. Stice, 7,713; Mr. Surma, 37,412.
Security Ownership of Certain Beneficial Owners
The following table sets forth information as to each unitholder of whom we are aware that, based on filings with
the SEC, beneficially owns 5% or more of our outstanding common units as of December 31, 2019:
Name and Address
of Beneficial Owner
Marathon Petroleum Corporation
539 S. Main Street
Findlay, Ohio 45840
Number of Common Units
Representing Limited Partner
Interests
665,997,540
Percent of Common Units
Representing Limited Partner
Interests
62.9%
Percent of Common Units is based on common units representing limited partner interests (“MPLX LP
common units”) outstanding as of February 17, 2020.
Marathon Petroleum Corporation. The MPLX common units are directly held by MPC Investment LLC,
MPLX GP LLC, MPLX Logistics Holdings LLC, Tesoro Logistics GP, LLC and Western Refining Southwest,
Inc. Marathon Petroleum Corporation is the ultimate parent company of MPC Investment LLC, MPLX GP LLC,
MPLX Logistics Holdings LLC, Tesoro Logistics GP, LLC and Western Refining Southwest, Inc. and may be
deemed to beneficially own the MPLX LP common units directly held by these entities.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 2019, with respect to common units that may be
issued under the MPLX LP 2012 Plan and the MPLX LP 2018 Plan:
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
Weighted average
exercise price of
outstanding
options, warrants
and rights
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in the first
column)
1,424,846
—
1,424,846
N/A
—
15,226,794
—
15,226,794
Plan category
Equity compensation plans approved by
security holders
Equity compensation plans not approved
by security holders
Total
Number of Securities to Be Issued includes:
•
1,109,598 phantom unit awards granted pursuant to the MPLX 2012 Plan and the MPLX 2018 Plan for
common units unissued and not forfeited, cancelled or expired as of December 31, 2019.
213
•
315,248 units as the maximum potential number of common units that could be issued in settlement of
performance units outstanding as of December 31, 2019, pursuant to the MPLX 2012 Plan and the MPLX
2018 Plan based on the closing price of our common units on December 31, 2019, of $25.46 per unit. The
number of units reported for this award vehicle may overstate dilution. See Item 8. Financial Statements and
Supplementary Data – Note 21 for more information on performance unit awards granted under the MPLX
2012 Plan and the MPLX 2018 Plan.
Weighted Average Exercise Price. There is no exercise price associated with phantom unit awards or
performance unit awards.
Number of Securities Remaining Available reflects the common units available for issuance pursuant to the
MPLX 2018 Plan. The number of units reported in this column assumes 119,207 as the maximum potential
number of common units that could be issued in settlement of performance units outstanding as of December 31,
2019, pursuant to the MPLX 2018 Plan based on the closing price of our common units on December 31, 2019,
of $25.46 per unit. The number of units assumed for this award vehicle may understate the number of common
units available for issuance pursuant to the MPLX 2018 Plan. See Item 8. Financial Statements and
Supplementary Data – Note 21 for more information on performance unit awards issued pursuant to the MPLX
2018 Plan.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Policy and Procedures with Respect to Related Person Transactions
The Board has adopted a formal written related person transactions policy establishing procedures for the
notification, review, approval, ratification and disclosure of related person transactions. Under the policy, a
“related person” includes any director, nominee for director, executive officer, or a known beneficial holder of
more than 5% of any class of our voting securities (other than MPC or its affiliates) or any immediate family
member of a director, nominee for director, executive officer or more than 5% owner. This procedure applies to
any transaction, arrangement or relationship and any series of similar transactions, arrangements or relationships
in which (i) we are a participant, (ii) the amount involved exceeds $120,000, and (iii) a related person has a direct
or indirect material interest.
The Board has provided its standing pre-approval for the following transactions, arrangements and relationships:
•
Payment of compensation to an executive officer or director of our general partner if the compensation is
otherwise required to be disclosed in our filings with the SEC;
• Any transaction where the related person’s interest arises solely from the ownership of securities;
• Any ongoing employment relationship provided that such employment relationship will be subject to initial
review and approval; and
• Any transaction between any of our subsidiaries and us, on the one hand, and our general partner or any of its
affiliates, on the other hand; provided, however, that such transaction is approved consistent with our
Partnership Agreement.
Any related person transaction identified prior to its consummation must be approved in advance by the Board. If
the related person transaction is identified after it commences, it will be promptly submitted to the Board or the
Chairman for ratification, amendment or rescission. If the transaction has been completed, the Board or the
Chairman will evaluate the transaction to determine if rescission is appropriate. Transactions entered into prior to
the closing of the Initial Offering, when this policy was adopted, were approved by the Board apart from the
policy.
In determining whether to approve or ratify a related person transaction, the Board or the Chairman will consider
all relevant facts and circumstances, including but not limited to:
• The benefits to us, including the business justification;
•
If the related person is a director or an immediate family member of a director, the impact on the director’s
independence;
214
• The availability of other sources for comparable products or services;
• The terms of the transaction and the terms available to unrelated third parties or to employees generally; and
• Whether the transaction is consistent with our Code of Business Conduct.
This policy is available on the “Corporate Governance” page of our website at
www.mplx.com/Investors/Corporate_Governance/Policies_and_Guidelines/.
Our Relationship with MPC
As of February 17, 2020, MPC owned through its affiliates 665,997,540 of our common units, representing
approximately 63% of our common units outstanding, and 100% of MPLX GP, our general partner. MPLX GP
manages our operations and activities through its officers and directors. In addition, various of our officers and
directors also serve as officers and/or directors of MPC. Accordingly, we view transactions between MPC and us
as related party transactions and have provided the following disclosures with respect to such transactions during
2019. Unless the context otherwise requires, references in the following discussion to “we” or “us” refer to our
affiliates and us.
Distributions and Reimbursements to MPC
Pursuant to our Partnership Agreement, we make cash distributions to our unitholders, including MPC. During
2019, we distributed approximately $1,529 million with respect to MPC’s limited partner interest.
Under our Partnership Agreement, we reimburse MPLX GP and its affiliates, including MPC, for all costs and
expenses incurred on our behalf. The amount we reimbursed in 2019 was $4 million.
Acquisition of ANDX
We completed the acquisition of ANDX (the “Merger”) on July 30, 2019. Prior to the Merger, MPC owned
through its affiliates approximately 64% of ANDX’s outstanding common units and 100% of its general partner.
At the effective time of the Merger, each common unit held by ANDX’s public unitholders was converted into
the right to receive 1.135 MPLX common units. Each ANDX common unit held by certain affiliates of MPC was
converted into the right to receive 1.0328 MPLX common units. This resulted in the issuance of approximately
102 million MPLX common units to public unitholders and approximately 161 million MPLX common units to
MPC. The units issued to MPC were valued at approximately $4.7 billion as of the transaction closing.
Transactions and Commercial and Other Agreements with MPC
We have multiple long-term, fee-based transportation and storage services agreements, as well as a variety of
operating services agreements, management services agreements, licensing agreements, employee services
agreements, omnibus agreements, a loan agreement, and an aircraft time-sharing agreement with MPC and its
consolidated subsidiaries. See “Our L&S Contracts with MPC and Third Parties - Transportation Services
Agreements, Storage Services Agreements, Terminal Services Agreements and Fuels Distribution Services
Agreement with MPC” in Item 1. Business, and Note 6 - Related Party Agreements and Transactions in the
Notes to Consolidated Financial Statements, for information regarding related party activities with MPC.
Director Independence
The information appearing under “Director Independence” in Item 10. Directors, Executive Officers and
Corporate Governance is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services
Auditor Independence
Our Audit Committee has considered whether PricewaterhouseCoopers LLP is independent for purposes of
providing external audit services to us and has determined that it is.
215
Auditor Fees
Following are the aggregate fees for professional services provided to us by PricewaterhouseCoopers LLP for the
years ended December 31, 2019, and December 31, 2018:
(In thousands)
Audit
Audit-Related
Tax
All Other
Total
2019
2018
$
$
6,208
—
2,312
10
$
8,530
$
3,617
163
989
6
4,775
Audit fees for the years ended December 31, 2019, and December 31, 2018, were primarily for professional
services rendered for the audit of the financial statements and of internal controls over financial reporting, the
performance of regulatory audits, issuance of comfort letters, the provision of consents and the review of
documents filed with the SEC.
Audit-Related fees for the year ended December 31, 2018, were for professional services rendered in relation to
updating accounting processes and procedures in order to comply with new accounting pronouncements.
Tax fees for the years ended December 31, 2019, and December 31, 2018, were for professional services
rendered for the preparation of IRS Schedule K-1 tax forms for MPLX LP unitholders and for income tax
consultation services.
All Other fees for the years ended December 31, 2019, and December 31, 2018, were for subscriptions and
licenses for online accounting resources provided by PricewaterhouseCoopers LLP.
Pre-Approval of Audit Services
Among other things, our Pre-Approval of Audit, Audit-Related, Tax and Permissible Non-Audit Services Policy
sets forth the procedure for the Audit Committee to pre-approve all audit, audit-related, tax and permissible
non-audit services, other than as provided under a de minimis exception. Under the policy, the Audit Committee
may pre-approve any services to be performed by our independent auditor up to twelve months in advance and
may approve in advance services by specific categories pursuant to a forecasted budget. Annually, the executive
vice president and chief financial officer of our general partner will present a forecast of audit, audit-related, tax
and permissible non-audit services for the ensuing fiscal year to the Audit Committee for approval in
advance. The executive vice president and chief financial officer of our general partner, in coordination with the
independent auditor, will provide an updated budget to the Audit Committee, as needed, throughout the ensuing
fiscal year.
For unbudgeted items, the Audit Committee has delegated pre-approval authority of up to $250,000 to the Chair
of the Audit Committee; such items are reported to the full Audit Committee at its next scheduled meeting.
In 2019 and 2018, the Audit Committee pre-approved all audit, audit-related, tax and permissible non-audit
services pursuant to this policy and did not use the de minimis exception.
216
Part IV
Item 15. Exhibits and Financial Statement Schedules
A. Documents Filed as Part of the Report
1. Financial Statements (see Part II, Item 8. of this Annual Report on Form 10-K regarding financial statements)
2. Financial Statement Schedules
Financial statement schedules required under SEC rules but not included in this Annual Report on Form 10-K are
omitted because they are not applicable or the required information is contained in the consolidated financial
statements or notes thereto.
217
Exhibits:
Exhibit
Number
1.1
2.1
2.2
2.3 †
2.4
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
8-K
1.1
3/13/2018
001-35714
8-K
2.1
3/4/2014
001-35714
8-K
2.1
12/2/2014
001-35714
10-Q
2.1
8/3/2015
001-35714
8-K
2.1
11/12/2015 001-35714
Third Amended and Restated
Distribution Agreement, dated as of
March 13, 2018, by and among the
Partnership, the General Partner and
each of J.P. Morgan Securities LLC,
Barclays Capital Inc., Citigroup
Global Markets Inc., Merrill Lynch,
Pierce, Fenner & Smith Incorporated,
RBC Capital Markets, LLC, UBS
Securities LLC and Wells Fargo
Securities, LLC
Partnership Interests Purchase
Agreement dated February 26, 2014,
by and between MPLX Operations
LLC and MPL Investment LLC
Partnership Interests Purchase and
Contribution Agreement, dated
December 1, 2014, by and among
MPLX Operations LLC, MPLX
Logistics Holdings LLC, MPLX LP
and MPL Investment LLC
Agreement and Plan of Merger, dated
as of July 11, 2015, by and among
MPLX LP, Sapphire Holdco LLC,
MPLX GP LLC, MarkWest Energy
Partners, L.P. and, for certain limited
purposes set forth therein, Marathon
Petroleum Corporation
Amendment to Agreement and Plan
of Merger, dated as of November 10,
2015, by and among MPLX LP,
Sapphire Holdco LLC, MPLX GP
LLC, MarkWest Energy Partners,
L.P. and Marathon Petroleum
Corporation
218
Exhibit
Number
2.5
2.6
2.7
2.8
2.9
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
8-K
2.1
11/17/2015 001-35714
8-K
2.1
3/17/2016
001-35714
8-K
2.1
3/2/2017
001-35714
8-K
2.1
9/1/2017
001-35714
8-K
2.1
11/13/2017 001-35714
Amendment Number 2 to Agreement
and Plan of Merger, dated as of
November 16, 2015, by and among
MPLX LP, Sapphire Holdco LLC,
MPLX GP LLC, MarkWest Energy
Partners, L.P. and Marathon
Petroleum Corporation
Membership Interests Contribution
Agreement, dated March 14, 2016,
between MPLX LP, MPLX Logistics
Holdings LLC, MPLX GP LLC and
MPC Investment LLC
Membership Interests Contributions
Agreement, dated March 1, 2017,
between MPLX LP, MPLX Logistics
Holdings LLC, MPLX Holdings Inc.,
MPLX GP LLC and MPC Investment
LLC
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
Membership Interests Contribution
Agreement, dated November 13,
2017, between MPLX LP, MPLX
Logistics Holdings LLC, MPLX
Holdings Inc., MPLX GP LLC and
MPC Investment LLC
2.10 † Agreement and Plan of Merger, dated
8-K
2.1
5/8/2019
001-35714
as of May 7, 2019, by and among
Andeavor Logistics LP, Tesoro
Logistics GP, LLC, MPLX LP,
MPLX GP LLC and MPLX MAX
LLC.
3.1
Certificate of Limited Partnership of
MPLX LP
S-1
3.1
7/2/2012
333-182500
219
Exhibit
Number
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
3.2
3.3
4.1
4.2
4.3
4.4
4.5
4.6
Amendment to the Certificate of
Limited Partnership of MPLX LP
Fifth Amended and Restated
Agreement of Limited Partnership of
MPLX LP, dated as of July 30, 2019
Indenture, dated February 12, 2015,
between MPLX LP and The Bank of
New York Mellon Trust Company,
N.A., as Trustee
First Supplemental Indenture, dated
February 12, 2015, between MPLX
LP and The Bank of New York
Mellon Trust Company, N.A., as
Trustee (including Form of Notes)
Third Supplemental Indenture, dated
as of December 22, 2015, by and
between MPLX LP and the Bank of
New York Mellon Trust Company,
N.A. (including Form of Note)
Fourth Supplemental Indenture, dated
as of December 22, 2015, by and
between MPLX LP and the Bank of
New York Mellon Trust Company,
N.A. (including Form of Note)
Fifth Supplemental Indenture, dated
as of December 22, 2015, by and
between MPLX LP and the Bank of
New York Mellon Trust Company,
N.A. (including Form of Note)
Registration Rights Agreement, dated
as of May 13, 2016, by and between
MPLX LP and the Purchasers party
thereto
S-1/A
3.2
10/9/2012 333-182500
8-K/A
3.1
8/14/2019
001-35714
8-K
4.1
2/12/2015
001-35714
8-K
4.2
2/12/2015
001-35714
8-K
4.3
12/22/2015 001-35714
8-K
4.4
12/22/2015 001-35714
8-K
4.5
12/22/2015 001-35714
8-K
4.1
5/16/2016
001-35714
220
Exhibit
Number
4.7
4.8
4.9
4.10
4.11
4.12
4.13
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Sixth Supplemental Indenture, dated as
of February 10, 2017, between the
Issuer and The Bank of New York
Mellon Trust Company, N.A., as
Trustee
Seventh Supplemental Indenture, dated
as of February 10, 2017, between the
Issuer and The Bank of New York
Mellon Trust Company, N.A., as
Trustee
Eighth Supplemental Indenture, dated
as of February 8, 2018, between the
Issuer and The Bank of New York
Mellon Trust Company, N.A., as
Trustee
Ninth Supplemental Indenture, dated
as of February 8, 2018, between the
Issuer and The Bank of New York
Mellon Trust Company, N.A., as
Trustee
Tenth Supplemental Indenture, dated
as of February 8, 2018, between the
Issuer and The Bank of New York
Mellon Trust Company, N.A., as
Trustee
Eleventh Supplemental Indenture,
dated as of February 8, 2018, between
the Issuer and The Bank of New York
Mellon Trust Company, N.A., as
Trustee
Twelfth Supplemental Indenture, dated
as of February 8, 2018, between the
Issuer and The Bank of New York
Mellon Trust Company, N.A., as
Trustee
8-K
4.1
2/10/2017 001-35714
8-K
4.2
2/10/2017 001-35714
8-K
4.1
2/8/2018
001-35714
8-K
4.2
2/8/2018
001-35714
8-K
4.3
2/8/2018
001-35714
8-K
4.4
2/8/2018
001-35714
8-K
4.5
2/8/2018
001-35714
221
Exhibit
Number
4.14
4.15
4.16
4.17
4.18
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
8-K
4.1
11/15/2018 001-35714
8-K
4.2
11/15/2018 001-35714
10-Q
4.3
10/31/2014 001-03473
(Andeavor)
8-K
4.1
9/9/2019
001-35714
10-K 4.33
2/21/2017
001-03473
(Andeavor)
Thirteenth Supplemental Indenture,
dated as of November 15, 2018,
between the Issuer and The Bank of
New York Mellon Trust Company,
N.A., as Trustee (including form of
note)
Fourteenth Supplemental Indenture,
dated as of November 15, 2018,
between the Issuer and The Bank of
New York Mellon Trust Company,
N.A., as Trustee (including form of
note)
Indenture, dated as of October 29,
2014, among Tesoro Logistics LP,
Tesoro Logistics Finance Corp., the
guarantors named therein and U.S.
Bank National Association, as trustee,
relating to the 5.50% Senior Notes
due 2019 and the 6.25% Senior Notes
due 2022
Sixth Supplemental Indenture, dated
as of September 6, 2019, to Indenture
dated as of October 29, 2014, among
Andeavor Logistics LP (f/k/a Tesoro
Logistics LP), Tesoro Logistics
Finance Corp. and U.S. Bank
National Association, as Trustee
Indenture, dated as of May 12, 2016,
among Tesoro Logistics LP, Tesoro
Logistics Finance Corp., the
guarantors named therein and U.S.
Bank National Association, as trustee,
relating to the 6.375% Senior Notes
due 2024
222
Exhibit
Number
4.19
4.20
4.21
4.22
4.23
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
8-K
4.2
9/9/2019
001-35714
10-K 4.34
2/21/2017
001-03473
(Andeavor)
8-K
4.3
9/9/2019
001-35714
8-K
4.1
11/28/2017 001-35143
(ANDX)
8-K
4.4
9/9/2019
001-35714
Fourth Supplemental Indenture, dated
as of September 6, 2019, to Indenture
dated as of May 12, 2016, among
Andeavor Logistics LP (f/k/a Tesoro
Logistics LP), Tesoro Logistics
Finance Corp. and U.S. Bank
National Association, as Trustee
Indenture, dated as of December 2,
2016, among Tesoro Logistics LP,
Tesoro Logistics Finance Corp., the
guarantors named therein and U.S.
Bank National Association, as trustee,
relating to the 5.25% Senior Notes
due 2025
Fourth Supplemental Indenture, dated
as of September 6, 2019, to Indenture
dated as of December 2, 2016, among
Andeavor Logistics LP (f/k/a Tesoro
Logistics LP), Tesoro Logistics
Finance Corp. and U.S. Bank
National Association, as Trustee
Indenture, dated as of November 28,
2017, among Tesoro Logistics LP,
Tesoro Logistics Finance Corp., the
guarantors named therein and U.S.
Bank National Association, as trustee,
relating to the 3.500% Senior Notes
due 2022, 4.250% Senior Notes due
2027 and 5.200% Senior Notes due
2047
Second Supplemental Indenture,
dated as of September 6, 2019, to
Indenture dated as of November 28,
2017, among Andeavor Logistics LP
(f/k/a Tesoro Logistics LP), Tesoro
Logistics Finance Corp. and U.S.
Bank National Association, as
Trustee
223
Exhibit
Number
4.24
4.25
4.26
4.27
4.28
4.29
4.30
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Fifteenth Supplemental Indenture,
dated as of September 9, 2019,
between the Issuer and The Bank of
New York Mellon Trust Company,
N.A., as Trustee (including form of
note)
Sixteenth Supplemental Indenture,
dated as of September 9, 2019,
between the Issuer and The Bank of
New York Mellon Trust Company,
N.A., as Trustee (including form of
note)
Seventeenth Supplemental Indenture,
dated as of September 23, 2019,
between MPLX LP and the Bank of
New York Mellon Trust Company,
N.A.
Eighteenth Supplemental Indenture,
dated as of September 23, 2019,
between MPLX LP and the Bank of
New York Mellon Trust Company,
N.A.
Nineteenth Supplemental Indenture,
dated as of September 23, 2019,
between MPLX LP and the Bank of
New York Mellon Trust Company,
N.A.
Twentieth Supplemental Indenture,
dated as of September 23, 2019,
between MPLX LP and the Bank of
New York Mellon Trust Company,
N.A.
Twenty-First Supplemental Indenture,
dated as of September 23, 2019,
between MPLX LP and the Bank of
New York Mellon Trust Company,
N.A.
8-K
4.5
9/9/2019
001-35714
8-K
4.6
9/9/2019
001-35714
8-K
4.1
9/27/2019 001-35714
8-K
4.2
9/27/2019 001-35714
8-K
4.3
9/27/2019 001-35714
8-K
4.4
9/27/2019 001-35714
8-K
4.5
9/27/2019 001-35714
224
Exhibit
Number
4.31
4.32
4.33
10.1*
10.2
10.3
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
8-K
4.6
9/27/2019 001-35714
8-K
4.7
9/27/2019 001-35714
S-1/A 10.3
10/9/2012 333-182500
8-K
10.1
11/6/2012 001-35714
X
8-K
10.2
11/6/2012 001-35714
Twenty-Second Supplemental
Indenture, dated as of September 23,
2019, between MPLX LP and the
Bank of New York Mellon Trust
Company, N.A.
Registration Rights Agreement, dated
as of September 23, 2019, by and
among MPLX LP, MPLX GP LLC,
Barclays Capital Inc., MUFG
Securities Americas Inc. and Wells
Fargo Securities, LLC
Description of Securities
MPLX LP 2012 Incentive
Compensation Plan
Contribution, Conveyance and
Assumption Agreement, dated as of
October 31, 2012, among MPLX LP,
MPLX GP LLC, MPLX Operations
LLC, MPC Investment LLC, MPLX
Logistics Holdings LLC, Marathon
Pipe Line LLC, MPL Investment LLC,
MPLX Pipe Line Holdings LP and
Ohio River Pipe Line LLC
Omnibus Agreement, dated as of
October 31, 2012, among Marathon
Petroleum Corporation, Marathon
Petroleum Company LP, MPL
Investment LLC, MPLX Operations
LLC, MPLX Terminal and Storage
LLC, MPLX Pipe Line Holdings LP,
Marathon Pipe Line LLC, Ohio River
Pipe Line LLC, MPLX LP and MPLX
GP LLC
225
Exhibit
Number
10.4
10.5
10.6
10.7
10.8
10.9
10.10
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Employee Services Agreement, dated
effective as of October 1, 2012, by
and among Marathon Petroleum
Logistics Services LLC, MPLX GP
LLC and Marathon Pipe Line LLC
Employee Services Agreement, dated
effective as of October 1, 2012, by
and among Catlettsburg Refining
LLC, MPLX GP LLC and MPLX
Terminal and Storage LLC
Management Services Agreement,
dated effective as of September 1,
2012, by and between Hardin Street
Holdings LLC and Marathon Pipe
Line LLC
Management Services Agreement,
dated effective as of October 10,
2012, by and between MPL Louisiana
Holdings LLC and Marathon Pipe
Line LLC
Amended and Restated Operating
Agreement, dated as of October 31,
2012, between Marathon Petroleum
Company LP and Marathon Pipe Line
LLC
Storage Services Agreement, dated
effective as of October 1, 2012, by
and between Marathon Pipe Line
LLC and Marathon Petroleum
Company LP (Patoka tank farm)
Storage Services Agreement, dated
effective as of October 1, 2012, by
and between Marathon Pipe Line
LLC and Marathon Petroleum
Company LP (Martinsville tank farm)
S-1/A 10.6
10/9/2012 333-182500
S-1/A 10.7
10/9/2012 333-182500
S-1/A 10.8
9/7/2012
333-182500
S-1/A 10.9
10/18/2012 333-182500
8-K
10.3
11/6/2012
001-35714
S-1/A 10.13
10/9/2012 333-182500
S-1/A 10.14
10/9/2012 333-182500
226
Exhibit
Number
10.11
10.12
10.13
10.14
10.15
10.16
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Storage Services Agreement, dated
effective as of October 1, 2012, by and
between Marathon Pipe Line LLC and
Marathon Petroleum Company LP
(Lebanon tank farm)
Storage Services Agreement, dated
effective as of October 1, 2012, by and
between Marathon Pipe Line LLC and
Marathon Petroleum Company LP
(Wood River tank farm)
Storage Services Agreement, dated
effective as of October 1, 2012, by and
between MPLX Terminal and Storage
LLC and Marathon Petroleum
Company LP (Neal butane cavern)
Transportation Services Agreement
(Patoka to Lima Crude System), dated
as of October 31, 2012, between
Marathon Petroleum Company LP and
Marathon Pipe Line LLC
Transportation Services Agreement
(Catlettsburg and Robinson Crude
System), dated as of October 31, 2012,
between Marathon Petroleum
Company LP and Marathon Pipe Line
LLC
Transportation Services Agreement
(Detroit Crude System), dated as of
October 31, 2012, between Marathon
Petroleum Company LP and Marathon
Pipe Line LLC
S-1/A 10.15 10/9/2012 333-182500
S-1/A 10.16 10/9/2012 333-182500
S-1/A 10.17 10/9/2012 333-182500
8-K
10.4
11/6/2012 001-35714
8-K
10.5
11/6/2012 001-35714
8-K
10.6
11/6/2012 001-35714
227
Exhibit
Number
10.17
10.18
10.19
10.20
10.21
10.22
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Transportation Services Agreement
(Wood River to Patoka Crude System),
dated as of October 31, 2012, between
Marathon Petroleum Company LP and
Marathon Pipe Line LLC
Transportation Services Agreement
(Garyville Products System), dated as
of October 31, 2012, between
Marathon Petroleum Company LP and
Marathon Pipe Line LLC
Transportation Services Agreement
(Texas City Products System), dated as
of October 31, 2012, between
Marathon Petroleum Company LP and
Marathon Pipe Line LLC
Transportation Services Agreement
(ORPL Products System), dated as of
October 31, 2012, between Marathon
Petroleum Company LP and Ohio
River Pipe Line LLC
Transportation Services Agreement
(Robinson Products System), dated as
of October 31, 2012, between
Marathon Petroleum Company LP and
Marathon Pipe Line LLC
Transportation Services Agreement
(Wood River Barge Dock), dated as of
October 31, 2012, between Marathon
Petroleum Company LP and Marathon
Pipe Line LLC
8-K
10.7
11/6/2012 001-35714
8-K
10.8
11/6/2012 001-35714
8-K
10.9
11/6/2012 001-35714
8-K 10.10 11/6/2012 001-35714
8-K 10.11 11/6/2012 001-35714
8-K 10.12 11/6/2012 001-35714
10.23* MPC Non-Employee Director
10-K 10.26 3/25/2013 001-35714
Phantom Unit Award Policy
10.24* MPLX GP LLC Amended and
10-K 10.30 2/24/2017 001-35714
Restated Non-Management Director
Compensation Policy and Equity
Award Terms
228
Exhibit
Number
10.25
10.26
10.27
10.28
10.29
10.30+
10.31
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
First Amendment to Amended and
Restated Operating Agreement, dated
as of January 1, 2015, between
Marathon Petroleum Company LP and
Marathon Pipe Line LLC
Operating Agreement, dated as of
January 1, 2015, between Hardin
Street Transportation LLC and
Marathon Pipe Line LLC
Transportation Services Agreement
(Cornerstone Pipeline System and
Utica Build-Out Projects), effective as
of June 11, 2015, by and between
Marathon Petroleum Company LP and
Marathon Pipe Line LLC
First Amendment to Storage Services
Agreement, dated as of September 17,
2015, by and between Marathon
Petroleum Company LP and Marathon
Pipe Line LLC
Employee Services Agreement, dated
December 28, 2015, by and between
MPLX LP and MW Logistics Services
LLC
Second Amended and Restated
Limited Liability Company Agreement
of MarkWest Utica EMG, L.L.C. dated
December 4, 2015, between MarkWest
Utica Operating Company, L.L.C. and
EMG Utica, LLC
Amended and Restated Transportation
Services Agreement, dated January 1,
2015, between Hardin Street Marine
LLC and Marathon Petroleum
Company LP
10-Q 10.2
5/4/2015
001-35714
10-Q 10.3
5/4/2015
001-35714
8-K
10.1
6/17/2015 001-35714
8-K
10.1
9/23/2015 001-35714
8-K
10.1
1/4/2016
001-35714
10-K 10.48 2/26/2016 001-35714
8-K
10.1
4/6/2016
001-35714
229
Exhibit
Number
10.32
10.33
10.34
10.35*
10.36*
10.37*
10.38*
10.39
10.40
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
8-K
10.2
4/6/2016
001-35714
8-K
10.3
4/6/2016
001-35714
8-K
10.4
4/6/2016
001-35714
10-Q 10.9
5/1/2017
001-35714
10-Q 10.7
5/2/2016
001-35714
10-Q 10.8
5/1/2017
001-35714
10-Q 10.9
5/2/2016
001-35714
8-K
10.1
4/29/2016 001-35714
8-K
10.1
9/6/2016
001-35714
First Amendment to the Amended and
Restated Transportation Services
Agreement, dated March 31, 2016,
between Hardin Street Marine LLC
and Marathon Petroleum Company LP
Amended and Restated Management
Services Agreement, dated January 1,
2015, between Hardin Street Marine
LLC and Marathon Petroleum
Company LP
Second Amended and Restated
Employee Services Agreement, dated
January 1, 2015, between Hardin
Street Marine LLC and Marathon
Petroleum Logistics Services LLC
Form of MPLX LP Performance Unit
Award Agreement - Marathon
Petroleum Corporation Officer
Form of MPLX LP Phantom Unit
Award Agreement - Marathon
Petroleum Corporation Officer
Form of MPLX LP Performance Unit
Award Agreement
Form of MPLX LP Phantom Unit
Award Agreement - Officer
Series A Preferred Unit Purchase
Agreement, dated as of April 27, 2016,
by and among MPLX LP and the
Purchasers party thereto
Master Reorganization Agreement,
dated September 1, 2016, by and
among MPLX Holdings Inc.,
MarkWest Energy Partners, L.P.,
MWE GP LLC, MPLX LP, MPLX GP
LLC, MPC Investment LLC, MPLX
Logistics Holdings LLC and
MarkWest Hydrocarbon, L.L.C.
230
Exhibit
Number
10.41
10.42
10.43
10.44
10.45
10.46
10.47
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Second Amendment to Amended and
Restated Operating Agreement, dated
August 1, 2016, between Marathon
Petroleum Company LP and
Marathon Pipe Line LLC
First Amendment to Employee
Services Agreement, dated May 10,
2016, by and between Marathon
Petroleum Logistics Services LLC,
MPLX GP LLC and Marathon Pipe
Line LLC
First Amendment to Amended and
Restated Transportation Services
Agreement, effective as of April 1,
2016, by and between Marathon
Petroleum Company LP and Hardin
Street Marine LLC
First Amendment to Amended and
Restated Management Services
Agreement, effective as of
November 1, 2016, between
Marathon Petroleum Company LP
and Hardin Street Marine LLC
First Amendment to Transportation
Services Agreement, dated
November 1, 2016, between
Marathon Pipeline LLC and
Marathon Petroleum Company LP
(Texas City Products System)
Second Amended and Restated
Employee Services Agreement, dated
March 1, 2017, between Marathon
Petroleum Logistics Services LLC,
Marathon Pipe Line LLC and MPLX
GP LLC
Transportation Services Agreement,
dated January 1, 2015, between
Hardin Street Transportation LLC
and Marathon Petroleum Company
LP
10-Q 10.2
10/31/2016 001-35714
10-Q 10.1
8/3/2016
001-35714
10-Q 10.2
8/3/2016
001-35714
10-K 10.62
2/24/2017
001-35714
10-K 10.63
2/24/2017
001-35714
8-K
10.1
3/2/2017
001-35714
8-K
10.2
3/2/2017
001-35714
231
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Exhibit
Number
10.48
10.49
10.50
10.51
10.52
10.53*
First Amendment to Transportation
Services Agreement, dated
December 1, 2016, between Hardin
Street Transportation LLC and
Marathon Petroleum Company LP
Second Amendment to
Transportation Services Agreement,
dated January 1, 2017, between
Hardin Street Transportation LLC
and Marathon Petroleum Company
LP
Third Amendment to Transportation
Services Agreement, dated January 1,
2017, between Hardin Street
Transportation LLC and Marathon
Petroleum Company LP
Third Amended and Restated
Terminal Services Agreement, dated
March 1, 2017, between MPLX
Terminals LLC and Marathon
Petroleum Company LP
Third Amended and Restated
Employee Services Agreement,
effective December 21, 2015,
between MPLX Terminals LLC and
Marathon Petroleum Logistics
Services LLC
Form of MPLX LP Phantom Unit
Award Agreement - Officer, Cliff
Vesting
10.54*
Amended Restricted Stock Award
Agreement
10.55* MPLX LP Executive Change in
Control Severance Benefits Plan
10.56
Transportation Services Agreement,
dated November 1, 2017, between
Marathon Pipe Line LLC and
Marathon Petroleum Company LP
8-K
10.3
3/2/2017
001-35714
8-K
10.4
3/2/2017
001-35714
8-K
10.5
3/2/2017
001-35714
8-K
10.6
3/2/2017
001-35714
8-K
10.7
3/2/2017
001-35714
10-Q 10.1
8/3/2017
001-35714
10-Q 10.2
10/30/2017 001-35714
10-Q 10.3
10/30/2017 001-35714
8-K
10.1
11/7/2017
001-35714
232
Exhibit
Number
10.57
10.58
10.59
10.60+
10.61+
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Fourth Amendment to Transportation
Services Agreement, dated
November 1, 2017, between Hardin
Street Transportation LLC and
Marathon Petroleum Company LP
Partnership Interests Restructuring
Agreement, dated as of December 15,
2017, among MPLX GP LLC and
MPLX LP
Term Loan Agreement, dated as of
January 2, 2018, among MPLX LP,
as borrower, Mizuho Bank, Ltd., as
administrative agent, each of Mizuho
Bank, Ltd., Merrill Lynch, Pierce,
Fenner & Smith Incorporated, The
Bank of Tokyo-Mitsubishi UFJ, Ltd.,
Barclays Bank PLC, JPMorgan Chase
Bank, N.A., and Wells Fargo
Securities, LLC, as joint lead
arrangers and joint bookrunners,
Bank of America, N.A., The Bank of
Tokyo-Mitsubishi UFJ, Ltd., Barclays
Bank PLC, JPMorgan Chase Bank,
N.A., and Wells Fargo Bank,
National Association, as syndication
agents, and the other lenders and
issuing banks that are parties thereto
Storage Services Agreement, dated as
of October 1, 2017, by and between
Marathon Petroleum Company LP,
Blanchard Refining Company LLC
and Galveston Bay Refining Logistics
LLC.
Storage Services Agreement, dated as
of October 1, 2017, by and between
Marathon Petroleum Company LP
and Garyville Refining Logistics
LLC.
8-K
10.2
11/7/2017
001-35714
8-K
10.1
12/19/2017 001-35714
8-K
10.1
1/4/2018
001-35714
8-K
10.1
2/2/2018
001-35714
8-K
10.2
2/2/2018
001-35714
233
Exhibit
Number
10.62
10.63+
10.64
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Master Amendment to Storage
Services Agreements, dated as of
October 1, 2017, by and between
Marathon Petroleum Company LP,
Blanchard Refining Company LLC,
Galveston Bay Refining Logistics LLC
and the other parties named therein.
Fuels Distribution Services
Agreement, dated as of September 26,
2017, by and between Marathon
Petroleum Company LP and MPLX
Fuels Distribution LLC.
First Amendment to Fuels Distribution
Services Agreement, dated as of
September 26, 2017, by and between
Marathon Petroleum Company LP and
MPLX Fuels Distribution LLC.
8-K
10.3
2/2/2018
001-35714
8-K
10.4
2/2/2018
001-35714
8-K
10.5
2/2/2018
001-35714
10.65* MPLX LP 2018 Incentive
8-K
10.1
3/5/2018
001-35714
10.66*
10.67*
10.68*
10.69*
10.70*
10.71*
Compensation Plan
Form of MPLX LP Performance Unit
Award Agreement - Marathon
Petroleum Corporation Officer
Form of MPLX LP Phantom Unit
Award Agreement - Marathon
Petroleum Corporation Officer
Form of MPLX LP Performance Unit
Award Agreement
Form of MPLX LP Phantom Unit
Award Agreement - Officer
Form of MPLX LP Phantom Unit
Award Agreement - Officer - Three
Year Cliff Vesting
First Amendment to the Loan
Agreement by and between MPLX LP
and MPC Investment LLC, dated
December 4, 2015
10-Q 10.8
4/30/2018 001-35714
10-Q 10.9
4/30/2018 001-35714
10-Q 10.10 4/30/2018 001-35714
10-Q 10.11 4/30/2018 001-35714
10-Q 10.12 4/30/2018 001-35714
10-Q 10.13 4/30/2018 001-35714
234
Exhibit
Number
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
10.72* MPLX LP 2018 Incentive
Compensation Plan MPC
Non-Employee Director Phantom Unit
Award Policy
10-K 10.78 2/28/2019 001-35714
10.73* MPLX GP LLC Amended and
10-K 10.79 2/28/2019 001-35714
10.74
10.75
10.76
10.77
10.78
10.79
Restated Non-Management Director
Compensation Policy and Director
Equity Award Terms
Support Agreement, dated as of May 7,
2019, by and among MPLX LP,
Andeavor Logistics LP, Tesoro
Logistics GP, LLC, Western Refining
Southwest, Inc. and Marathon
Petroleum Corporation.
First Amendment to the MPLX 2018
Incentive Compensation Plan
MPLX LP 2018 Incentive
Compensation Plan Phantom Unit
Award Agreement Officer Grant
(3-year pro-rata vesting)
MPLX LP 2018 Incentive
Compensation Plan Performance Unit
Award Agreement 2019-2021
Performance Cycle
MPLX LP 2018 Incentive
Compensation Plan Phantom Unit
Award Agreement Marathon
Petroleum Corporation Officer (3-year
pro-rata vesting)
2018 Incentive Compensation Plan
Performance Unit Award Agreement
2019-2021 Performance Cycle
Marathon Petroleum Corporation
Officer
8-K
10.1
5/8/2019
001-35714
10-Q 10.1
5/9/2019
001-35714
X
10-Q 10.2
5/9/2019
001-35714
10-Q 10.3
5/9/2019
001-35714
10-Q 10.4
5/9/2019
001-35714
235
Exhibit
Number
10.80
10.81
10.82
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Support Agreement, dated as of May 7,
2019, by and among MPLX LP,
Andeavor Logistics LP, Tesoro
Logistics GP, LLC, Western Refining
Southwest, Inc. and Marathon
Petroleum Corporation
Amended and Restated Credit
Agreement, dated as of July 26, 2019,
by and among MPLX, as borrower,
Wells Fargo Bank, National
Association, as administrative agent,
each of Wells Fargo Securities, LLC,
JPMorgan Chase Bank, N.A., Barclays
Bank PLC, BofA Securities, Inc.,
Citigroup Global Markets Inc., Mizuho
Bank, Ltd., MUFG Bank, Ltd. and
Royal Bank of Canada, 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., MUFG Bank, Ltd. and
Royal Bank of Canada, as
documentation agents, and the other
lenders and issuing banks that are
parties thereto
Amended and Restated Loan
Agreement dated as of July 31, 2019 by
and between MPLX LP and MPC
Investment LLC.
8-K
10.1
5/8/2019 001-35714
8-K
10.1
8/1/2019 001-35714
8-K
10.2
8/1/2019 001-35714
236
Exhibit
Number
10.83
10.84
10.85
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
8-K
10.1
9/27/2019
001-35714
8-K
10.2
10/31/2017 001-35143
(ANDX)
10-K 10.77
2/28/2019
001-35054
Term Loan Agreement, dated as of
September 26, 2019, by and among
MPLX LP, as borrower, Wells Fargo
Bank, National Association, as
administrative agent, each of Wells
Fargo Securities, LLC, BofA
Securities, Inc. and Mizuho Bank,
Ltd., as joint lead arrangers and joint
bookrunners, and the syndication
agents, documentation agents and
lenders that are parties thereto
Fourth Amended and Restated
Omnibus Agreement, dated as of
October 30, 2017, among Andeavor,
Tesoro Refining & Marketing
Company LLC, Tesoro Companies,
Inc., Tesoro Alaska Company LLC,
Tesoro Logistics LP and Tesoro
Logistics GP, LLC
First Amendment to Fourth Amended
and Restated Omnibus Agreement,
dated as of January 30, 2019, among
Andeavor LLC, Marathon Petroleum
Company LP, Tesoro Refining &
Marketing Company LLC, Tesoro
Companies, Inc., Tesoro Alaska
Company LLC, Andeavor Logistics
LP and Tesoro Logistics GP, LLC
237
Exhibit
Number
10.86
10.87
10.88
10.89
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Waiver and Second Amendment to
Fourth Amended and Restated
Omnibus Agreement, dated as of
July 29, 2019, by and among MPC,
Andeavor Logistics LP, Tesoro
Logistics GP, LLC, Tesoro
Refining & Marketing Company
LLC, Tesoro Companies, Inc., Tesoro
Alaska Company LLC and Marathon
Petroleum Company LP.
Third Amended and Restated
Schedules to Fourth Amended and
Restated Omnibus Agreement,
effective August 6, 2018, by and
among Andeavor, Tesoro Refining &
Marketing Company LLC, Tesoro
Companies, Inc., Tesoro Alaska
Company LLC, Andeavor Logistics
LP and Tesoro Logistics GP, LLC
Secondment Agreement, dated as of
January 30, 2019, by and among
Marathon Refining Logistics
Services, LLC, Andeavor Logistics
LP, Tesoro Logistics GP, LLC and
certain other parties thereto
Secondment Agreement, dated as of
January 30, 2019, by and among
Marathon Petroleum Logistics
Services, LLC, Andeavor Logistics
LP, Tesoro Logistics GP, LLC and
certain other parties thereto
8-K
10.3
8/1/2019
001-35054
10-Q 10.2
11/17/2018 001-35143
(ANDX)
8-K
10.1
2/5/2019
001-35143
(ANDX)
8-K
10.2
2/5/2019
001-35143
(ANDX)
10.90
10.91
Form of MPLX LP Replacement
Award for 2017 ANDX Award
Form of MPLX LP Replacement
Award for 2018 ANDX Award
10-Q 10.47
11/4/2019
10-Q 10.48
11/4/2019
001-35143
(ANDX)
001-35143
(ANDX)
238
Exhibit
Number
10.92
10.93
10.94
10.95
10.96
10.97
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Keep-Whole Commodity Fee
Agreement, dated as of December 7,
2014, among Tesoro Refining &
Marketing Company LLC, QEP Field
Services, LLC, QEPM Gathering I,
LLC and Green River Processing,
LLC
First Amendment to Keep-Whole
Commodity Fee Agreement, dated as
of February 1, 2016, among QEP
Field Services, LLC, QEPM
Gathering I, LLC, Green River
Processing, LLC, and Tesoro
Refining & Marketing Company LLC
Fuel Distribution and Supply
Agreement, dated October 15, 2014,
by and between Western Refining
Wholesale, LLC and Western
Refining Southwest, Inc.
Amendment No. 1 to Fuel
Distribution and Supply Agreement,
dated October 15, 2014, by and
between Western Refining
Wholesale, LLC and Western
Refining Southwest, Inc.
Product Supply Agreement, dated
October 15, 2014, by and among
Western Refining Southwest, Inc.,
Western Refining Company, L.P. and
Western Refining Wholesale, LLC
Amendment No. 1 to Product Supply
Agreement, dated October 15, 2014,
by and among Western Refining
Southwest, Inc., Western Refining
Company, L.P. and Western Refining
Wholesale, LLC
8-K
10.9
12/8/2014
001-35143
(ANDX)
8-K
10.3
2/3/2016
001-35143
(ANDX)
8-K
10.2
10/16/2014 001-36114
(WNRL)
10-Q 10.20
8/7/2018
001-35143
(ANDX)
8-K
10.1
10/16/2014 001-36114
(WNRL)
10-Q 10.7
8/7/2018
001-35143
(ANDX)
239
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Exhibit
Number
10.98
10.99
10.100
10.101
10.102
10.103
14.1
Amendment No. 2 to Product Supply
Agreement, dated October 15, 2014,
by and among Western Refining
Southwest, Inc., Western Refining
Company, L.P. and Western Refining
Wholesale, LLC
Amendment No. 3 to Product Supply
Agreement, dated October 15, 2014,
by and among Western Refining
Southwest, Inc., Western Refining
Company, L.P. and Western Refining
Wholesale, LLC
Amendment No. 4 to Product Supply
Agreement, dated October 15, 2014,
by and among Western Refining
Southwest, Inc., Western Refining
Company, L.P. and Western Refining
Wholesale, LLC
Amendment No. 5 to Product Supply
Agreement, dated October 15, 2014,
by and among Western Refining
Southwest, Inc., Western Refining
Company, L.P. and Western Refining
Wholesale, LLC
Fourth Amendment to Third Amended
and Restated Terminal Services
Agreement, dated March 1, 2017,
between MPLX Terminals LLC and
Marathon Petroleum Company LP
Fifth Amendment to Third Amended
and Restated Terminal Services
Agreement, dated March 1, 2017,
between MPLX Terminals LLC and
Marathon Petroleum Company LP
Code of Ethics for Senior Financial
Officers
21.1
List of Subsidiaries
10-Q 10.8
8/7/2018
001-35143
(ANDX)
10-Q 10.9
8/7/2018
001-35143
(ANDX)
10-Q 10.10
8/7/2018
001-35143
(ANDX)
10-Q 10.11
8/7/2018
001-35143
(ANDX)
10-K 14.1
2/24/2017
240
X
X
X
Exhibit
Number
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
23.1
24.1
31.1
31.2
32.1
32.2
Consent of Independent Registered
Public Accounting Firm
Power of Attorney of Directors and
Officers of MPLX GP LLC
Certification of Chief Executive Officer
pursuant to Rule 13(a)-14 and 15(d)-14
under the Securities Exchange Act of
1934
Certification of Chief Financial Officer
pursuant to Rule 13(a)-14 and 15(d)-14
under the Securities Exchange Act of
1934
Certification of Chief Executive Officer
pursuant to 18 U.S.C. Section 1350
Certification of Chief Financial Officer
pursuant to 18 U.S.C. Section 1350
101.INS Inline XBRL Instance Document
101.SCH Inline XBRL Taxonomy Extension
Schema
101.PRE Inline XBRL Taxonomy Extension
Presentation Linkbase
101.CAL Inline XBRL Taxonomy Extension
Calculation Linkbase
101.DEF Inline XBRL Taxonomy Extension
Definition Linkbase
101.LAB Inline XBRL Taxonomy Extension
X
X
X
X
X
X
X
X
X
X
X
X
104
†
*
Label Linkbase
Cover Page Interactive Data File
(formatted as Inline XBRL and
contained in Exhibit 101)
The exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be
provided to the Securities and Exchange Commission upon request.
Indicates management contract or compensatory plan, contract or arrangement in which one or more
directors or executive officers of the Registrant may be participants.
241
+
Application has been made to the Securities and Exchange Commission for confidential treatment of
certain provisions of these exhibits. Omitted material for which confidential treatment has been requested
and has been filed separately with the Securities and Exchange Commission.
Pursuant to Item 601(b)(4) of Regulation S-K, certain instruments with respect to long-term debt issues
have been omitted where the amount of securities authorized under such instruments does not exceed
10 percent of the total consolidated assets of the Registrant. The Registrant hereby agrees to furnish a copy
of any such instrument to the Securities and Exchange Commission upon its request.
242
Item 16. Form 10-K Summary
Not applicable.
243
Pursuant to the requirements of Section 13 or 15(d) 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.
SIGNATURES
Date: February 28, 2020
MPLX LP
MPLX GP LLC
Its general partner
By:
By: /s/ C. Kristopher Hagedorn
C. Kristopher Hagedorn
Vice President and Controller of MPLX GP LLC
(the general partner of MPLX LP)
244
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on February 28, 2020 on behalf of the registrant and in the capacities indicated.
Signature
Title
/s/ Michael J. Hennigan
Michael J. Hennigan
/s/ Pamela K.M. Beall
Pamela K.M. Beall
/s/ C. Kristopher Hagedorn
C. Kristopher Hagedorn
*
Gary R. Heminger
*
Michael L. Beatty
*
Christopher A. Helms
*
Garry L. Peiffer
*
Dan D. Sandman
*
Frank M. Semple
*
J. Michael Stice
*
John P. Surma
*
Donald C. Templin
Director, President and Chief Executive Officer of
MPLX GP LLC (the general partner of MPLX LP)
(principal executive officer)
Director, Executive Vice President and Chief
Financial Officer of MPLX GP LLC (the general
partner of MPLX LP) (principal financial officer)
Vice President and Controller of MPLX GP LLC (the
general partner of MPLX LP) (principal accounting
officer)
Chairman of the Board of Directors of MPLX GP
LLC (the general partner of MPLX LP)
Director of MPLX GP LLC (the general partner of
MPLX LP)
Director of MPLX GP LLC (the general partner of
MPLX LP)
Director of MPLX GP LLC (the general partner of
MPLX LP)
Director of MPLX GP LLC (the general partner of
MPLX LP)
Director of MPLX GP LLC (the general partner of
MPLX LP)
Director of MPLX GP LLC (the general partner of
MPLX LP)
Director of MPLX GP LLC (the general partner of
MPLX LP)
Director of MPLX GP LLC (the general partner of
MPLX LP)
*
The undersigned, by signing his name hereto, does sign and execute this report pursuant to the Power of
Attorney executed by the above-named directors and officers of the general partner of the registrant, which
is being filed herewith on behalf of such directors and officers.
By: /s/ Michael J. Hennigan
Michael J. Hennigan
Attorney-in-Fact
February 28, 2020
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COMPANY INFORMATION
Headquarters
200 East Hardin St.
Findlay, OH 45840
(419) 421-2414
Stock Exchange Listing
New York Stock Exchange
Common Unit Symbol
MPLX
MPLX LP Website: www.MPLX.com
Investor Relations Office
539 South Main St.
Findlay, OH 45840
IR@marathonpetroleum.com
Kristina Kazarian,
Vice President, Investor Relations
(419) 421-2071
Independent Accountants
PricewaterhouseCoopers LLP
406 Washington St., Suite 200
Toledo, OH 43604
Principal Unit Transfer Agent
Computershare
Unitholder correspondence should be mailed to:
P.O. Box 505000
Louisville, KY 40233-5000
Overnight correspondence should be mailed to:
462 South 4th St., Suite 1600
Louisville, KY 40202
(877) 373-6374 (toll free – U.S., Canada,
Puerto Rico)
(781) 575-2879 (other non-U.S. jurisdictions)
web.queries@computershare.com
Annual Report on Form 10-K
Additional copies of the
MPLX LP 2019 Annual Report may be obtained
by contacting:
Public Affairs
539 South Main St.
Findlay, OH 45840
(419) 421-3577
Distributions
Distributions on units, as may be declared by
the Board of Directors, are typically paid
mid-month in February, May, August
and November.
Tax Reporting
MPLX unitholders can access Schedule K-1
tax information by contacting:
Tax Package Support
P.O. Box 799060
Dallas, TX 75379-9060
(800) 232-0011
www.taxpackagesupport.com/mplx
An MPLX refi ned-product
storage and loading facility
in Jacksonville, Florida
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MPLX LP
200 EAST HARDIN ST.
FINDLAY, OH 45840
Non-GAAP Financial Measures
flow
interest,
taxes, depreciation and
Earnings before
amortization
(DCF)
(EBITDA), distributable cash
and distribution coverage ratio are non-GAAP financial
measures provided in this annual report. EBITDA and DCF
reconciliations to the nearest GAAP financial measure are
included on Pages 13-15 and in the MPLX Annual Report on
Form 10-K for the year ended Dec. 31, 2019, filed with the SEC.
Distribution coverage ratio is the ratio of DCF attributable
to GP and LP unitholders to total GP and LP distributions
declared. EBITDA, DCF and distribution coverage ratio
are not defined by GAAP and should not be considered in
isolation of or as an alternative to net income attributable
to MPLX, net cash provided by (used in) operating activities
or other financial measures prepared in accordance with
GAAP. Certain EBITDA forecasts were determined on an
EBITDA-only basis. Accordingly, information related to the
elements of net income, including tax and interest, are not
available and, therefore, reconciliations of these non-GAAP
financial measures to the nearest GAAP financial measures
have not been provided.
MPLX subsidiary
Marathon Pipe Line LLC
(MPL) provides safety-
related activities at state
fairs to enhance public
awareness of calling 811
before digging, in order
to avoid third-party
infrastructure damage.
Here, a fair-goer enjoys
safe digging at the
MPL exhibit at the
Ohio State Fair
in Columbus.
Disclosures Regarding Forward-Looking
Statements
This summary annual report wrap includes forward-
looking statements. You can identify our forward-looking
statements by words such as “anticipate,” “believe,”
“design,” “estimate,” “expect,” “forecast,” “goal,”
“guidance,” “imply,” “intend,” “objective,” “opportunity,”
“outlook,” “plan,” “position,” “pursue,” “prospective,”
“predict,” “project,” “potential,” “seek,” “strategy,”
“target,” “could,” “may,” “should,” “would,” “will” or other
similar expressions that convey the uncertainty of future
events or outcomes. We have based our forward-looking
statements on our current expectations, estimates and
projections about our industry and our partnership. We
caution that these 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. In addition, we have based many
of these forward-looking statements on assumptions
about future events that may prove to be inaccurate.
While our management considers these assumptions to
be reasonable, they are inherently subject to signifi cant
business, economic, competitive, regulatory and other
risks, contingencies and uncertainties, most of which
are diffi cult to predict and many of which are beyond
our control. Accordingly, our actual results may differ
materially from the future performance that we have
expressed or forecast in our forward-looking statements.
We have included in our attached Form 10-K for the year
ended Dec. 31, 2019, cautionary language identifying
important factors, though not necessarily all such factors,
that could cause future outcomes to differ materially from
those set forth in the forward-looking statements.
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