®
2018 ANNUAL REPORT
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MPLX LP
200 East Hardin St.
Findlay, OH 45840
®
Non-GAAP Financial Measures
Adjusted EBITDA, distributable cash flow (DCF), distribution coverage
ratio and leverage ratio are non-GAAP financial measures provided
in this presentation. Adjusted EBITDA and DCF reconciliations to the
nearest GAAP financial measure are included on Pages 10-11 and in
the MPLX Annual Report on Form 10-K for the year ended Dec. 31,
2018, 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. Leverage ratio is consolidated debt to last 12 months pro
forma adjusted EBITDA. These non-GAAP financial measures 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.
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. In accordance with “safe harbor”
provisions of the Private Securities Litigation Reform Act of 1995,
we have included in our attached Form 10-K for the year ended
Dec. 31, 2018, 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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TABLE OF CONTENTS
1 LETTER TO OUR
UNITHOLDERS
2
4
5
6
8
9
STRATEGIC VISION
LOGISTICS AND STORAGE
GATHERING AND
PROCESSING
FINANCIAL AND OPERATIONAL
HIGHLIGHTS
BOARD OF DIRECTORS
COMPANY OFFICERS
10
RECONCILIATION DATA
Front cover: MPLX dock facility in Garyville, Louisiana
Inside cover: Sherwood complex in West Virginia
MPLX | 2018 ANNUAL REPORT
COMPANY INFORMATION
Headquarters
200 East Hardin St.
Findlay, OH 45840
(419) 421-2414
MPLX LP Website: www.MPLX.com
Investor Relations Office
539 South Main St.
Findlay, OH 45840
MPLXInvestorRelations@marathonpetroleum.com
Kristina Kazarian,
Vice President, Investor Relations
(419) 421-2071
Independent Accountants
PricewaterhouseCoopers LLP
406 Washington St., Suite 200
Toledo, OH 43604
Stock Exchange Listing
New York Stock Exchange
Common Unit Symbol
MPLX
Principal Unit Transfer Agent
ComputershareShareholder correspondence
should be mailed to:
P.O. Box 505000
Louisville, KY 40233-5000
Overnight correspondence should
be mailed to:
462 South 4th Street, 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 2018 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
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MV Catlettsburg
on the Ohio River
MPLX | 2018 ANNUAL REPORT 1
FROM THE CHAIRMAN AND CEO
Fellow unitholders,
Throughout 2018, MPLX achieved a variety of milestones that not only met our str ategic objectives for the year,
but went well beyond. We expanded our business through new projects, enhanced the stability of our cas h fl ow
and simplifi ed our fi nancial structure. At the same time, we achieved the largest increase in annual EBITDA
since becoming a public company. Our 2018 adjusted EBITDA of nearly $3.5 billion r epresented an increase of
approximately $1.5 billion over 2017, with almost $400 million of this incr ease from organic investments.
The magnitude of our annual or ganic growth highlights our commer cial and operational acumen. Our careful
focus on strategic projects has allowed us to effectively deploy capital to develop and execute industr y
solutions where we operate.
In our Logistics and Storage segment, we acquired a strategically located export terminal, expanded our Ozark
and Wood River pipeline systems, added tankage at Texas City, Texas, and Patoka, Illinois, and increased the
size of our marine fl eet. In our Gathering and Processing segment, we added 11 new plants that expanded
our natural gas processing capacity by almost 1.5 billion cubic feet per day and our fr actionation capacity by
100,000 barrels per day.
As you’ll see in this report, we also delivered on our
commitment to enhance the fi nancial strength of our
partnership by generating strong distributable cash fl ow
and funding our organic growth without issuing any public
equity. We returned nearly $2.1 billion to unitholders while
increasing our coverage ratio and maintaining a strong
balance sheet.
As we look ahead, our focus will continue to be on
increasing our presence throughout the midstr eam
value chain and developing str ategic assets that generate
third-party revenue. As we have in the past, we expect to
continue to invest in growth projects that deliver attr active
returns, positioning us for long-term unitholder value .
On behalf of the Board of Directors, I thank you for
your investment and look forwar d to growing the
partnership together.
Sincerely,
Gary R. Heminger
Chairman and Chief Executive Offi cer
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2 MPLX | 2018 ANNUAL REPORT
STRATEGIC VISION
CAPTURE FULL MIDSTREAM VALUE CHAIN
ENHANCE CASH-FLOW STABILITY
We are focused on developing infrastructure
to support growth across the hydrocarbon
value chain, including gathering, processing
and fractionation assets, as well as inbound
and outbound logistics infrastructure, such as
long-haul pipelines and export facilities. Our
business strategy and investments are
focused on connecting growing domestic
supply to global demand centers.
Fee-based services and long-term contracts
provide our company through-cycle cash-fl ow
stability. Our strategic relationship with Marathon
Petroleum Corporation (MPC), and increased
focus on third-party business, fosters growth
opportunities as well as a base of stable cash
fl ows. Planned investments in long-haul pipelines
and export facilities are expected to provide
additional stability to our cash-fl ow profi le.
Onshore pipelines supporting
the Louisiana Offshore Oil Port
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MPLX | 2018 ANNUAL REPORT 3
GROW IN PREMIER BASINS
MAINTAIN FINANCIAL DISCIPLINE
Our assets are located in some of the premier
production areas of the U.S., including the
Marcellus and Permian basins. We intend to
increase operating cash fl ow by capitalizing
on organic investment opportunities that arise
in our areas of operations and increasing the
utilization of our existing facilities by providing
additional services for new and existing customers.
We high-grade our portfolio of investment
opportunities to ensure effi cient deployment
of capital. We are committed to maintaining
an investment grade credit profi le and plan to
fi nance our organic growth capital without
issuing any equity.
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4 MPLX | 2018 ANNUAL REPORT
LOGISTICS AND STORAGE
Our Logistics and Storage segment, which generates stable cash fl ows with its fee-based revenues,
reported segment income from operations of $1.7 billion and adjusted EBITDA of $2.1 billion in 2018.
Adjusted EBITDA increased by $1.3 billion compared to the prior year. The increase was primarily due to
the acquisition of refi ning logistics assets and fuels distribution services from MPC, as well as record
crude oil and product pipeline throughputs.
During the year, we continued executing on our long-term strategy of expanding crude oil and refi ned
products infrastructure. We purchased an eastern Gulf Coast export terminal in Mt. Airy, Louisiana, and also
completed the expansion of the Ozark and Wood River-to-Patoka pipeline systems, which connect Cushing,
Oklahoma, to Patoka, Illinois. Lastly, we increased the size of our marine fl eet, placed a new butane cavern
in service and added strategic tankage in Texas City, Texas, and Patoka.
There are numerous growth projects planned for 2019, as we continue to identify opportunities to capture
value across the midstream value chain, with a focus on long-haul pipelines that add stable cash fl ows and
export facilities that meet growing global market needs. We have announced planned investments in crude
oil, natural gas and natural gas liquids pipelines originating in the Permian basin. These pipelines are expected
to connect growing supply in this basin to global demand centers. We plan to develop and expand our
export capabilities at multiple locations along the Gulf Coast, including the recently acquired Mt. Airy terminal.
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GATHERING AND PROCESSING
MPLX | 2018 ANNUAL REPORT 5
Our Gathering and Processing segment delivered strong results in 2018, with segment income from
operations of $767 million. Adjusted EBITDA was $1.4 billion for the year, representing an increase of
15 percent versus the prior year. The signifi cant year-over-year increase was driven by record gathered,
processed and fractionated volumes.
Throughout the year, we continued to execute on our organic growth program by commissioning
eight processing plants and three fractionation facilities. In total, we increased our processing capacity
by nearly 20 percent, to over 9.3 billion cubic feet per day, while also adding 100,000 barrels per day of
fractionation capacity.
Consistent with our strategy of constructing plants on a just-in-time basis, we expect to complete two
additional plants at our Sherwood Complex in the Marcellus basin in 2019. The addition of these plants
will increase our processing capacity in the Marcellus and Utica basins to over 7.4 billion cubic feet per
day, further strengthening our position as the largest processor in the Northeast.
In the Delaware basin, we are focused on developing a super-system very similar to what we have in
the Northeast. We are currently operating two processing plants and have three additional plants under
various stages of development. Upon completion, we will have approximately 1 billion cubic feet per day
of processing capacity, leading to signifi cant liquids production in this basin.
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6 MPLX | 2018 ANNUAL REPORT
FINANCIAL AND OPERATIONAL HIGHLIGHTS
FINANCIAL HIGHLIGHTS
2016
2017
2018
Net income attributable to MPLX ($mm)
$ 233
$ 794
$ 1,818
Adjusted EBITDA attributable to MPLX ($mm)
Net cash provided by operating activities ($mm)
Distributable cash fl ow (DCF) ($mm)
Distribution per common unit (rounded to nearest $0.01)
Distribution coverage ratio
Growth capital expenditures ($mm)
1,419
1,491
1,140
2.05
1.23x
1,292
2,004
1,907
1,628
2.30
1.28x
1,518
3,475
2,826
2,781
2.53
1.36x
1,998
82%
MPLX Total Return
Since IPO
S&P 500: 102%
Peers: 31% (1)
$2.8
Billion
Distributable
Cash Flow in 2018
(1) Peer group includes: Andeavor Logistics LP, Buckeye Partners, L.P., Enterprise Product Partners L.P., Magellan Midstream Partners, L.P., Phillips 66 Partners LP and Plains All
American Pipeline LP.
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MPLX | 2018 ANNUAL REPORT 7
ADJUSTED EBITDA ATTRIBUTABLE TO MPLX
$ millions
3,475
2,004
1,419
2016
2017
2018
DISTRIBUTION AND COVERAGE RATIO
2.05
2.30
1.23x
1.28x
2.53
1.36x
2016
2017
2018
Distribution coverage ratio
Distribution per common unit (rounded to nearest $0.01)
$3.5
Billion
Adjusted
EBITDA in 2018
1.36x
Distribution
Coverage Ratio
3.9x
Consolidated
Debt-to-
Adjusted EBITDA
Ratio
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8 MPLX | 2018 ANNUAL REPORT
BOARD OF DIRECTORS
Standing, left to right
Donald C. Templin
President, Refi ning, Marketing
and Supply, 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, and assumed his current
role in 2018. 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 various
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 Chesa-
peake Midstream Partners,
L.P., later called Access
Midstream Partners G.P.,
L.L.C.
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.
Timothy T. Griffi th
Senior Vice President
and Chief Financial
Offi cer, MPC. Prior to
MPC, Mr. Griffi th was
vice president and
treasurer of Smurfi t-
Stone Container Corp.,
vice president and
treasurer of Cooper-
Standard Automotive
and assistant treasurer
of Lear Corp. He also
held positions at
Comerica Inc. and
Citicorp Securities.
Seated, left to right
Michael J. Hennigan
President, 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.
Gary R. Heminger
Chairman and CEO,
MPLX GP LLC, Chairman
and CEO, MPC, and
Chairman and CEO of
the general partner of
Andeavor Logistics LP.
Mr. Heminger joined
Marathon Oil Co. in
1975 and held various
leadership positions,
including head of
Marathon’s downstream
operations beginning
in 2001. Mr. Heminger
was named president
and CEO of Marathon
Petroleum Corp. in 2011
and chairman in 2016.
Gregory J. Goff
Executive Vice
Chairman, MPC.
Mr. Goff previously
served as chairman,
president and chief
executive offi cer
of Andeavor and
chairman and chief
executive offi cer of
the general partner
of Andeavor Logistics
LP. He completed a
29-year career with
ConocoPhillips where
he held several senior
leadership positions.
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.
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COMPANY OFFICERS
MPLX | 2018 ANNUAL REPORT 9
Standing, left to right
Seated, left to right
Not pictured
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
Shawn M. Lyon
Vice President
Operations
Suzanne Gagle
General Counsel
John S. Swearingen
Executive Vice President
Logistics and Storage
Michael J. Hennigan
President
Gary R. Heminger
Chairman and Chief Executive Offi cer
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
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10 MPLX | 2018 ANNUAL REPORT
RECONCILIATION DATA
Reconciliation of adjusted EBITDA attributable to MPLX LP, and DCF attributable to GP and
LP unitholders from net income (unaudited)
(In millions)
Net income
Depreciation and amortization
Provision (benefi t) for income taxes
Amortization of deferred fi nancing costs
Loss on extinguishment of debt
Non-cash equity-based compensation
Impairment expense
Net interest and other fi nancial costs
(Income) loss from equity method investments (1)
Distributions/adjustments related to equity method investments
Unrealized derivative losses (gains) (2)
Acquisition costs
Adjusted EBITDA
Adjusted EBITDA attributable to non-controlling 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
Equity method investment capital expenditures paid out
Other
Portion of DCF adjustments attributable to Predecessor (3)
DCF attributable to MPLX LP
Preferred unit distributions
DCF attributable to GP and LP unitholders
2016
$ 434
591
(12)
46
–
10
130
215
74
150
36
(1)
1,673
(3)
(251)
1,419
16
(215)
(84)
(3)
(1)
8
1,140
(41)
$ 1,099
Year Ended Dec. 31
2017
$ 836
683
1
53
–
15
–
301
(78)
231
6
11
2,059
(8)
(47)
2,004
33
(301)
(103)
(13)
6
2
1,628
(65)
$ 1,563
2018
$ 1,834
766
8
59
46
19
–
556
(240)
447
(5)
3
3,493
(18)
–
3,475
32
(556)
(146)
(31)
7
–
2,781
(75)
$ 2,706
(1) Includes an impairment expense of $89 million related to one of the partnership’s equity method investments for the year ended Dec. 31, 2016.
(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 MPLX LP and DCF prior
to the acquisition dates.
Reconciliation of adjusted EBITDA attributable to MPLX LP, and DCF attributable to
GP and LP unitholders from net cash provided by operating activities (unaudited)
(In millions)
Net cash provided by operating activities
Changes in working capital items
All other, net
Non-cash equity-based compensation
Net gain on disposal of assets
Loss on extinguishment of debt
Current income taxes
Net interest and other fi nancial costs
Asset retirement expenditures
Unrealized derivative losses (gains) (1)
Acquisition costs
Other adjustments to equity method investment distributions
Adjusted EBITDA
Adjusted EBITDA attributable to non-controlling interests
Adjusted EBITDA attributable to Predecessor (2)
Adjusted EBITDA attributable to MPLX LP
Deferred revenue impacts
Net interest and other fi nancial costs
Maintenance capital expenditures
Equity method investment capital expenditures paid out
Other
Portion of DCF adjustments attributable to Predecessor (2)
DCF attributable to MPLX LP
Preferred unit distributions
DCF attributable to GP and LP unitholders
Year Ended Dec. 31
2016
$ 1,491
2017
$ 1,907
2018
$ 2,826
(76)
(16)
10
1
–
5
215
6
36
(1)
2
1,673
(3)
(251)
1,419
16
(215)
(84)
(3)
(1)
8
1,140
(41)
(147)
(28)
15
–
–
2
301
2
6
11
(10)
2,059
(8)
(47)
2,004
33
(301)
(103)
(13)
6
2
1,628
(65)
41
(45)
19
(2)
46
–
556
7
(5)
3
47
3,493
(18)
–
3,475
32
(556)
(146)
(31)
7
–
2,781
(75)
$ 1,099
$ 1,563
$ 2,706
(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 MPLX LP and DCF prior
to the acquisition dates.
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MPLX | 2018 ANNUAL REPORT 11
RECONCILIATION DATA
Reconciliation of Capital Expenditures (unaudited)
(In millions)
Capital expenditures (1)
Maintenance
Growth
Total capital expenditures
Less:
Increase (decrease) in capital accruals
Asset retirement expenditures
Additions to property, plant and equipment
Capital expenditures of unconsolidated subsidiaries (2)
Total gross capital expenditures
Less:
Joint venture partner contributions
Total capital expenditures, net
Acquisitions
Total capital expenditures, net and acquisitions
Less: Maintenance capital
Acquistions
Total growth capital expenditures
Year Ended Dec. 31
2016
2017
2018
$ 84
1,213
1,297
(22)
6
1,313
131
1,444
64
1,380
–
1,380
88
–
$ 1,292
$ 103
1,381
1,484
71
2
1,411
384
1,795
169
1,626
249
1,875
108
249
$ 1,518
$ 146
1,884
2,030
104
7
1,919
421
2,340
196
2,144
451
2,595
146
451
$ 1,998
(1) Includes capital expenditures of the Predecessor for all periods presented.
(2) Capital expenditures includes amounts related to unconsolidated, partnership operated subsidiaries.
Reconciliation of Net Income to last 12 months pro forma adjusted EBITDA (unaudited)
(In millions)
Net income
Net income to adjusted EBITDA adjustments
Adjusted EBITDA attribuatble to MPLX LP
Pro forma adjustments for acquisitions
MPLX rail yards
in Hopedale,
Ohio
LTM Pro forma adjusted EBITDA
Consolidated debt
Consolidated debt to adjusted EBITDA
Year Ended Dec. 31
2016 2016 w
$ $ 434
2017
$ 836
985
1,419
30
1,449
4,858
3.4x
1,168
2,004
146
2,150
7,748
3.6x
2018
$ 1,834
1,641
3,475
92
3,567
13,856
3.9x
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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, 2018
‘ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
to
For the transition period from
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, Ohio 45840
(Address of principal executive offices)
(419) 421-2414
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Units Representing Limited Partnership Interests
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is
not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. È
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. (Check one):
Large accelerated filer È
Non-accelerated filer ‘
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 30, 2018 was approximately $9.8 billion. This
amount is based on the closing price of the registrant’s common units on the New York Stock Exchange on June 29, 2018.
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 794,158,848 common units outstanding at February 15, 2019.
‘
Accelerated filer
Smaller reporting company ‘
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.
Item 9A. Controls and Procedures
Item 9B. Other Information
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
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
4
32
60
61
72
73
74
76
80
111
114
179
179
179
180
191
221
223
225
226
241
242
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
Class A Reorganization
Condensate
DCF (a non-GAAP financial measure)
DOT
Dth/d
EBITDA (a non-GAAP financial measure)
EIA
EPA
FASB
FERC
GAAP
Gal
Gal/d
IDR
Initial Offering
IRS
Joint-Interest Acquisition
LIBOR
MarkWest Merger
mbbls
mbpd
mcf
MMBtu
MMcf/d
Net operating margin (a non-GAAP financial
measure)
NGL
NYSE
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.
Barrels
One billion cubic feet per day
One British thermal unit, an energy measurement
On September 1, 2016, a series of reorganization transactions
were initiated in order to simplify our ownership structure and its
financial and tax reporting requirements, resulting in the
elimination of all previously issued and outstanding MPLX LP
Class A units
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
Dekatherms per day
Earnings Before Interest, Taxes, Depreciation and Amortization
United States Energy Information Administration
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 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
Segment revenues, less purchased product costs, less derivative
gains (losses) related to purchased product costs
Natural gas liquids, such as ethane, propane, butanes and natural
gasoline
New York Stock Exchange
OTC
Partnership Agreement
PHMSA
PPI
Predecessor
Realized derivative gains/losses
SEC
SMR
Unrealized derivative gains/losses
USCG
VIE
WTI
Over-the-Counter
Fourth Amended and Restated Agreement of Limited Partnership
of MPLX LP, dated as of February 1, 2018
Pipeline and Hazardous Materials Safety Administration
Producer Price Index
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 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
West Texas Intermediate
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.
You can identify our forward-looking statements by words such as “anticipate,” “believe,” “could,” “design,”
“estimate,” “expect,” “forecast,” “goal,” “guidance,” “imply,” “intend,” “may,” “objective,” “opportunity,”
“outlook,” “plan,” “position,” “potential,” “predict,” “project,” “prospective,” “pursue,” “seek,” “should,”
“strategy,” “target,” “will,” “would” or other similar expressions that convey the uncertainty of future events or
outcomes. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995,
these statements are accompanied by 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.
Forward-looking statements include, but are not limited to, statements that relate to, or statements that are subject
to risks, contingencies or uncertainties that relate to:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the potential merger, consolidation or combination of MPLX with ANDX;
future levels of revenues and other income, income from operations, net income attributable to MPLX LP,
earnings per unit, Adjusted EBITDA or DCF (please read Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations—Non-GAAP Financial Information for the definitions of
Adjusted EBITDA and DCF);
the regional, national and worldwide availability and pricing of refined products, crude oil, natural gas,
NGLs and other feedstocks;
consumer demand for refined products;
our ability to manage disruptions in credit markets or changes to our credit rating;
anticipated levels of drilling activity, production rates and volumes of throughput of crude oil, natural gas,
NGLs, refined products or other hydrocarbon-based products;
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 reliability of processing units and other equipment;
expectations regarding joint venture arrangements and other acquisitions, including the dropdowns
completed by Marathon Petroleum Corporation (“MPC”), or divestitures of assets;
business strategies, growth opportunities and expected investment;
the adequacy of our capital resources and liquidity, including but not limited to, availability of sufficient
cash flow to execute our business plan and to pay distributions;
the effect of restructuring or reorganization of business components;
the potential effects of judicial or other proceedings on our business, financial condition, results of
operations and cash flows;
the potential effects of changes in tariff rates on our business, financial condition, results of operations and
cash flows;
continued or further volatility in and/or degradation of general economic, market, industry or business
conditions;
compliance with federal and state environmental, economic, health and safety, energy and other policies and
regulations;
1
•
•
•
our ability to successfully implement our business plans, growth strategy and self-funding model;
capital market conditions, including the cost of capital, and our ability to raise adequate capital to execute
our business plan and implement our growth strategy; and
the anticipated effects of actions of third parties such as competitors; 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:
•
•
•
•
•
•
volatility or degradation in general economic, market, industry or business conditions;
risks and uncertainties associated with intangible assets, including any future goodwill or intangible assets
impairment charges;
availability and pricing of domestic and foreign supplies of natural gas, NGLs and crude oil and other
feedstocks;
availability and pricing of domestic and foreign supplies of refined products such as gasoline, diesel fuel, jet
fuel, home heating oil and petrochemicals;
foreign imports and exports of crude oil, refined products, natural gas and NGLs;
completion of midstream infrastructure by competitors;
• midstream and refining industry overcapacity or under capacity;
•
•
•
•
•
•
•
•
•
•
•
•
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;
fluctuations in consumer demand for refined products, natural gas and NGLs, including seasonal
fluctuations;
changes to the expected construction costs and timing of projects and planned investments, and our ability
to obtain regulatory and other approvals with respect thereto;
political and economic conditions in nations that consume refined products, natural gas and NGLs,
including the United States, and in crude oil producing regions, including the Middle East, Africa, Canada
and South America;
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;
changes in fuel and utility costs for our facilities;
failure to realize the benefits projected for capital projects, or cost overruns associated with such projects;
the ability to successfully implement growth opportunities, including strategic initiatives and actions;
the ability to realize the strategic benefits of joint venture opportunities;
accidents or other unscheduled shutdowns affecting our machinery, pipelines, processing, fractionation and
treating facilities or equipment, or those of our suppliers or customers;
unusual weather conditions and natural disasters;
2
•
•
•
•
disruptions due to equipment interruption or failure, including electrical shortages and power grid failures;
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;
state and federal environmental, economic, health and safety, energy and other policies and regulations,
including the cost of compliance;
adverse changes in laws including with respect to tax and regulatory matters;
• modifications to earnings and distribution growth objectives;
•
•
•
•
•
•
•
•
rulings, judgments or settlements and related expenses in litigation or other legal, tax or regulatory matters,
including unexpected environmental remediation costs, in excess of any reserves or insurance coverage;
the suspension, reduction or termination of MPC’s obligations under MPLX’s commercial agreements;
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;
labor and material shortages;
the ability and willingness of parties with whom we have material relationships to perform their obligations
to us;
capital market conditions, including an increase of the current yield on MPLX LP common units, adversely
affecting MPLX LP’s ability to meet its distribution growth guidance;
changes in the credit ratings assigned to our debt securities and trade credit, changes in the availability of
unsecured credit, changes affecting the credit markets generally and our ability to manage such changes; 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.
3
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.
We are engaged in the transportation, storage and distribution of crude oil and refined petroleum products;
gathering, processing and transportation of natural gas; and the gathering, transportation, fractionation, storage
and marketing of NGLs. Our operations are conducted in the following operating segments: Logistics and
Storage (“L&S”) and Gathering and Processing (“G&P”). Our L&S assets are primarily located in the Midwest
and Gulf Coast regions of the United States while our G&P assets are primarily located in the Northeast and
Southwest regions of the United States. For more information on these segments, see Our Operating Segments
discussion below. The map below and Item 2. Properties detail our assets as of December 31, 2018:
We have a strategic relationship with MPC, which is a large source of our revenues, where we have executed
multiple transportation and storage services agreements which are long-term, fee-based agreements with
minimum volume commitments which provide us with a stable and predictable revenue stream and source of
cash flows. MPC’s significant interest in us and its stated intent to grow its midstream business has been
evidenced by the completion of various dropdowns of MLP-qualifying midstream assets throughout 2017 and
2018. In addition, immediately following the completion of the dropdowns in 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
(the “GP IDR Exchange”). This exchange eliminated the general partner cash distribution requirements of
4
MPLX. As of December 31, 2018, MPC owned approximately 64 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 natural gas resource plays,
including the Marcellus Shale, Utica Shale, STACK Shale and Permian Basin 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.
2018 RESULTS
The following table summarizes the operating performance for each segment for the year ended December 31,
2018. 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.
(In millions)
Segment revenues and other income
Segment cost of revenues and purchases
Segment income from operations
Segment Adjusted EBITDA
RECENT DEVELOPMENTS
L&S
2018
G&P
Total
$
$
3,240
$
3,185 $
1,086
1,736
1,707
767
2,057
$
1,418 $
6,425
2,793
2,503
3,475
On January 25, 2019, we announced the board of directors of our general partner had declared a distribution of
$0.6475 per common unit that was paid on February 14, 2019 to common unitholders of record on February 5, 2019.
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 unsecured senior notes due
February 2029 and $1.5 billion aggregate principal amount of 5.5 percent unsecured 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 proceeds were used
to repay outstanding borrowings under the MPLX Credit Agreement (see Note 18) and the MPC Loan
Agreement (see Note 6) and to redeem the $750 million 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 on February 15 and August 15, commencing on February 15, 2019.
On December 10, 2018, MPLX redeemed all of the $750 million 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 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.
2018 ACQUISITIONS, INVESTMENTS AND OTHER HIGHLIGHTS
During 2018, we continued to execute on our organic growth plan through projects which included: expansion of
the Ozark pipeline and Wood River-to-Patoka pipelines, completion of the Robinson Butane Cavern, tank farm
and marine fleet expansions, and the addition of processing and fractionating capacity at numerous plants
through projects which were completed throughout the year. We also had non-organic growth through the
5
acquisition of MPLX Refining Logistics LLC (“Refining Logistics”) and MPLX Fuels Distribution LLC (“Fuels
Distribution”) from MPC as well as the acquisition of an eastern U.S. Gulf Coast export terminal (the “Mt. Airy
Terminal”) as described below.
On September 26, 2018, MPLX acquired the Mt. Airy Terminal, which has 4 million barrels of third-party leased
storage capacity and a 120 mbpd dock, from Pin Oak Holdings, LLC, for $451 million. The facility has the
capability to significantly expand its storage capacity to 10 million barrels and is permitted for construction of a
second 120 mbpd dock. The facility is strategically located on the Mississippi River between New Orleans and
Baton Rouge and is near several Gulf Coast refineries, including MPC’s Garyville refinery. The Mt. Airy
Terminal can handle multiple refined products, as well as residual fuel and bunker products, to provide
optionality and flexibility of feedstocks and finished products in a single location. The Mt. Airy Terminal also
has significant growth opportunities as a result of multiple pipelines and rail lines crossing the property in
addition to being positioned as an aggregation point for liquids growth for both ocean-going vessels and inland
barges. See Item 8. Financial Statements and Supplementary Data—Note 4 for additional information.
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 unsecured senior notes due March 2023,
$1.25 billion aggregate principal amount of 4.0 percent unsecured senior notes due March 2028, $1.75 billion
aggregate principal amount of 4.5 percent unsecured senior notes due April 2038, $1.5 billion aggregate principal
amount of 4.7 percent unsecured senior notes due April 2048, and $500 million aggregate principal amount of
4.9 percent unsecured senior notes due April 2058. The 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. The net
proceeds were used to repay the $4.1 billion 364-day term loan facility (drawn to fund the cash portion of the
consideration for the Refining Logistics and Fuels Distribution acquisition described below) and other
borrowings as well as for general business purposes.
On February 1, 2018, MPLX acquired Refining Logistics and Fuels Distribution from MPC in exchange for
$4.1 billion in cash and common units and general partner units of 111.6 million and 2.3 million, respectively.
The general partner units maintained MPC’s two percent economic general partner interest, which converted into
a non-economic general partner interest immediately thereafter as part of the GP IDR Exchange. Refining
Logistics owns and operates the integrated tank farm assets that support MPC’s refining operations. These
essential 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. Fuels Distribution
is structured to provide a broad range of scheduling and marketing services as an agent of MPC. See Item 8.
Financial Statements and Supplementary Data—Note 4 for additional details.
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. For the year ending
December 31, 2019, we expect fee-based contracts to be approximately 95 percent of our Net operating margin
6
(for more information on Net operating margin, which is a non-GAAP measure, see Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations).
Growth in Premier Basins: Our assets are located in some of the premier production areas in the United States,
including the Marcellus and Permian basins. 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.
7
ORGANIZATIONAL STRUCTURE
The following diagram depicts our organizational structure and MPC’s ownership interest in us as of
February 15, 2019.
Marathon Petroleum Corporation
(NYSE: MPC)
and Affiliates (including our General Partner)
504,701,934 Common Units
(63.6% of common units outstanding)
Public Unitholders
289,456,914 Common
Units (36.4% of common
units outstanding)
MPLX GP LLC
(our General Partner)
non-economic general partner interest
Series A Preferred
Unitholders
30,769,232
Preferred Units
MPLX LP
(NYSE: MPLX)
(the Partnership)
MPLX Operations LLC
MarkWest Energy Partners, L. P.
L&S
Operating
Subsidiaries
G&P
Operating
Subsidiaries
We are an MLP with outstanding common units and preferred units. Our common units are publicly traded on the
NYSE under the symbol “MPLX.” The preferred units rank senior to all common units with respect to
distributions and rights upon liquidation. The holders of the 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 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 may convert their preferred units into common units at any time after the third anniversary of the
issuance date or prior to liquidation, dissolution or winding up of the Partnership, in full or in part, subject to
minimum conversion amounts and conditions. After the fourth anniversary of the issuance date, MPLX may
convert the preferred units into common units at any time, in whole or in part, subject to certain minimum
conversion amounts and conditions, if the closing price of MPLX LP common units is greater than $48.75 for the
20-day trading period immediately preceding the conversion notice date. The conversion rate for the 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 preferred units are entitled to vote on an as-converted basis with the common
8
unitholders and have certain other class voting rights with respect to any amendment to the Partnership Agreement
that would adversely affect any rights, preferences or privileges of the preferred units. In addition, upon certain
events involving a change in control the holders of preferred units may elect, among other potential elections, to
convert their preferred units to common units at the then applicable change of control conversion rate.
INDUSTRY OVERVIEW
As of December 31, 2018, our diversified services in the midstream sector are across the hydrocarbon value
chain. The types of midstream services provided by both our L&S and G&P segments are as follows:
L&S:
Our L&S assets are integral to the success of MPC’s operations related to transportation and storage across the
hydrocarbon value chain.
•
•
Logistics. 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
and Canada to numerous refiners. Terminals provide for the receipt, storage, blending, additization,
handling and redelivery of refined petroleum products.
Storage. The hydrocarbon market is often volatile and the ability to take advantage of fast-moving market
conditions is enhanced by our ability to store crude oil and other hydrocarbon-based products at our tank
farms, butane and propane caverns, and in tanks within MPC’s refineries. Storage facilities provide
flexibility and logistics optionality, which enhances MPC’s ability to maximize returns for refined products.
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 transport raw, or
untreated, natural gas to a central location for treating and processing. A large gathering system may involve
thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically
designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow
gathering of additional production without significant incremental capital expenditures.
• Compression. Natural gas compression is a mechanical process in which a volume of natural gas at a
given pressure is compressed to a desired higher pressure, which allows the natural gas to be gathered
more efficiently and delivered into a higher-pressure system, processing plant or pipeline. Field
compression is typically used to allow a gathering system to operate at a lower pressure or provide
sufficient discharge pressure to deliver natural gas into a higher-pressure system. Since wells produce
at progressively lower field pressures as they deplete, field compression is needed to maintain
throughput across the gathering system.
9
•
Treating and dehydration. To the extent that gathered natural gas contains contaminants, such as water
vapor, carbon dioxide and/or hydrogen sulfide, such natural gas is dehydrated to remove the saturated
water and treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.
• 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. It is accomplished by controlling the temperature and pressure of the stream of mixed
NGLs in order to take advantage of the different boiling points and vapor pressures of separate products.
Fractionation systems typically exist either as an integral part of a gas processing plant or as a central
fractionator, often located many miles from the primary production and processing complex. A central
fractionator may receive mixed streams of NGLs from many processing plants. A fractionator can
fractionate one product or in a central fractionator, multiple products. We operate fractionation facilities at
certain processing facilities that separate ethane from the remainder of the y-grade stream. We also operate
central fractionation facilities that separate y-grade into propane, butanes and natural gasoline.
•
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. We
market NGLs domestically as well as for export to international markets. NGLs are transported via pipeline,
railcar, including unit trains, and truck. Each pipeline typically has storage capacity located both throughout
the pipeline network and at major market centers to help temper seasonal demand and daily operational or
supply-demand shifts. We also have caverns for propane storage in the northeastern United States.
Due to advances in well completion technology and horizontal drilling techniques, unconventional sources, such
as shale and tight sand formations, have become the most significant 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 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 OPERATING SEGMENTS
We conduct our operations in two segments which include L&S and G&P. As of December 31, 2018, 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, primarily in the Midwest and Gulf Coast regions of the United States. These assets
consist of a network of wholly and jointly-owned common carrier crude oil and refined product pipelines and
associated storage assets, refined product terminals, storage caverns, refinery-integrated 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 8,000 miles of pipeline across 17 states. Our storage caverns consist of
butane, propane, and liquefied petroleum gas (“LPG”) storage with a combined capacity of 4.175 million barrels
located in Neal, West Virginia; Woodhaven, Michigan; and Robinson, Illinois. Our terminal facilities for the
10
receipt, storage, blending, additization, handling and redelivery of refined petroleum products are located
primarily in the Midwest, Gulf Coast and Southeast regions of the United States, and have a combined total shell
capacity of approximately 23.7 million barrels. We also own tank farm assets at certain MPC refineries which
include approximately 56 million barrels storage capacity, in addition to 48 rail and truck racks, 21 docks, and
gasoline blenders. Our marine business owns and operates 23 boats, 256 barges, and 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. Our fuels distribution business provides MPC
with a broad range of scheduling and marketing services. Additionally, we 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. We have completed the Robinson Butane Cavern project, Texas City tank farm
expansion project, and major expansion work on the Ozark pipeline system as well as increasing our overall
pipeline capacity across a variety of other pipeline systems. Our L&S assets are integral to the success of MPC’s
operations.
We generate revenue in the L&S segment primarily by charging tariffs for 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. 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, 2018, approximately 92 percent of L&S segment revenue and
other income was generated from MPC. In this segment, we do not take ownership of the crude oil or products
that we transport and store for our customers, and we do not engage in the trading of any commodities. However,
we could be required to purchase or sell hydrocarbon-based volumes in the open market to make up negative or
positive imbalances.
G&P:
We operate several natural gas gathering systems with the scope of gathering services that we provide dependent
upon 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. The
capacities of these gathering systems are supported by long-term, fee-based agreements with major producer
customers. 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. 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
supported by long-term, fee-based agreements with our key producer customers. All NGLs, other than purity
ethane as discussed below, produced at our Cadiz Complex, Seneca Complex, Harmon Creek Complex,
Majorsville Complex, Mobley Complex and Sherwood Complex are gathered to the Houston Complex or to the
Hopedale Complex through a system of NGL pipelines to allow for fractionation into purity NGL products.
NGLs other than purity ethane produced at the Bluestone processing plant are also fractionated at the Bluestone
Complex into purity NGL products. We can also gather NGLs produced at a third party’s processing facilities to
the Houston, Hopedale and Bluestone Complexes for fractionation.
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As a result of the volume of natural gas production from the liquids-rich areas of the Marcellus and Utica Shales,
we recover ethane from the natural gas stream for 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 pipeline projects from many of our systems as follows:
• We transport purity ethane produced at the Majorsville Complex, Mobley Complex and Sherwood Complex
to the Houston Complex on a FERC pipeline.
• We deliver purity ethane to Sunoco Logistics Partners L.P.’s (“Sunoco”) Mariner West pipeline (“Mariner
West”) from the Harmon Creek Complex, Houston Complex and Bluestone Complex.
• We deliver purity ethane to Enterprise Products Partners L.P.’s Appalachia-to-Texas Express pipeline from
the Houston Complex and the Cadiz Complex.
•
•
Sunoco developed the Mariner East project (“Mariner East”), a pipeline and marine project that originates at
our Houston Complex. In December 2014, Mariner East began transporting propane to Sunoco’s terminal
near Philadelphia, Pennsylvania (“Marcus Hook Facility”) where it is loaded onto marine vessels and
delivered to international markets. In May 2016, Mariner East began transporting purity ethane in addition
to propane to the Marcus Hook Facility.
In December 2018, phase two of Mariner East, a pipeline from our Houston and Hopedale Complexes in
western Pennsylvania and eastern Ohio, respectively, began transporting propane and butane to the Marcus
Hook Facility where it is loaded onto marine vessels and delivered to domestic and international markets.
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. For a full list of our gas processing facilities, fractionation facilities, natural gas
gathering systems, NGL pipelines and natural gas pipelines see Item 2. Properties—Gathering and Processing.
Plant
Processing (MMcf/d):
Sherwood Complex
Smithburg Complex
Western Oklahoma
Complex
Torñado Complex
Apollo Complex
Preakness Complex
Fractionation (mbpd):
Hopedale Complex
De-ethanization (mbpd):
Sherwood Complex
Existing capacity
Planned capacity
expansion
Expected in-
service of
expansion
capacity
2,200
—
500
—
—
—
240
60
400
1,200
165
200
200
200
80
20
2019
TBD
2019
2019
2020
2021
2019
2019
Geographic Region
Marcellus Operations
Marcellus Operations
Southwest Operations
Southwest Operations
Southwest Operations
Southwest Operations
Marcellus/Utica Operations
Marcellus Operations
A significant portion of our business comes from a limited number of key customers. For the year ended
December 31, 2018, revenues earned from two customers are significant to the segment, each accounting for
15 percent of G&P operating revenues and seven percent of consolidated operating revenues, respectively.
12
The following table summarizes our key producer customers and attributes for each geographic region:
Marcellus Operations
Utica Operations
Southern Appalachian
Operations
Southwest Operations
Key Producer Customers Range Resources,
Antero Resources(1),
EQT(1), CNX,
Southwestern(1), HG
Energy(1), Penn
Energy and others
Ascent, Gulfport,
Antero Resources(1),
EQT and others
Diversified Gas and
Oil(1), and Gas
Supply Resources(1)
Newfield, BP,
Trinity, Chevron
USA and others
Volume Protection
67% of 2018
capacity contains
minimum volume
commitments
27% of 2018
capacity contains
minimum volume
commitments
24% of 2018
capacity contains
minimum volume
commitments
14% of 2018
capacity contains
minimum volume
commitments
Area Dedications
4.1 million acres
3.9 million acres
None
2.0 million acres
(1) We do not provide gathering services for these producer customers.
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, MPC has committed to provide us with minimum quarterly throughputs. 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 a Fuels Distribution
Services Agreement with MPC under which we provide scheduling and marketing services of MPC’s products.
The following table sets forth additional information regarding our transportation, terminal, fuels distribution,
and storage services agreements with MPC:
Agreement
Transportation Services (mbpd):
Crude pipelines
Product pipelines
Marine
Storage Services (mbbls):
Caverns
Tank Farms(3)
Terminal Services (mbbls)
Fuels Distribution Services (million gallons)
Initiation Date
Term (years)(4)
MPC minimum
commitment(1)
Various
Various
January 1, 2015
Various
Various
April 1, 2016
February 1, 2018
5-10
10-15
6
10-17
3-10
10
10
1,421
1,005
N/A(2)
4,175
75,740
131,530
23,449
(1) Quarterly 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
13
our terminal services agreements refer to quarterly terminal throughput in thousands of barrels.
Commitments for the Fuels Distribution Services Agreement refers to millions of gallons per year.
Minimum commitments on some agreements are reduced by any third-party throughput volumes.
(2) MPC has committed to utilize 100 percent of our available capacity of boats and barges.
(3) Volume shown represents total tank farm capacity in thousands of barrels (includes Refining Logistics tanks).
(4) Renewal terms on our agreements include multiple two to five-year terms for transportation services
agreements, one additional five-year term for our terminal services agreement, 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 our Fuels Distribution
Services Agreement. These renewals are automatic, unless terminated by either party.
Under all of our transportation services agreements, except for our marine agreement, if MPC fails to transport
its minimum throughput volumes during any quarter, then MPC will pay us a deficiency payment equal to the
volume of the deficiency multiplied by the tariff rate then in effect (the “Quarterly Deficiency Payment”). Under
these transportation services agreements, the amount of any Quarterly 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 any of the succeeding four or eight quarters, after which time any unused credits will expire.
Upon the expiration or termination of a transportation services agreement, MPC will have the opportunity to
apply any such remaining credit amounts until the completion of any such four-quarter or eight-quarter period, as
applicable. Remaining credits may be used against any volumes shipped by MPC on the applicable pipelines,
without regard to minimum volume commitments that may have been in place during the term of the agreement.
Under our terminal services agreement, if MPC fails to meet its minimum volume commitment during any
quarter, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the
contractual fee then in effect.
Under the Fuels Distribution Services Agreement, 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 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.
MPC’s obligations under these agreements will not terminate if MPC no longer controls our general partner.
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 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 four joint interest pipelines including Capline, Centennial, Lou-Lex and Muskegon. We
receive an operating fee for each of these pipelines, which is subject to adjustment for inflation. In addition, we
14
are reimbursed for specific costs associated with operating each pipeline. The length and renewals 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. Generally, 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.
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.
Other Agreements with MPC
We have an omnibus agreement with MPC that 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 services to us, as well as MPC’s indemnification of us for
certain matters, including certain environmental, title and tax matters. In addition, we will indemnify MPC for
certain matters under this agreement.
We also have various employee services agreements 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.
OUR RELATIONSHIP WITH MPC
One of our competitive strengths is our strategic relationship with MPC, which, with its recent 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. MPC’s midstream segment consists of both MPLX and ANDX, the latter of
which was acquired through the Andeavor acquisition. 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 64 percent of the outstanding common units of MPLX as of December 31, 2018. We believe MPC
will promote and support the successful execution of our business strategies given its significant interest in us
and its stated intention to grow its midstream business. This was demonstrated by the completion of the
dropdowns of MLP-qualifying assets and services in 2017 and 2018.
OUR G&P CONTRACTS WITH 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
15
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.
COMPETITION
Within our L&S segment, 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 products from MPC due to the increased availability of less
expensive products from other suppliers or for other reasons, MPC may ship only the minimum volumes (or pay
the shortfall payment if it does not ship the minimum volumes), which would cause a decrease in our revenues.
MPC competes with integrated petroleum companies, which have their own crude oil supplies and distribution
and marketing systems, as well as with independent refiners, many of which also have their own distribution and
marketing systems. MPC also competes with other suppliers that purchase refined products for resale.
Competition in any particular geographic area is affected significantly by the volume of products produced by
refineries in that area and by the availability of products and the cost of transportation to that area from distant
refineries.
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.
16
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. In the Marcellus and Utica regions, our early entrance in the liquids-rich corridors of the Marcellus
and Utica shale plays through our strategic gathering and processing agreements with key producers enhances
our competitive position to participate in the further development of these resource plays. In the Southern
Appalachia region, our operational experience of more than 20 years as the largest processor and fractionator and
our existing presence in the Appalachian Basin provide a significant competitive advantage. In the Southwest
region, our major gathering systems are located primarily in the heart of shale plays with significant long-term
growth opportunities and provide producers with low-pressure and fuel-efficient service, which differentiates us
from many competing gathering systems in those areas. 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.
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. However, we manage the seasonality impact through the execution of our marketing strategy. We
have access to up to 0.8 million barrels of propane storage capacity in the Southern Appalachia region provided
by an arrangement with a third party which provides us with flexibility to manage the seasonality impact.
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
17
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 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 FERC’s regulations require the rate and rules and
regulations tariffs to be publicly posted on the company’s website. 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 charges and may suspend the effectiveness of a newly filed rate or service for up
to seven months. A successful protest to a new rate or service could result in a petroleum pipeline paying
refunds, together with interest, for the period that the rate or 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 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.
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 in effect for the 365-day period
ending on the date of the passage of EPAct 1992 for interstate transportation service 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 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 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 PPI plus an adder that is currently set at 1.23 percent and is
reviewed every five years. The current adder will be in effect until June 30, 2021 or upon 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 their rates if those rates would otherwise
be above the 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
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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. 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. 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. The state
regulators could limit our ability to increase our rates or to set rates based on our costs or could order us to reduce
our rates and could 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. (“MarkWest Pioneer”), with respect to our Hobbs Pipeline and the Arkoma Connector
Pipeline. 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. Pursuant to FERC’s jurisdiction, existing rates and/or other tariff provisions may be
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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 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 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.
Gas-Electric Coordination. In 2015, FERC issued Order 587-W and adopted new standards designed to improve
coordination between the gas and electric industries. Among other things, the new standards revise the
nomination timelines used by interstate natural gas pipelines. Interstate natural gas pipelines were required to
implement the new standards in 2016. FERC continues to evaluate other measures to improve coordination
between the gas and electric industries, and the adoption of any such measures may impact FERC’s regulation of
jurisdictional natural gas pipelines.
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 gathering facilities
from the jurisdiction of FERC if the primary function of the facilities is gathering natural gas. There is, however,
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no bright-line test for determining the jurisdictional status of pipeline facilities. We own a number of facilities
that we believe establish the pipeline’s status as a gatherer 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, 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 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.
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. We have several NGL pipelines that carry NGLs owned by us between our
processing and fractionation facilities that cross state lines. We do not have FERC tariffs on file for these
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pipelines because we believe they are not subject to FERC requirements or that they would otherwise meet the
qualifications for a waiver from FERC’s filing and reporting requirements. We cannot, however, provide
assurance that FERC will not, at some point, either at the request of other entities or on its own initiative, assert
that some or all of these pipelines are subject to FERC requirements for interstate petroleum pipelines and not
exempt from its filing and reporting requirements. We also cannot provide assurance that such an assertion
would not adversely affect our results of operations. In the event FERC were to determine that these NGL
pipelines are subject to FERC requirements for common carrier pipelines or otherwise would not qualify for a
waiver from FERC’s applicable regulatory requirements, we would likely be required to file a tariff with FERC
for the pipelines, provide a cost justification for their transportation rates, and provide service to all potential
shippers without undue discrimination, and we may also be subject to fines, penalties or other sanctions.
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. Currently, PHMSA plans to move forward with final rulemaking on possible changes
to 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 will likely be implemented in 2019
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 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.
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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.
ENVIRONMENTAL REGULATION
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
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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 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.
Under the omnibus agreement, MPC has agreed to indemnify us for all known and certain unknown
environmental liabilities that are associated with the ownership or operation of our assets that we acquired from
MPC and due to occurrences on or before the closing of the Initial Offering. Indemnification for any unknown
environmental liabilities will be limited to liabilities due to occurrences on or before the closing of the Initial
Offering and identified prior to the fifth anniversary of the closing of the Initial Offering, and will be subject to
an aggregate deductible of $500,000 before we are entitled to indemnification for losses incurred. Any other
liabilities for which MPC has agreed to indemnify us are not subject to a deductible before we are entitled to
indemnification. There is no limit on the amount for which MPC has agreed to indemnify us under the omnibus
agreement once we meet the deductible, if applicable. Neither we nor our general partner have any contractual
obligation to investigate or identify any such unknown environmental liabilities. We have agreed to indemnify
MPC for events and conditions associated with the ownership or operation of our assets due to occurrences after
the closing of the Initial Offering and for environmental liabilities associated with or arising from our ownership
or operation of the assets on or after the closing of the Initial Offering, in each case, to the extent MPC is not
required to indemnify us for such liabilities. MPLX Pipe Line Holdings LLC (“Pipe Line Holdings”), has agreed
to indemnify MPC for events and conditions associated with the operations of the Pipe Line Holdings assets that
occur after the closing of the Initial Offering. Liabilities for which we and Pipe Line Holdings have agreed to
indemnify MPC pursuant to the omnibus agreement are not subject to a deductible before MPC is entitled to
indemnification. There is no limit on the amount for which we or Pipe Line Holdings has agreed to indemnify
MPC under the omnibus agreement.
Hazardous Substances and Wastes
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. The Comprehensive Environmental
Response, Compensation, and Liability Act, as amended (“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. Additionally, neighboring landowners and other third parties
can file claims for personal injury and property damage allegedly caused by hazardous substances or other
pollutants released into the environment. While we generate materials in the course of our operations that may be
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regulated as hazardous substances under CERCLA or similar state statutes, we do not believe that we have any
current material liability for cleanup costs under such laws or for third-party claims. We also may incur liability
under the Resource Conservation and Recovery Act, as amended (“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.
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 or for the storage, gathering and
transportation of crude oil. Although waste disposal practices within the NGL industry and other oil and natural
gas related industries have been enhanced and improved over the years, it is possible that petroleum
hydrocarbons and other non-hazardous or hazardous wastes may have been disposed of by prior owners or
operators on or under these various properties owned or leased by us during the operating history of those
facilities. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state
laws. Under these laws, 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.
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 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 assets we acquired from MPC in our Initial Offering, as
further described above under “General”. 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
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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.
Water Discharges
Our operations can result in the discharge of pollutants, including crude oil and refined products. Regulations
under the Water Pollution Control Act of 1972 (“Clean Water Act”), Oil Pollution Act of 1990 (“OPA-90”) and
analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters.
Such discharges are prohibited, except in accord with the terms of a permit issued by the EPA or the analogous
state agency. Spill prevention, control and countermeasure requirements under federal law and some state laws
require appropriate containment berms and similar structures to help prevent the contamination of navigable
waters in the event of a hydrocarbon tank spill, oil overflow, rupture or leak. For example, the Clean Water Act
requires us to maintain Spill Prevention Control and Countermeasure (“SPCC”) plans at many of our facilities.
We maintain numerous discharge permits for facilities and vessels as required under the National Pollutant
Discharge Elimination System program of the Clean Water Act and have implemented systems to oversee our
compliance efforts. Any unpermitted release of pollutants, including oil, NGLs or condensates, could result in
administrative, civil and criminal penalties as well as significant remedial obligations. In addition, the Clean
Water Act and analogous state law may also require individual permits or coverage under general permits for
discharges of storm water from certain types of facilities, but these requirements are subject to several
exemptions specifically related to oil and natural gas operations and facilities. The Clean Water Act also
prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a
permit. We conduct regular review of the applicable laws and regulations, and maintain discussions with the
various federal, state and local agencies with regard to the application of those laws and regulations to our
facilities, including the permitting process and categories of applicable permits for storm water or other
discharges, stream crossings and wetland disturbances that may be required for the construction or operation of
certain of our facilities in the various states.
In addition, the transportation and storage of crude oil and refined products over and adjacent to water involves
risk and subjects us to the provisions of OPA-90 and related state requirements. Among other requirements,
OPA-90 requires the owner or operator of a tank vessel, a facility or a pipeline to maintain an emergency plan to
respond to releases of oil or hazardous substances. Also, in case of any such release, OPA-90 requires the
responsible company to pay resulting removal costs and damages. OPA-90 also provides for civil penalties and
imposes criminal sanctions for violations of its provisions. We operate facilities at which releases 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 SPCC plans for facilities subject to Clean Water Act
SPCC requirements.
Construction or maintenance of our plants, compressor stations, pipelines, barge dock and storage facilities may
impact wetlands, which are also regulated under the Clean Water Act 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
Clean Water Act 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.
Air Emissions
The Clean Air Act 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.
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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. For example, the EPA issued final regulations in October
2015 to revise the National Ambient Air Quality Standard for ozone to 70 parts per billion for both the eight-hour
primary and secondary standards protective of public health and public welfare. In actions dated April 30, 2018,
and July 25, 2018, the EPA finalized nonattainment designations for certain areas under the lower primary ozone
standard. For areas designated nonattainment, states will be required to adopt State Implementation Plans
(“SIPs”) for nonattainment areas. These SIPs may include NOx and/or 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. In 2016, the EPA promulgated regulation regarding performance standards for methane emissions from
new and modified oil and gas production and natural gas processing and transmission facilities, which could
require additional capital expenditures, increase our operating costs or otherwise restrict our operations. In
September 2018, the EPA proposed targeted improvements to the 2016 New Source Performance Standards for
the oil and gas industry that are meant to streamline implementation of the rules. Additionally, the EPA finalized
regulations to revise existing refinery air emissions standards, which require additional controls, lower emission
standards and require ambient air monitoring. These revised refinery standards affect refineries, including MPC’s
refineries from which we receive significant revenues. To the extent capital expenditures required to comply with
new legislative and regulatory requirements have a material effect on MPC or our other customers, they could
have a material effect on our business and results of operations.
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
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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 including the imposition of a carbon tax. The EPA’s 2016 New
Source Performance Standards 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 the EPA continues to review and consider further changes to these standards. 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.
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.
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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, 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. 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.
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.
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.
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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 real-time transient leak detection system monitors throughput 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.
Pipeline Permitting
Pipeline construction and expansion is subject to government permitting and involves numerous regulatory
environmental, political and legal uncertainties, most of which are beyond our control. We believe our operations
are in substantial compliance with our permits.
Facility Safety
At manned facilities, the workplaces associated with the processing and storage facilities and the pipelines we
operate are also 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 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, which are often unclear, 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.
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.
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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 specification
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.
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 4,500 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.
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Item 1A. Risk Factors
You should carefully consider each of the following risks and all the other information set forth elsewhere 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 $13.9 billion as of December 31, 2018. We may incur
significant debt obligations in the future, including under our loan agreement with MPC. Our existing and 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. Our funds available for operations, business opportunities and distributions to unitholders will also
be reduced by that portion of our cash flow required to make interest payments on our debt.
• 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 or delay 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 are dependent upon production from oil and natural gas reserves and wells
owned by our producer customers, which 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.
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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 new oil or natural gas reserves are discovered in
areas served by our assets, producers may choose not to develop those reserves. If we are not able to obtain new
supplies of oil or natural gas to replace the natural decline in volumes from existing wells, throughput on our
pipelines and the utilization rates of our facilities would decline, which could have a material adverse effect on
our business, results of operations and financial condition and could reduce our ability to make distributions to
our unitholders.
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 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.
Global economic conditions may have adverse impacts on our business and financial condition and adversely
impact our ability to access capital markets on acceptable terms.
Changes in economic conditions could adversely affect our financial condition and results of operations. A
number of economic factors, including, but not limited to, 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 and higher tax rates 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 business plan and growth strategy may require access to new capital. An increased cost of capital could
impair our ability to grow, our ability to make distributions to unitholders at our intended levels and trigger us
to impair our goodwill and intangible assets.
Our ability to successfully operate our business, generate sufficient cash to pay the quarterly cash distributions to
our unitholders and to allow for growth of our business and the growth of our distributions is subject to a number
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of risks and uncertainties, including economic and competitive factors beyond our control, which may impair our
access to new capital. If the cost of capital becomes too expensive, we may not be able to raise the necessary
funds from the capital markets on satisfactory terms, if at all. We may be required to consider alternative
financing strategies such as the formation of joint ventures or the sale of non-strategic assets, which may not
provide the necessary capital, and our ability to develop or acquire strategic and accretive assets and finance
growth projects will be limited. Factors that influence our cost of capital include market conditions, including our
common unit price and the resultant distribution yield. A significant decline in oil prices can impact our common
unit price. When the price of our common units decreases, the resultant distribution yield increases, and our cost
of capital increases accordingly. A significant drop in our unit price could also trigger an impairment of our
goodwill and intangible assets.
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.
Our inability, or limited ability, to control certain aspects of management of joint venture legal entities in which
we have a partial ownership interest means that we may be unable to control, and may not receive, the amount of
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cash we expect to be distributed to us, which could adversely affect our ability to pay the minimum quarterly
distribution to our unitholders. In addition, for entities where we have a noncontrolling ownership interest, or for
entities that we operate but in which the noncontrolling interest owners have participative rights, we will be
unable to control ongoing operational or other decisions, including the incurrence of capital expenditures that we
may be required to fund, the incurrence of debt, or the pursuit of certain projects that we may want to pursue.
Certain of our joint venture partners have the option to not make, or may otherwise cease making, capital
contributions, so we may be required to fully fund capital or operating expenditures for the joint venture. For
joint ventures we operate, we may not receive adequate reimbursement for all of the expenditures we incur to
operate the joint venture.
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
periods when we record net losses and may not make distributions during periods when we record net income.
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 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 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 and/or give the
producer the right to repurchase certain assets and terminate their contracts with us if construction deadlines are
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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 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.
Due to capacity, market and other constraints relating to the growth of our business, we may experience
difficulties in the execution of our business plan, which may increase our costs and reduce our revenues and
cash available for distribution.
The successful execution of our business strategy is impacted by a variety of factors, including our ability to
grow our business and satisfy our customers’ requirements for gathering, processing, fractionation, marketing,
transportation and storage services. Our ability to grow our business and satisfy our customers’ requirements may
be adversely affected by a variety of factors, including the following:
• more stringent permitting and other regulatory requirements;
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•
a limited supply of qualified fabrication and construction contractors, which could delay or increase the cost
of the construction and installation of our facilities or increase the cost of operating our existing facilities;
unexpected increases in the volume of oil, natural gas, NGLs and refined products being delivered to our
facilities, which could adversely affect our ability to expand our facilities in a manner that is consistent with
our customers’ production or delivery schedules;
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•
•
changes in, or inability to meet, downstream gas, NGL, crude oil or refined product pipeline quality
specifications, which could reduce the volumes of gas, NGLs, crude oil and refined products that we
receive;
scheduled maintenance, unexpected outages or downtime at our facilities or at upstream or downstream
third-party facilities, which could reduce the volumes of oil, gas, NGLs and refined products that we
receive; and
• market and capacity constraints affecting downstream oil, natural gas, NGL and refined products facilities,
including limited gas and NGL capacity downstream of our facilities, limited railcar and NGL pipeline
facilities and reduced demand or limited markets for certain NGL or refined products, which could reduce
the volumes of oil, gas, NGLs and refined products that we receive and adversely affect the pricing received
for NGLs.
If we are unable to successfully execute our business strategy, then our operating and capital expenditures may
materially increase and our revenues and cash available for distribution may be adversely affected.
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 17.
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.
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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, 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:
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•
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.
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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.
Although we obtain our supply of oil, natural gas, refinery off-gas, NGLs and refined products from numerous
third-party producers and suppliers, a significant portion comes from a limited number of key producers/
suppliers, who are usually under no obligation to deliver a specific volume to our facilities. If these key suppliers,
or a significant number of other 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 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
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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 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.
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.
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.
Our future growth may depend in part on our ability to integrate our future acquisitions. We cannot guarantee
that we will successfully integrate assets acquired in dropdowns from MPC, or any other acquisitions, into our
existing operations, or that we will achieve the desired profitability and anticipated results from such
acquisitions. Failure to achieve such planned results could adversely affect our operations and cash available for
distribution.
Significant acquisitions, including any potential transaction with ANDX, present potential risks including:
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•
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inaccurate assumptions about future synergies, revenues, capital expenditures and operating costs;
an inability to successfully integrate 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;
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•
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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 incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset
devaluation or restructuring charges; and
the loss of customers or key employees from the acquired businesses.
Unexpected costs and challenges may arise whenever businesses with different operations or management are
combined, and we may experience unanticipated delays in realizing the benefits of an acquisition, if at all. Our
capitalization and results of operation may also change significantly, and unitholders will not have the
opportunity to evaluate the economic, financial and other relevant information that we may consider in
determining the application of these funds and other resources.
We are indemnified for liabilities arising from an ongoing remediation of property 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.
The prior third-party owner or operator of our Kenova, Boldman, Cobb, Kermit and Majorsville facilities has
been or is currently involved in investigatory or remedial activities with respect to the real property underlying
those facilities pursuant to regulatory orders with the EPA and various state regulatory agencies. The third party
or its successor in interest has agreed to retain sole liability and responsibility for, and to indemnify us against,
any environmental liabilities associated with these regulatory orders or the real property underlying 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. In addition, the previous 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 AMD with
respect to that real property. The third party has accepted liability and responsibility for, and has agreed to
indemnify us against, any environmental liabilities associated with the AMD that are not exacerbated by us in
connection with our operations. MPC has also agreed to indemnify us for certain environmental liabilities related
to assets contributed to us by MPC in our Initial Offering or sold to us subsequently. Our results of operation 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.
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, which we refer to collectively as 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.
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Risks Relating to our Industry
Certain of our pipelines may be subject to federal or state rate and service regulation, and the imposition and/
or 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 and/or service regulations by FERC and/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 and/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.
Most of our natural gas and NGL pipelines are generally not subject to regulation by FERC. The NGA
specifically exempts natural gas gathering systems from FERC’s jurisdiction. Yet, such operations 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.
We cannot assure unitholders that FERC will not at some point determine that some or all of such pipelines are
within its jurisdiction, and regulate such services, which could limit the rates that we may charge, increase our
costs of operation, and subject us to fines, penalties or other sanctions. 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.
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.
MPC has agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in
effect during the term of our transportation services agreements with MPC. However, this agreement does not
prevent other shippers or interested persons from challenging our tariff rates or proration rules; nor does it
prevent regulators from reviewing our rates and tariffs on their own initiative. At the end of the term of each of
our transportation services agreements with MPC, if the agreement is not renewed, MPC will be free to
challenge, or to cause other parties to challenge or assist others in challenging, our tariffs in effect at that time.
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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.
If we are unable to obtain new rights-of-way or other property rights, or the cost of renewing existing
rights-of-way or property rights increases, then we may be unable to fully execute our growth strategy, which
may adversely affect our operations and cash flows available for distribution to unitholders.
The construction of additions to, or expansions of, our facilities may require us to obtain new rights-of-way or
other property rights prior to constructing new plants, pipelines and other transportation and storage facilities.
We may be unable to obtain such rights-of-way or other property rights to connect new natural gas supplies to
our existing gathering lines, to connect our existing or future facilities to new natural gas, NGL, crude oil or
refined product markets, or to capitalize on other attractive expansion opportunities. Additionally, it may become
more expensive for us to renew existing rights-of-way or other property rights, including the renewal of leases
for land on which our processing facilities are located. If the cost of obtaining new or renewing existing
rights-of-way or other property rights increases, it may adversely affect our operations and cash flows available
for distribution to unitholders. If we are unable to renew a lease or other land rights for land on which any of our
processing or other facilities are located, we may be required to remove our facilities from that site, which could
require us to incur significant costs and expenses, disrupt our operations, and adversely affect our cash available
for distribution.
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.
Our revolving credit facility and our loan agreement with MPC Investment LLC (“MPC Investment”) have
variable interest rates. The United States Federal Reserve has gradually raised the federal funds rate since 2015
and may continue to raise interest rates in the future. 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. Furthermore, 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.
Our business is subject to laws and regulations with respect to environmental, occupational safety and health,
nuisance, zoning, land use and other regulatory matters, and the violation of, or the cost of compliance with,
such laws and regulations could adversely affect our operations and cash flows available for distribution to
our unitholders.
Numerous governmental agencies enforce federal, regional, state and local laws and regulations on a wide range
of environmental, occupational safety and health, nuisance, zoning, land use, endangered species and other
regulatory matters. We could be adversely affected by increased costs due to stricter pollution-control
requirements or liabilities resulting from non-compliance with operating or other regulatory permits. Strict joint
and several liability may be incurred without regard to fault, or the legality of the original conduct, under certain
of the environmental laws for remediation of contaminated areas, including CERCLA, RCRA and analogous
state laws. Private parties, including the owners of properties located near our facilities or through which our
pipelines pass, also may have the right to pursue legal actions to enforce compliance, as well as seek damages for
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non-compliance, with environmental laws and regulations or for personal injury or property damage. New, more
stringent environmental laws, regulations and enforcement policies, the listing of additional species as
endangered or threatened or the designation of new critical habitat for listed species, and new, amended or
re-interpreted permitting requirements, policies and processes, might adversely affect our operations and
activities, and existing laws, regulations and policies could be reinterpreted or modified to impose additional
requirements, delays or constraints on our construction of facilities or on our operations, increase our operating
costs, or require our facilities to be aggregated into one air emissions permit or permit application. In addition,
government disruptions, such as a U.S. federal government shutdown, may delay or halt the granting and renewal
of permits, licenses and other items required by us and our customers to conduct our business. We have
experienced construction delays related to these factors as a result of the U.S. federal government’s recent
shutdown. Federal, state and local agencies also could impose additional health and safety requirements, any of
which could increase our operating costs. Local governments may adopt more stringent local permitting and
zoning ordinances that impose additional time, place and manner restrictions, delays or constraints on our
activities to construct and operate our facilities, require the relocation of our facilities, prevent or restrict the
expansion of our facilities, or increase our costs to construct and operate our facilities, including the construction
of sound mitigation devices.
In addition, we face the risk of accidental releases or spills associated with our operations, which could result in
material costs and liabilities, including those relating to claims for damages to property, natural resources and
persons, environmental remediation and restoration costs and governmental fines and penalties. Our failure to
comply with or alleged non-compliance with environmental or safety-related laws and regulations could result in
administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and even
injunctions that restrict or prohibit some or all of our operations. 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 legislation or regulations restricting emissions of GHGs or methane could result in increased
operating costs, reduced demand for our services and adversely affect the cash flows available for distribution
to our unitholders.
As a consequence to an EPA administrative conclusion that GHGs present an endangerment to public health and
the environment, the EPA and some states have adopted or are considering regulations aimed at regulating GHG
emissions from certain stationary sources that are potential sources of certain principal, or criteria, pollutant
emissions. For example, on June 3, 2016, the EPA finalized new regulations that set methane emission standards
for new and modified oil and gas production and natural gas processing and transmission facilities. The
regulations were part of the prior Administration’s efforts to reduce methane emissions from the oil and gas
sector by up to 45 percent from 2012 levels by 2025. In September 2018, the EPA proposed targeted
improvements to the 2016 New Source Performance Standards for the oil and gas industry that are meant to
streamline implementation of the rules. Because the issue of climate change continues to receive scientific and
political attention, there is also the potential for further legislation or regulation that could result in increased
operating costs and/or reduced demand for the oil, natural gas, NGLs and products we gather, process,
fractionate, store and transport.
To the extent that state or federal legislation is passed or regulations are imposed to reduce or regulate GHG
emissions, we may experience delays in the construction and installation of new facilities due to more stringent
permitting requirements, incur additional costs to reduce methane emissions associated with our operations or be
required to aggregate the emissions from separate facilities for permitting purposes or to relocate one or more of
our facilities due to more stringent emissions standards. If we incur additional costs to reduce methane emissions
associated with our operations, it is possible that we may be able to pass through a portion of those costs to our
producer customers to the extent permitted under our contractual arrangements. To the extent that we incur
additional costs or delays, our cash available for distribution may be adversely affected.
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Our producer customers or suppliers may also experience similar issues, which may adversely impact their
drilling schedules and production volumes and reduce the volumes delivered to us. 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.
Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing, as well as
governmental reviews of such activities, could delay or impede oil or gas production or result in reduced
volumes available for us to gather, transport, store, process and fractionate.
We do not conduct hydraulic fracturing operations, but we do provide gathering, processing, transportation,
storage and fractionation services with respect to natural gas, oil, NGLs and refined products produced by our
customers as a result of such operations. Hydraulic fracturing is an important and common practice that is used to
stimulate production of hydrocarbons, particularly natural gas, from tight formations such as shales. The process
involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture
the surrounding rock and stimulate production. The process is typically regulated by state oil and gas
commissions but several federal agencies have asserted regulatory authority over certain aspects of the process,
including the EPA and BLM. In addition, Congress has from time to time considered legislation to provide for
additional regulation of hydraulic fracturing. Also, several states have adopted or are considering legal
requirements that could impose more stringent permitting, disclosure and well construction requirements on
hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions
regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in
particular. If new 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 and oil wells in shale
formations and increase our producers’ costs of compliance. This could significantly reduce the volumes
delivered to us, which could adversely impact our earnings, profitability and cash flows.
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.
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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.
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 over 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.
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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,
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.
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We rely on the performance of our information technology systems, and the failure of any information
technology system, including a failure due to a cybersecurity breach, could have an adverse effect on our
results of operations, financial condition and cash flows.
Our business has become increasingly dependent upon digital technologies, including information systems,
infrastructure and cloud applications for the gathering and processing of natural gas, the gathering, fractionation,
transportation and marketing of NGLs, and the gathering, storage and transportation of crude oil and refined
products. We are heavily dependent on our information technology systems, including our network infrastructure
and cloud applications, for the 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, investor and payroll data, and to manage or support a variety of business processes, including our
supply chain, pipeline operations, gathering and processing operations, financial transactions, banking and
numerous other processes and transactions. These information systems involve data network and
telecommunications, Internet access and website functionality, and various computer hardware equipment and
software applications, including those that are critical to the safe operation of our business. Our systems and
infrastructure are subject to damage or interruption from a number of potential sources including natural
disasters, software viruses or other 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.
To protect against such attempts of unauthorized access or attack, we have implemented multiple layers of
cybersecurity protections, infrastructure protection technologies, disaster recovery plans and employee training.
While we have invested significant amounts in the protection of our technology systems and maintain what we
believe are adequate security controls over personally identifiable investor and contractor data, there can be no
guarantee such plans, to the extent they are in place, will be effective. 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. Unauthorized disclosure of sensitive or personally identifiable information, including by cyber-
attacks or other security breach, could cause loss of data, give rise to remediation or other expenses, 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 investigations, which could have an adverse
effect on our reputation, business, financial condition, results of operations and cash flows available for
distribution to our unitholders. State and federal cybersecurity legislation could also impose new requirements,
which could increase our cost of doing business.
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.
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Risks Relating to the Business and Operations of MPC
MPC accounted for a large portion of our revenues in 2018 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 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, 2018, 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 46 percent of our revenues and other income, including 92 percent of the revenues and other
income 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, the most
significant of 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 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 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
affect changes at MPC or acquire control of the company, which could impact the pursuit of MPC’s business
strategies. Campaigns by stockholders to affect 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.
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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 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 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. In addition, the initial terms of MPC’s obligations under those agreements range from three to
17 years. 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 the following four quarters or eight quarters 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 succeeding four or
eight quarters, 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
applicable four or eight quarter 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, 2018, MPC had consolidated long-term
indebtedness of approximately $28 billion, of which $9 billion was a direct obligation of MPC. The covenants
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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.
MPC’s long-term credit ratings are currently investment grade. 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 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 law
may subject us to additional entity-level taxation by individual states. Imposition of any such additional taxes on
us will 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.
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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.
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. 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. 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.
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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 23 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
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.
53
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.
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 64 percent of our outstanding common units as of
February 15, 2019. Although our general partner has a duty to manage us in a manner that is not adverse to the
best interests of our partnership and our unitholders, 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
54
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;
•
•
•
•
•
•
•
•
•
•
•
•
our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by our general
partner with contractual standards governing its duties, limiting our general partner’s liabilities and
restricting the remedies available to our unitholders for actions that, without the limitations, might constitute
breaches of fiduciary duty;
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;
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.
55
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
expect to rely primarily upon 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
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
56
•
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 15, 2019, our general partner and its affiliates owned approximately 64 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 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-
57
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 agreement or our employee services agreements, our general partner
determines the amount of these expenses. Under the terms of the omnibus agreement, 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 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 15, 2019, MPC held 504,701,934 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.
58
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.
Neither our Partnership Agreement nor our omnibus agreement will prohibit MPC or any other affiliates of our
general partner, including ANDX, 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.
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
59
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
60
Item 2. Properties
LOGISTICS AND STORAGE
Crude Oil Pipelines
The following table sets forth certain information regarding our crude oil pipelines, as of December 31, 2018.
Pipeline Name
Patoka to Lima and Canton crude
pipelines
Diameter
(inches)
Length
(miles)
Capacity
(mbpd)(1)
Associated MPC Refineries
Patoka, IL to Lima, OH
Lima OH, to Canton, OH
20”/22”
12”/16”
Subtotal
Catlettsburg and Robinson crude
pipelines
Patoka, IL to Robinson, IL
Patoka, IL to Catlettsburg, KY
20”
24”/20”
Subtotal
Detroit crude pipelines
Samaria, MI to Detroit, MI
Romulus, MI to Detroit, MI(2)
Subtotal
Ozark crude pipeline
Cushing, OK to Wood River, IL
Wood River to Patoka crude pipelines
Wood River, IL to Patoka, IL
Roxanna, IL to Patoka, IL(3)
Subtotal
St. James to Garyville crude pipeline
St. James, LA to Garyville, LA
Inactive pipelines
Total
16”
16”
22”
22”
12”
30”
302
153
455
78
406
484
44
17
61
433
57
58
115
20
49
267 Detroit, MI; Canton, OH
84 Canton, OH
351
245 Robinson, IL
270 Catlettsburg, KY
515
117 Detroit, MI
80 Detroit, MI
197
360 All Midwest refineries
360 All Midwest refineries
94 All Midwest refineries
454
620 Garyville, LA
N/A
1,617
2,497
(1) Capacity shown is 100 percent of the capacity of these pipelines and based on physical barrels.
(2)
Includes approximately 16 miles of pipeline leased from a third party.
(3) A portion of this pipeline system is leased from a third party.
61
The following table sets forth certain information regarding crude oil pipelines in which we have a joint interest,
as of December 31, 2018.
Pipeline Name
Bakken Pipeline
Dakota Access Pipeline
Energy Transfer Crude Oil Company (ETCO) pipeline
Subtotal
Illinois Extension
LOOP
LOCAP
Total
Diameter
(inches)
Length
(miles)
30”
30”
24”
48”
48”
1,172
749
1,921
168
48
57
2,194
Ownership
Interest
9.2%
35%
40.7%
58.5%
Our crude oil pipeline and related assets are strategically positioned to support diverse and flexible crude oil
supply options for MPC’s Gulf Coast and Mid-Continent refineries, which receive imported and domestic crude
oil through a variety of sources. Imported and domestic crude oil is transported to supply hubs in Wood River
and Patoka, Illinois 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. Our major crude oil pipelines are connected to these supply hubs and
transport crude oil to refineries owned by MPC and third parties.
62
Product Pipelines
The following table sets forth certain information regarding our product pipelines as of December 31, 2018.
Pipeline Name
Louisiana products pipelines
Diameter
(inches)
Length
(miles)
Capacity
(mbpd)(1) Associated MPC Refineries
Garyville, LA to Zachary, LA
Zachary, LA to connecting pipelines(4)
20”
36”
Subtotal
Texas products pipelines
Texas City, TX to Pasadena, TX
Pasadena, TX to connecting pipelines(4)
16”
36”/30”
Subtotal
Ohio products pipelines
Bellevue 4” Products
Canton, OH to East Sparta, OH(2)(3)
Columbus Locals(4)
Cornerstone Pipeline
Cadiz, OH to East Sparta, OH(3)
East Sparta, OH to Canton, OH
East Sparta, OH to Heath, OH(3)
East Sparta, OH to Midland, PA
Heath, OH to Dayton, OH
Heath, OH to Findlay, OH or Lima, OH
Kenova, WV to Columbus, OH
Lima Pump-Out(4)
RIO
Toledo, OH to Steubenville, OH
Subtotal
Illinois products pipelines
Robinson, IL to Lima, OH
Robinson, IL to Louisville, KY
Robinson, IL to Mt. Vernon, IN(5)
Wood River, IL to Clermont, IN
Wabash Pipeline
4”
6”
12”
16”
8”
8”
8”
6”
8”/12”
14”
10”
8”
4”/6”
10”
16”
10”
10”
West leg—Wood River, IL to Champaign, IL
East leg—Robinson, IL to Champaign, IL
Champaign, IL to Hammond, IN(6)
12”
12”
16”/12”
Subtotal
Michigan product pipelines
Detroit LPG—Woodhaven #1
Detroit LPG—Woodhaven #2
Subtotal
Kentucky products pipeline
4”
4”
Louisville, KY to Louisville International Airport
Louisville, KY to Lexington, KY(7)
8”/6”
8”
Subtotal
Tennessee products pipeline
Nashville Bordeaux to Nashville 51st(8)
Inactive pipelines(9)
Total
70
2
72
40
3
43
3
17
1
50
9
81
62
108
149
150
N/A
251
54
935
250
129
79
317
130
86
140
1,131
12
14
26
14
87
101
389 Garyville, LA
N/A Garyville, LA
389
215 Galveston Bay, TX
N/A Galveston Bay, TX
215
5 N/A
73 Canton, OH
N/A N/A
198 Canton, OH
40 Canton, OH
47 Canton, OH
32 Canton, OH
24
Catlettsburg, KY;
Canton, OH
Catlettsburg, KY;
Canton, OH
63
74 Catlettsburg, KY
N/A N/A
33 N/A
32 N/A
621
51 Robinson, IL
82 Robinson, IL
77 Robinson, IL
48 Robinson, IL
71 Robinson, IL
99 Robinson, IL
85 Robinson, IL
513
6 N/A
6 N/A
12
29 Robinson, IL
37 N/A
66
8”/12”
2
140
2,450
60 N/A
N/A
1,876
63
(1) Capacity shown is 100 percent of the capacity of these pipelines and based on physical barrels.
(2) Consists of two separate approximately 8.5 mile pipelines.
(3)
This pipeline is bi-directional.
(4) Capacity not shown, as the pipeline is designed to meet outgoing capacity for connecting pipelines.
(5)
This pipeline is leased from a third party.
(6) Capacity not shown for 16 miles on this pipeline due to complexities associated with bi-directional
capability.
(7) We own a 65 percent undivided joint interest in the Louisville, KY to Lexington, KY system.
(8)
This pipeline is leased from a third party.
Includes 77 miles of pipeline leased from a third party.
(9)
The following table sets forth certain information regarding a products pipeline in which we have a joint interest,
as of December 31, 2018.
Pipeline Name
Explorer Pipeline
Total
Diameter
(inches)
12”-28”
Length
(miles)
1,830
1,830
Ownership
Interest
24.5%
Our product pipelines are strategically positioned to transport products from certain MPC refineries to MPC and
MPLX marketing operations, as well as those of third parties. These pipelines also supply feedstocks to MPC’s
Gulf Coast and Mid-Continent refineries. These 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, 2018.
Owned and Operated Terminals(1)
Number of
Terminals
Tank Shell Capacity
(thousand barrels)
Number of Tanks
Number of Loading
Lanes
Alabama
Florida
Georgia
Illinois
Indiana
Kentucky
Louisiana
Michigan
North Carolina
Ohio
Pennsylvania
South Carolina
Tennessee
West Virginia
Total
2
4
4
4
6
6
1
8
4
12
1
1
4
2
59
443
3,422
998
1,221
3,229
2,587
97
2,440
1,509
3,218
390
371
1,149
1,587
22,661
16
65
31
33
60
56
7
73
34
101
12
8
30
25
551
4
22
9
14
17
25
2
26
13
28
2
3
12
2
179
(1) MPLX also operates one leased terminal and has partial ownership interest in two terminals, with a
combined tank shell capacity of 1,068 mbbls.
64
Marine Assets
The following table sets forth certain information regarding our marine assets as of December 31, 2018. The
marine business currently has an associated transportation service agreement with MPC.
Marine Vessels
Inland tank barges:
Less than 25,000 barrels
25,000 barrels and over
Total
Inland towboats:
Less than 2,000 horsepower
2,000 horsepower and over
Total
Number of
Boats and
Barges
Capacity
(thousand barrels)
Associated MPC Refineries
Catlettsburg, KY; Garyville, LA
931
5,738
6,669
61
195
256
2
21
23
Catlettsburg, KY; Garyville, LA
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.
The MRF 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.
Refinery Assets
The following table outlines the tankage, rail and truck racks, and docks owned by us at MPC’s refineries as of
December 31, 2018. Each of the following assets are currently included in storage services agreements with
MPC.
MPC Refinery
Galveston Bay, Texas City, Texas
Garyville, Louisiana
Catlettsburg, Kentucky
Robinson, Illinois
Detroit, Michigan
Canton, Ohio
Total
Other L&S Assets
Tank Capacity
(mbbls)
Rail Racks
Truck Racks
Docks
18,468
17,320
5,177
6,987
4,998
2,700
55,650
1
3
4
5
5
4
22
5
5
4
4
4
4
26
14
6
—
—
1
—
21
The following table sets forth certain information regarding our other midstream assets as of December 31, 2018,
each of which currently has an associated transportation services agreement or storage services agreement with
MPC.
Asset Name
LOOP(2)
Wood River Barge Dock
Mt. Airy Terminal(3)
Canton Crude Truck Unload
Tank Farms(4)
Caverns
Capacity (1)
Associated MPC Refineries
N/A N/A
78 mbpd Garyville, LA
3,979 mbbls Garyville, LA
2.7 mbpd Canton, OH
20,090 mbbls N/A
4,175 mbbls N/A
65
(1) Capacity for Tank Farms is shown as 100 percent of the available storage capacity. Capacity for the Wood
River 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.
(3)
The Mt. Airy Terminal includes 34 tanks, 2-bay ethanol loading rack, barge dock, ship dock and 7 dock
loading lines.
(4) We own and operate 16 tank farms and operate two leased tank farms.
GATHERING AND PROCESSING
The following tables set forth certain information relating to our gas processing facilities, fractionation facilities,
natural gas gathering systems, NGL pipelines and natural gas pipelines as of and for the year ended
December 31, 2018. All throughputs and utilizations included are weighted-averages for days in operation.
Gas Processing Complexes
Plant
Marcellus Shale:
Bluestone Complex
Harmon Creek Complex
Houston Complex
Majorsville Complex
Mobley Complex
Sherwood Complex(2)
Total Marcellus Shale
Utica Shale:
Cadiz Complex(3)
Seneca Complex(3)
Total Utica Shale
Southern Appalachia:
Kenova Complex(4)
Boldman Complex(4)
Cobb Complex
Kermit Complex(4)(5)
Langley Complex
Total Southern Appalachia(5)
Southwest:
Carthage Complex
Western Oklahoma Complex
Hidalgo Complex
Argo Complex
Javelina Complex
Total Southwest(6)
Total Gas Processing
Location
Design
Throughput
Capacity (MMcf/d)
Natural Gas
Throughput(1)
(MMcf/d)
Utilization of
Design
Capacity(1)
Butler County, PA
Washington County, PA
Washington County, PA
Marshall County, WV
Wetzel County, WV
Doddridge County, WV
Harrison County, OH
Noble County, OH
Wayne County, WV
Pike County, KY
Kanawha County, WV
Mingo County, WV
Langley, KY
Panola County, TX
Custer and Beckham
Counties, OK
Culberson County, TX
Culberson County, TX
Corpus Christi, TX
410
200
720
1,270
920
2,200
5,720
525
800
1,325
160
70
65
32
325
620
600
500
200
200
142
392
12
528
1,072
708
1,736
4,448
472
414
886
96
30
19
N/A
102
247
423
420
199
39
107
1,642
9,307
1,188
6,769
96%
75%
78%
92%
77%
94%
88%
90%
52%
67%
60%
43%
29%
N/A
31%
40%
71%
91%
100%
21%
75%
75%
79%
(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.
66
(2)
(3)
The Sherwood Complex is partially owned by Sherwood Midstream LLC (“Sherwood Midstream”). We
account for Sherwood Midstream as an equity method investment. See discussion in Item 8. Financial
Statements and Supplementary Data—Note 5.
The Cadiz and Seneca Complexes are owned by MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”).
We account for MarkWest Utica EMG as an equity method investment. See discussion in Item 8. Financial
Statements and Supplementary Data—Note 5.
(4) A portion of the gas processed at the Boldman plant, and all of the gas processed at the Kermit plant, is
(5)
further processed at the Kenova plant to recover additional NGLs.
The Kermit processing plant is operated by a third party solely to prevent liquids from condensing in the
gathering and transmission pipelines upstream of our Kenova plant. We do not receive Kermit gas volume
information but do receive all of the liquids produced at the Kermit Complex. As such, the design
throughput capacity and the natural gas throughput has been excluded from the subtotal.
(6) Centrahoma Processing LLC’s processing capacity of 550 MMcf/d and actual throughput of 249 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
Facility
Marcellus Shale:
Bluestone Complex(2)
Houston Complex(2)
Total Marcellus Shale
Hopedale Complex(2)(3)
Utica Shale:
Ohio Condensate Complex(4)
Total Utica Shale
Southern Appalachia:
Siloam Complex(5)
Total Southern Appalachia
Southwest:
Javelina Complex
Total Southwest
Total C3+ Fractionation and
Condensate Stabilization
Location
Design
Throughput
Capacity (mbpd)
NGL
Throughput(1)
(mbpd)
Utilization of
Design
Capacity(1)
Butler County, PA
Washington County, PA
Harrison County, OH
Harrison County, OH
South Shore, KY
Corpus Christi, TX
47
60
107
240
23
23
24
24
11
11
22
61
83
158
12
12
15
15
11
11
405
279
47%
102%
78%
86%
52%
52%
63%
63%
100%
100%
80%
(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) Our Houston, Hopedale and Bluestone Complexes have above-ground NGL storage with a usable capacity
of 938 thousand barrels, large-scale truck and rail loading. In addition, our Houston Complex has large-scale
truck unloading. 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.
67
(3)
(4)
The Hopedale Complex is jointly owned by MarkWest Ohio Fractionation Company, L.L.C. (“Ohio
Fractionation”) and 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 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. The Marcellus Operations include its portion utilized of the jointly
owned Hopedale Fractionation Complex. The Utica Operations includes Utica’s portion utilized of the
jointly owned Hopedale Fractionation Complex. Additionally, Sherwood Midstream has the right to
fractionation revenue and the obligation to pay expenses related to 20 mbpd of capacity in the Hopedale 3
fractionator.
The Ohio Condensate Complex has up to 100 thousand barrels of condensate storage. The Ohio Condensate
Complex is partially-owned by MarkWest Utica EMG Condensate, L.L.C. We account for Ohio Condensate
as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data—
Note 5.
(5) Our Siloam Complex has 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. This facility has 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
Facility
Marcellus Shale:
Bluestone Complex
Harmon Creek Complex
Houston Complex
Majorsville Complex
Mobley Complex
Sherwood Complex
Total Marcellus Shale
Utica Shale:
Cadiz Complex(2)
Total Utica Shale
Southwest:
Javelina Complex
Total Southwest
Total De-ethanization
Location
Design
Throughput
Capacity (mbpd)
NGL
Throughput(1)
(mbpd)
Utilization of
Design
Capacity(1)
Butler County, PA
Washington County, PA
Washington County, PA
Marshall County, WV
Wetzel County, WV
Doddridge County, WV
Harrison County, OH
Corpus Christi, TX
34
20
40
80
10
60
244
40
40
18
18
302
20
1
37
67
10
36
171
14
14
7
7
192
59%
28%
93%
84%
100%
86%
82%
35%
35%
39%
39%
72%
(1) NGL throughput is a weighted average for days in operation. The utilization of design capacity has been
(2)
calculated using the weighted average design throughput capacity.
The Cadiz Complex is owned by MarkWest Utica EMG. We account for MarkWest Utica EMG as an equity
method investment. See discussion in Item 8. Financial Statements and Supplementary Data—Note 5.
68
Natural Gas Gathering Systems
System
Marcellus Shale:
Bluestone System
Houston System
Total Marcellus Shale
Utica Shale:
Ohio Gathering System(2)
Jefferson Gas System(3)
Total Utica Shale
Southwest
East Texas System
Western Oklahoma System
Southeast Oklahoma System
Eagle Ford System
Other Systems(4)
Total Southwest
Total Natural Gas Gathering
Location
Design
Throughput
Capacity (MMcf/d)
Natural Gas
Throughput(1)
(MMcf/d)
Utilization of
Design
Capacity(1)
Butler County, PA
Washington County, PA
Harrison, Monroe,
Belmont, Guernsey and
Noble Counties, OH
Jefferson County, OH
Harrison and Panola
Counties, TX
Wheeler County, TX and
Roger Mills, Ellis, Dewey,
Custer, Beckham,
Washita, Kingfisher,
Canadian, and Blaine
Counties OK
Hughes, Pittsburg and
Coal Counties, OK
Dimmit County, TX
Various
227
1,304
1,531
1,123
2,000
3,123
183
972
1,155
764
1,045
1,809
680
476
585
755
45
60
2,125
6,779
455
585
42
9
1,567
4,531
81%
79%
79%
68%
75%
72%
70%
78%
77%
93%
15%
74%
74%
(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.
The Ohio Gathering System is owned by Ohio Gathering Company, L.L.C. (“Ohio Gathering”). We account
for our investment in Ohio Gathering through MarkWest Utica EMG, which is accounted for as an equity
method investment. See discussion in Item 8. Financial Statements and Supplementary Data—Note 5.
The Jefferson Gas System is owned by MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C.
(“Jefferson Dry Gas”), which is a joint venture between MarkWest Liberty Midstream and EMG MWE Dry
Gas Holdings, LLC. We account for Jefferson Dry Gas as an equity method investment. See discussion in
Item 8. Financial Statements and Supplementary Data—Note 5.
Excludes lateral pipelines where revenue is not based on throughput.
(2)
(3)
(4)
69
NGL Pipelines
Pipeline
Location
Design
Throughput
Capacity (mbpd)
NGL
Throughput
(mbpd)
Utilization of
Design
Capacity
Marcellus Shale:
Sherwood to Mobley propane
and heavier liquids pipeline
Mobley to Majorsville propane
and heavier liquids pipeline
Majorsville to Houston propane
and heavier liquids pipeline
Majorsville to Hopedale propane
and heavier liquids pipeline
Majorsville to Hopedale propane
and heavier liquids pipeline
Third-party processing plant to
Bluestone ethane and heavier
liquids pipeline
Bluestone to Mariner West
ethane pipeline
Sarsen to Bluestone ethane and
heavier liquids pipeline
Houston to Ohio River ethane
pipeline(1)
Majorsville to Houston ethane
pipeline
Sherwood to Mobley ethane
pipeline
Mobley to Majorsville ethane
pipeline
Harmon Creek to Houston
propane and heavier liquids
pipeline
Harmon Creek to Mariner West
ethane pipeline
Utica Shale:(2)
Seneca to Cadiz propane and
heavier liquids pipeline
Cadiz to Hopedale propane and
Doddridge County, WV to
Wetzel County, WV
Wetzel County, WV to
Marshall County, WV
Marshall County, WV to
Washington County, PA
Marshall County, WV to
Harrison County, OH
Marshall County, WV to
Harrison County, OH
Butler County, PA
Butler County, PA to
Beaver County, PA
Butler County, PA
Washington County, PA
to Beaver County, PA
Marshall County, WV to
Washington County, PA
Doddridge County, WV to
Wetzel County, WV
Wetzel County, WV to
Marshall County, WV
Washington County, PA
Washington County, PA
Noble County, OH to
Harrison County, OH
Harrison County, OH
heavier liquids pipeline
Seneca to Cadiz ethane and
Noble County, OH to
heavier liquids pipeline(3)
Harrison County, OH
Cadiz to Atex ethane pipeline
Harrison County, OH
Cadiz to Utopia ethane pipeline Harrison County, OH
Appalachia:
Langley to Siloam propane and
heavier liquids pipeline(4)
Langley, KY to South
Shore, KY
Southwest:
East Texas propane and heavier
liquids pipeline
Panola County, TX
70
75
105
45
140
422
32
35
7
57
137
47
57
140
110
75
90
69/82
125
125
17
39
71
97
30
124
143
8
20
2
13
113
35
45
9
6
10
32
15
4
11
11
22
95%
92%
67%
89%
34%
25%
57%
29%
23%
82%
74%
79%
6%
5%
13%
36%
18%
3%
9%
65%
56%
(1)
(2)
(3)
This is a section of the Mariner West pipeline which is FERC-regulated and is leased to, and operated by,
Sunoco.
The Utica Shale pipelines are owned by MarkWest Utica EMG. We account for MarkWest Utica EMG as
an equity method investment. See discussion in Item 8. Financial Statements and Supplementary
Data—Note 5
This pipeline from Seneca to Cadiz can only be used for either propane and heavier liquids or ethane and
heavier liquids at one time. Both throughput capacities are listed above, respectively, with ethane included
in the total.
(4) NGLs transported through the Langley to Ranger and Ranger to Kenova pipelines are combined with NGLs
recovered at the Kenova Complex. The design capacity and volume reported for the Langley to Siloam
pipeline represent the combined NGL stream.
Title to Properties
Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the
property and in some instance these rights-of-way are revocable at the election of the grantor. 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 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, and in some instances, these permits are revocable at the
election of the grantor. We also have obtained easements and license agreements from railroad companies to
cross over or under railroad properties or rights-of-way, many of which are also 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 our Siloam, Houston and Hopedale 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, including our Majorsville, Sarsen,
Bluestone, Boldman, Kermit and Cobb processing facilities, 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 23, for additional information regarding our leases.
Under the omnibus agreement, 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.
71
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.
Litigation
We are a party to a number of lawsuits and other proceedings and cannot predict the outcome of every such
matter with certainty. 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.
MPLX, MarkWest, MarkWest Liberty Midstream, MarkWest Liberty Bluestone, L.L.C., Ohio Fractionation and
MarkWest Utica EMG (collectively, the “MPLX Parties”) are 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 relate 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. With respect to work performed by Westcon at the Mobley and
Bluestone processing complexes, one or more of the MPLX Parties have asserted breach of contract, fraud, and
with respect to work performed at the Mobley processing complex, MarkWest Liberty Midstream has also
asserted negligent misrepresentation claims against Westcon. Westcon has also asserted claims against one or
more of the MPLX Parties regarding these construction projects for breach of contract, unjust enrichment,
promissory estoppel, fraud and constructive fraud, tortious interference with contractual relations, and civil
conspiracy. Collectively, in the several cases, the MPLX Parties seek in excess of $10 million, plus an
unspecified amount of punitive damages. Collectively, in the several cases, Westcon seeks in excess of
$40 million, plus an unspecified amount of punitive damages. It is possible that, in connection with these
lawsuits, the MPLX Parties will incur material amounts of damages. While the ultimate outcome and impact to
MPLX cannot be predicted with certainty, MPLX does not consider it reasonably possible that a loss resulting
from such lawsuits or other proceedings in excess of any amounts accrued has been incurred that is expected to
have a material adverse effect on its consolidated financial position, results of operations, or cash flows.
In 2003, the State of Illinois brought an action against the Premcor Refining Group, Inc. (“Premcor”) and Apex
Refining Company (“Apex”) asserting claims for environmental cleanup related to the refinery owned by these
entities in the Hartford/Wood River, Illinois area. In 2006, Premcor and Apex filed third-party complaints against
numerous owners and operators of petroleum products facilities in the Hartford/Wood River, Illinois area,
including Marathon Pipe Line LLC (“MPL”). These complaints, which have been amended since filing, assert
claims of common law nuisance and contribution under the Illinois Contribution Act and other laws for
environmental cleanup costs that may be imposed on Premcor and Apex by the State of Illinois. On September 6,
2016, the trial court approved a settlement between Apex and the State of Illinois whereby Apex agreed to settle
all claims against it for a $10 million payment. Premcor filed a motion for permissive appeal and requested a stay
to the proceeding until the motion is ruled upon. Premcor reached a settlement with the State of Illinois in the
second quarter of 2018, which has been objected to by certain third-party defendants, including MPL, and is
subject to court approval. Several third-party defendants in the litigation including MPL have asserted cross-
claims in contribution against the various third-party defendants. This litigation is currently pending in the Third
Judicial Circuit Court, Madison County, Illinois. The trial concerning Premcor’s claims against third-party
defendants, including MPL, previously scheduled to commence September 10, 2018, has been postponed and a
new trial date has not been set. While the ultimate outcome and impact to MPLX cannot be predicted with
certainty, MPLX does not consider it reasonably possible that a loss resulting from such lawsuits or other
proceedings in excess of any amounts accrued has been incurred that is expected to have a material adverse effect
72
on its consolidated financial position, results of operations, or cash flows. Under the omnibus agreement, MPC
will indemnify MPLX for the full cost of any losses should MPL be deemed responsible for any damages in this
lawsuit.
Environmental Proceedings
As previously reported, 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 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.
We are involved in a number of other environmental proceedings arising in the ordinary course of business.
While the ultimate outcome and impact on us cannot be predicted with certainty, we believe the resolution of
these environmental proceedings will not have a material adverse effect on our consolidated results of operations,
financial position or cash flows.
Item 4. Mine Safety Disclosure
Not applicable
73
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 15, 2019, there were 290 registered holders of 289,456,914 outstanding common units held by the
public, including 288,356,605 common units held in street name. In addition, as of February 15, 2019, MPC and
its affiliates owned 504,701,934 of our common units, constituting approximately 64 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.
Preferred Unit Distributions
The holders of the 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
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. 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.
74
Recent Sales of Unregistered Units
In connection with the issuance of 6,845 common units upon the vesting of phantom units under the MPLX LP
2012 Incentive Compensation Plan, our general partner purchased 140 general partner units for $5,012 in cash
during the first quarter of 2018, to maintain its two percent general partner interest in us. The general partner
units were issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of
1933, as amended.
On February 1, 2018, in connection with the Refining Logistics and Fuels Distribution acquisition, we issued
2,277,778 general partner units to our general partner. The general partner units were issued in reliance on an
exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended.
75
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)
2018
2017
2016
2015
2014
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
$ 6,425
2,503
1,834
1,818
$ 3,867
1,191
836
794
$ 3,029
683
434
233
$ 1,101
381
333
156
$
attributable to MPLX LP
1,743
411
1
99
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
2.29
2.29
—
1.07
1.06
—
—
—
—
1.23
1.22
0.11
793
245
239
121
115
1.55
1.55
1.50
partner common unit
2.5300
2.2975
2.0500
1.8200
1.4100
Consolidated Balance Sheets Data (at period end)
Property, plant and equipment, net
Total assets
Long-term debt, including capital leases(1)
Redeemable 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(2)
Other Financial Data
Adjusted EBITDA attributable to MPLX
LP(3)(4)
DCF attributable to MPLX LP(3)(4)
Cash distributions declared on limited partner
14,639
22,779
13,392
1,004
12,187
19,500
6,945
1,000
11,408
17,509
4,422
1,000
10,214
16,404
5,255
—
2,826
(2,686)
(73)
1,919
1,907
(2,308)
171
1,411
1,491
(1,417)
113
1,313
427
(1,681)
1,275
334
3,475
2,781
2,004
1,628
1,419
1,140
498
399
1,324
1,544
644
—
335
(140)
(225)
141
166
137
common units
$ 1,985
$
895
$
692
$
255
$
106
(1) 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 borrowings under MarkWest’s credit facility.
(2) Represents cash capital expenditures as reflected on the Consolidated Statements of Cash Flows for the
(3)
(4)
periods indicated, which are included in cash used in investing activities.
The 2015 Adjusted EBITDA attributable to MPLX LP includes pre-merger EBITDA from MarkWest and
the 2015 DCF includes undistributed DCF from MarkWest.
For all years presented, Predecessor is excluded from Adjusted EBITDA attributable to MPLX LP and DCF
attributable to MPLX LP.
76
Operating Data
L&S
Crude oil transported for (mbpd)(1):
MPC
Third parties
Total
% MPC
Products transported for (mbpd)(2):
MPC(3)
Third parties
Total
% MPC
2018
2017
2016
2015
2014
1,833
347
2,180
84%
1,003
172
1,175
85%
1,622
314
1,936
84%
928
157
1,085
86%
1,461
182
1,643
89%
844
146
990
85%
1,443
197
1,640
88%
966
27
993
97%
0.55
0.65
0.59
N/A
219
18
838
203
1,041
80%
852
26
878
97%
$ 0.64
0.61
$ 0.63
N/A
211
18
Average tariff rates ($ per Bbl)(4):
Crude oil pipelines
Product pipelines
Total pipelines
$
$
0.59 $
0.79
0.66 $
0.56 $
0.74
0.63 $
0.57 $
0.68
0.61 $
Terminal throughput (mbpd)(5)
1,481
1,477
1,505
Marine Assets (number in operation)(6)
Barges
Towboats
256
23
232
18
222
18
G&P Consolidated entities(8)
Gathering Throughput (MMcf/d)
Marcellus Operations
Utica Operations
Southwest Operations
Total gathering throughput
Natural Gas Processed (MMcf/d)
Marcellus Operations
Utica Operation
Southwest Operations
Southern Appalachian Operations
Total natural gas processed
C2 + NGLs Fractionated (mbpd)
Marcellus Operations(10)
Utica Operations
Southwest Operations
Southern Appalachian Operations(11)
Total C2 + NGLs fractionated(12)
2018
2017
2016
2015
2014
1,004
—
1,410
2,414
3,619
—
1,326
265
5,210
320
—
20
14
354
910
—
1,431
2,341
3,210
—
1,226
253
4,689
260
—
18
15
293
889
—
1,439
2,328
2,964
—
1,125
243
4,332
220
—
24
12
256
1,155
—
1,566
2,721
3,826
—
1,438
247
5,511
379
—
18
15
412
77
2018
2017
2016
2015(7)
2014
G&P Consolidated entities plus
Partnership-Operated Equity Method
Investments(9)
Gathering Throughput (MMcf/d)
Marcellus Operations
Utica Operations
Southwest Operations
Total gathering throughput
Natural Gas Processed (MMcf/d)
Marcellus Operations
Utica Operations
Southwest Operations
Southern Appalachian Operations
Total natural gas processed
C2 + NGLs Fractionated (mbpd)
Marcellus Operations(10)
Utica Operations(10)
Southwest Operations
Southern Appalachian Operations(11)
Total C2 + NGLs fractionated(12)
1,155
1,809
1,567
4,531
4,448
886
1,438
247
7,019
379
47
18
15
459
1,004
1,192
1,412
3,608
3,885
984
1,326
265
6,460
320
40
20
14
394
910
932
1,433
3,275
3,210
1,072
1,226
253
5,761
260
42
18
15
335
889
745
1,441
3,075
2,964
1,136
1,125
243
5,468
220
51
24
12
307
Pricing Information
Natural Gas NYMEX HH ($/MMBtu)
C2 + NGL Pricing/Gal(13)
$
$
3.07 $
0.78 $
3.02 $
0.66 $
2.55 $
0.47 $
2.04
0.40
2018
2017
2016
2015
2014
(1) 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.
(2) Represents the average aggregate daily number of barrels of products transported on our pipelines for MPC
(3)
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.
This table represents operating data for entities that have been consolidated into the MPLX financial
(8)
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.
(9)
(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
78
Utica’s portion utilized of the jointly owned Hopedale Fractionation Complex. Additionally, Sherwood
Midstream has the right to fractionation revenue and the obligation to pay expenses related to 20 mbpd of
capacity in the Hopedale 3 fractionator.
Includes NGLs fractionated for the Marcellus and Utica Operations.
(11)
(12) Purity ethane makes up approximately 171 mbpd, 141 mbpd, 114 mbpd and 83 mbpd of MPLX LP
consolidated total fractionated products for the years ended December 31, 2018, 2017, 2016 and 2015,
respectively. Purity ethane makes up approximately 185 mbpd, 146 mbpd, 118 mbpd and 89 mbpd of
MPLX operated total fractionated products for the years ended December 31, 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.
79
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. We are engaged in the transportation, storage and
distribution of crude oil and refined petroleum products; gathering, processing and transportation of natural gas;
and the gathering, transportation, fractionation, storage and marketing of NGLs. Our operations are conducted in
our Logistics and Storage and Gathering and Processing segments.
SIGNIFICANT FINANCIAL AND OTHER HIGHLIGHTS
During 2018, 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 time simplifying our financial structure and maintaining our investment grade credit profile. Significant
financial and other highlights for the year ended December 31, 2018, are listed below. Refer to the Results of
Operations and the Liquidity and Capital Resources sections for further details.
• L&S Segment Adjusted EBITDA attributable to MPLX LP increased approximately $1,282 million, or
165 percent, in 2018 compared to 2017. This increase was primarily due to $944 million of Segment
Adjusted EBITDA generated by Refining Logistics and Fuels Distribution following the February 1, 2018
acquisition; an additional $159 million of Segment Adjusted EBITDA due to increased distributions and
other adjustments from equity method investments including the joint venture with Enbridge Energy
Partners L.P. (“MarEn Bakken”) and the Joint-Interest Acquisition; as well as increased transportation
revenues due to higher rates and volumes of crude and refined products shipped.
• G&P Segment Adjusted EBITDA attributable to MPLX LP increased approximately $189 million, or
15 percent, in 2018 compared to 2017. This increase was primarily due to $140 million of Segment
Adjusted EBITDA from increased gathered, processed and fractionated volumes, which drove higher
utilization rates and higher fee-based revenue in the Marcellus and Southwest. These increases are a result
of expansions at the Houston, Majorsville, Harmon Creek and Argo facilities. Increased prices in the
Marcellus, Northeast and Southwest also resulted in higher Segment Adjusted EBITDA of approximately
$45 million. Further, there was an increase in distributions from unconsolidated affiliates of $57 million and
an increase in derivative gains of $12 million which was offset by increased facility and operating expenses
as well as employee related costs of $65 million. Compared to full-year 2017, gathering volumes were up
26 percent, processing volumes were up nine percent and fractionated volumes were up 16 percent.
Additional highlights for the year ended December 31, 2018, including a look ahead to anticipated growth, are
listed below.
Dropdown Acquisition from MPC
On February 1, 2018, we acquired Refining Logistics and Fuels Distribution from MPC in exchange for
$4.1 billion in cash and a fixed number of common units and general partner units of 111.6 million and
80
2.3 million, respectively. The general partner units maintained MPC’s two percent economic general partner
interest, which converted into a non-economic general partner interest immediately thereafter in the GP IDR
Exchange. This dropdown acquisition was the last in a series of three planned dropdown transactions announced
by MPC in early 2017. Refining Logistics contains the integrated tank farm assets that support MPC’s refining
operations and includes 619 tanks with approximately 56 million barrels storage capacity (crude, finished
products and intermediates), 32 rail and truck racks, 18 docks, and gasoline blenders. Fuels Distribution is
structured to provide a broad range of scheduling and marketing services as an agent to MPC.
Other Significant Acquisitions and Investments
• On October 17, 2018, MPLX announced it is jointly developing with Crimson Midstream LLC (“Crimson”)
a multi-diameter pipeline to provide connectivity from St. James and Raceland, Louisiana to the Louisiana
Offshore Oil Port LLC terminal in Clovelly, Louisiana. The proposed pipeline would have the ability to
transport up to 600 mbpd of crude oil and has an expected in-service date in the first half of 2020.
• On September 26, 2018, MPLX acquired the Mt. Airy Terminal with 4 million barrels of third-party leased
storage capacity and a 120 mbpd dock from Pin Oak Holdings, LLC for $451 million. The facility has the
capability to significantly expand its storage capacity to 10 million barrels and is permitted for construction
of a second 120 mbpd dock. The facility is strategically located on the Mississippi River between New
Orleans and Baton Rouge and is near several Gulf Coast refineries, including MPC’s Garyville refinery. The
Mt. Airy Terminal can handle multiple refined products, as well as residual fuel and bunker products, to
provide optionality and flexibility of feedstocks and finished products in a single location. The Mt. Airy
Terminal also has significant growth opportunities as a result of multiple pipelines and rail lines crossing the
property in addition to being positioned as an aggregation point for liquids growth for both ocean-going
vessels and inland barges.
• On September 4, 2018, MPLX announced it is jointly developing with Energy Transfer Partners, L.P.
(“Energy Transfer”), Magellan Midstream Partners, L.P. (“Magellan”) and Delek US Holdings, Inc. a new
30-inch diameter common carrier pipeline to transport crude oil from the Permian Basin to the Texas Gulf
Coast region. The 600-mile pipeline system is expected to be operational in mid-2020 with multiple Texas
origins and would have the strategic capability to transport crude oil to both Energy Transfer’s Nederland,
Texas terminal and Magellan’s East Houston, Texas terminal. The ability to increase the diameter and
capacity of the pipeline exists if additional commitments are received.
• On July 26, 2018, MPLX announced a number of steps it has taken to further expand its presence in the
Permian Basin. These activities include development of a 200 MMcf/d gas processing plant in Loving
County Texas, called the Torñado plant, as well as natural gas gathering infrastructure primarily in Lea
County, New Mexico. These expansion activities are expected to be complete in the third quarter of 2019.
MPLX also acquired a 10 percent equity interest in the Agua Blanca pipeline which is a 1,400 MMcf/d
pipeline (which has the ability to be expanded to 2,000 MMcf/d) originating in Orla, Texas and ending in
Waha, Texas. Agua Blanca is also constructing a lateral to connect our MarkWest Argo Plant, which
commenced operations in early 2018.
Financing Activities
• 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 unsecured senior notes due
February 2029 and $1.5 billion aggregate principal amount of 5.5 percent unsecured senior notes due
February 2049. The notes were offered at a price to the public of 99.432 percent and 98.031 percent of par,
respectively. The proceeds were used to repay outstanding borrowings under the MPLX Credit Agreement
and the MPC Loan Agreement, to redeem $750 million aggregate principal amount of 5.5 percent senior
notes due February 2023, as well as for general business purposes.
81
• On September 25, 2018, MPLX drew $1 billion under the MPLX Credit Agreement. The proceeds were
used to fund the acquisition of the Mt. Airy Terminal, to pay down the MPC Loan Agreement and for
general business purposes.
• 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.
• 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 unsecured senior notes due
March 2023, $1.25 billion aggregate principal amount of 4.0 percent unsecured senior notes due March
2028, $1.75 billion aggregate principal amount of 4.5 percent unsecured senior notes due April 2038,
$1.5 billion aggregate principal amount of 4.7 percent unsecured senior notes due April 2048, and
$500 million aggregate principal amount of 4.9 percent unsecured senior notes due April 2058. The 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. The net proceeds were used to repay the $4.1 billion 364-day term loan
facility (as described below), the outstanding borrowings under the MPLX Credit Agreement and the MPC
Loan Agreement, as well as for general business purposes.
• On February 1, 2018, immediately following the completion of the dropdown acquisitions mentioned above,
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. This exchange eliminated the general partner cash distribution requirements of
MPLX.
• On February 1, 2018, in connection with the dropdown acquisition, MPLX drew $4.1 billion on a 364-day
term loan facility with a syndicate of lenders, which was entered into on January 2, 2018. The proceeds of
the term loan facility were used to fund the cash portion of the dropdown consideration for Refining
Logistics and Fuels Distribution.
• We did not make any issuances under our ATM Program during the year ended December 31, 2018.
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) 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
82
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
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 evaluates contract performance on the basis of Net operating margin, a non-GAAP financial
measure, which is defined as segment revenue less both segment purchased product costs and realized derivative
gains and losses related to purchased product costs. These charges have been excluded for the purpose of
enhancing the understanding by both management and investors of the underlying baseline operating
performance of our contractual arrangements, which management uses to evaluate our financial performance for
purposes of planning and forecasting. Net operating margin does not have any standardized definition and,
therefore, is unlikely to be comparable to similar measures presented by other reporting companies. Net
operating margin results should not be evaluated in isolation of, or as a substitute for, our financial results
prepared in accordance with GAAP. Our use of Net operating margin and the underlying methodology in
excluding certain charges is not necessarily an indication of the results of operations expected in the future, or
that we will not, in fact, incur such charges in future periods.
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 15).
83
RESULTS OF OPERATIONS
The following table and discussion is a summary of our results of operations for the years ended 2018, 2017 and
2016, 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 the acquisition of HSM, HST, WHC and MPLXT.
2018
2017
$ Change
2016
$ Change
(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/(loss) 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/(benefit) for income taxes
Net income
Less: Net income
attributable to noncontrolling interests
Less: Net income attributable to Predecessor
Net income attributable to MPLX LP
$
1,704 $
2,159
198
349
718
902
49
1,156 $
1,082
—
277
279
889
8
240
7
99
6,425
948
845
135
5
860
766
—
291
72
3,922
2,503
5
534
122
1,842
8
1,834
16
—
1,818
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
Adjusted EBITDA attributable to MPLX LP(2)
DCF(2)
DCF attributable to GP and LP unitholders(2)
$
3,475
2,781
2,706 $
2,004
1,628
1,563 $
548 $
1,077
198
72
439
13
41
162
1
7
2,558
420
194
73
3
405
83
—
50
18
1,246
1,312
3
238
66
1,005
7
998
10
(36)
1,024
1,471
1,153
1,143
958 $
936
—
298
235
572
11
(74)
7
86
3,029
454
448
57
1
388
591
130
227
50
2,346
683
1
210
50
422
(12)
434
2
199
233
1,419
1,140
1,099
$
$
198
146
—
(21)
44
317
(3)
152
(1)
6
838
74
203
5
1
67
92
(130)
14
4
330
508
1
86
6
415
13
402
4
(163)
561
585
488
464
(1)
Includes an impairment expense of $89 million related to one of MPLX’s equity method investments for the
year ended December 31, 2016.
(2) Non-GAAP financial measure. See the following tables for reconciliations to the most directly comparable
GAAP measures.
84
(In millions)
2018
2017
2016
Reconciliation of Adjusted EBITDA attributable to MPLX LP and
DCF attributable to GP and LP unitholders from Net income:
Net income
Provision/(benefit) 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)/loss from equity method investments(1)
Distributions/adjustments related to equity method investments
Unrealized derivative (gains)/losses(2)
Acquisition costs
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
Equity method investment capital expenditures paid out
Other
Portion of DCF adjustments attributable to Predecessor(3)
DCF
Preferred unit distributions
$
1,834 $
8
59
46
556
836 $
1
53
—
301
2,503
766
19
—
(240)
447
(5)
3
3,493
(18)
—
3,475
32
(556)
(146)
(31)
7
—
2,781
(75)
1,191
683
15
—
(78)
231
6
11
2,059
(8)
(47)
2,004
33
(301)
(103)
(13)
6
2
1,628
(65)
DCF attributable to GP and LP unitholders
$
2,706 $
1,563 $
434
(12)
46
—
215
683
591
10
130
74
150
36
(1)
1,673
(3)
(251)
1,419
16
(215)
(84)
(3)
(1)
8
1,140
(41)
1,099
(1)
Includes an impairment expense of $89 million related to one of MPLX’s equity method investments for the
year ended December 31, 2016.
(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.
The Adjusted EBITDA and DCF adjustments related to Predecessor are excluded from Adjusted EBITDA
attributable to MPLX LP and DCF prior to the acquisition dates.
(3)
85
(In millions)
2018
2017
2016
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 (loss)/gain 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
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
Equity method investment capital expenditures paid out
Other
Portion of DCF adjustments attributable to Predecessor(2)
DCF
Preferred unit distributions
$
$
2,826
41
(45)
19
(2)
556
46
—
7
(5)
3
47
3,493
(18)
—
3,475
32
(556)
(146)
(31)
7
—
2,781
(75)
$
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)
DCF attributable to GP and LP unitholders
$
2,706
$
1,563
$
1,491
(76)
(16)
10
1
215
—
5
6
36
(1)
2
1,673
(3)
(251)
1,419
16
(215)
(84)
(3)
(1)
8
1,140
(41)
1,099
(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.
The Adjusted EBITDA and DCF adjustments related to Predecessor are excluded from Adjusted EBITDA
attributable to MPLX LP and DCF prior to the acquisition dates.
(2)
2018 Compared to 2017
Service revenue increased $548 million in 2018 compared to 2017. This variance was primarily due to a
$167 million increase in fees from volume growth in the Marcellus and the Southwest areas; a $13 million
increase related to increases in volume and transportation rates of crude oil and 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 $1,077 million in 2018 compared to 2017. This variance was primarily
due to a $947 million increase from the acquisition of Refining Logistics and Fuels Distribution; a $100 million
86
increase related to higher volumes and transportation rates of related-party crude oil and 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 $198 million in 2018 compared to 2017. This variance was primarily
due to ASC 606 classification and non-cash changes.
Rental income increased $72 million in 2018 compared to 2017. This 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 $439 million in 2018 compared to 2017. This 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 $54 million in 2018 compared to 2017. This variance
was primarily due to higher prices in the Southwest, Northeast and Marcellus 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 $162 million in 2018 compared to 2017. This 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 $420 million in 2018 compared to 2017. This variance was primarily due to ASC 606
gross-ups of $369 million, higher repairs and maintenance and operating costs in the Marcellus and Southwest 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 $194 million in 2018 compared to 2017. This 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 $76 million in 2018 compared to 2017. This
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 $405 million in 2018 compared to 2017. This 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.
87
Depreciation and amortization expense increased $83 million in 2018 compared to 2017. This 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 $50 million in 2018 compared to 2017. This variance was
primarily due to the acquisition of Refining Logistics and Fuels Distribution as well as increased labor and
benefits costs.
Other taxes increased $18 million in 2018 compared to 2017. This 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 $307 million in 2018 compared to 2017. This 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.
2017 Compared to 2016
Service revenue increased $198 million in 2017 compared to 2016. This variance was primarily due to a
$155 million increase in fees on higher volumes due to new gathering and processing facilities in the Marcellus
and Southwest areas, a $38 million increase from the acquisition of Ozark pipeline, and an $12 million increase
related to volumes of crude oil and products shipped.
Service revenue-related parties increased $146 million in 2017 compared to 2016. This variance was primarily
due to a $41 million increase related to volumes in related-party crude oil and products shipped, a $26 million
increase from the acquisition of Ozark pipeline, and the inclusion of $79 million of revenue generated by
MPLXT and its subsidiaries in the first quarter of 2017, as they were not formed as a business until April 1,
2016.
Rental income decreased $21 million in 2017 compared to 2016. This variance was primarily driven by the
impact of recognizing rental income on a straight-line basis related to certain customer agreements.
Rental income-related parties increased $44 million in 2017 compared to 2016. This variance was primarily due
to the inclusion of $24 million of revenue generated by MPLXT and its subsidiaries in the first quarter of 2017,
as they were not formed as a business until April 1, 2016, and a $14 million increase in HSM equipment revenue
due to increased capacity as a result of acquisition or chartering of additional barges.
Product sales increased $317 million in 2017 compared to 2016. This variance was primarily due to mainly to
increased pricing of approximately $252 million as well as higher volume growth of approximately $61 million
in the Marcellus and Southwest areas.
Income (loss) from equity method investments increased $152 million in 2017 compared to 2016. This variance
was primarily due to the inclusion of $15 million due to the acquisition of MarEn Bakken, $21 million due the
acquisition of the joint-interest assets from MPC, and $27 million from our other equity method investments due
mainly to increased volumes in the Utica area. The year ended December 31, 2016 also included an impairment
expense of $89 million related to one of our equity method investments.
Cost of revenues increased $74 million in 2017 compared to 2016. This variance was primarily due to an increase
of $20 million due to the inclusion of MPLXT and its subsidiaries in the first quarter of 2017, as they were not
formed as a business until April 1, 2016, an increase of $31 million from the acquisition of the Ozark pipeline, an
$18 million increase in expenses related to greater project spend, and a $4 million increase in HSM costs for
chartering additional barges.
88
Purchased product costs increased $203 million in 2017 compared to 2016. This variance was primarily due to
higher NGL and gas prices and purchase volumes in the Southwest area, partially offset by a $12 million
unrealized gain on an embedded derivative.
Purchases-related parties increased $67 million in 2017 compared to 2016. This variance was primarily due to
the inclusion of approximately $23 million related party purchases of MPLXT and its subsidiaries in the first
quarter of 2017, as they were not formed as a business until April 1, 2016, as well as general increases in
employee costs due to headcount.
Depreciation and amortization expense increased $92 million in 2017 compared to 2016. This variance was
primarily due to accelerated depreciation expense of approximately $38 million incurred on the decommissioning
of the Houston 1 facility in the Marcellus area and other various assets, approximately $15 million of additional
depreciation due to the inclusion of MPLXT and the Ozark pipeline, as well as additions to in-service property,
plant and equipment.
Impairment expense decreased $130 million in 2017 compared to 2016. This variance was primarily due to a
non-cash impairment to goodwill in two reporting units in the G&P segment during 2016. See Item 8. Financial
Statements and Supplementary Data—Note 15 for more information.
General and administrative expenses increased $14 million in 2017 compared to 2016. This variance was
primarily due to an increase in acquisition costs, as well as employee costs related to the omnibus and employee
services agreements with MPC.
Interest expense and other financial costs increased $92 million in 2017 compared to 2016. This variance was
primarily due to the senior notes issued in February 2017.
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. For the L&S segment, Segment Adjusted EBITDA attributable to MPLX LP excludes the Adjusted
EBITDA related to the HSM Predecessor prior to the March 31, 2016 acquisition and the HST, WHC and
MPLXT Predecessor prior to the March 1, 2017 acquisition.
89
The tables below present information about Segment Adjusted EBITDA for the reported segments for the years
ended December 31, 2018, 2017 and 2016.
L&S Segment
(In millions)
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
Adjusted EBITDA attributable to
Predecessor
Segment Adjusted EBITDA(1)
2018
2017
$ Change
2016
$ Change
$
2,289
725
14
166
46
3,240
401
685
240
142
36
1,736
240
(166)
235
3
9
—
2,057
1,200
279
—
36
47
1,562
370
299
163
106
22
602
163
(36)
76
11
6
(47)
775
$
1,089 $
446
14
130
(1)
1,006 $
235
—
—
53
1,678
31
386
77
36
14
1,134
77
(130)
159
(8)
3
47
1,282
1,294
289
246
128
99
17
515
128
—
—
(1)
4
(251)
395
194
44
—
36
(6)
268
81
53
35
7
5
87
35
(36)
76
12
2
204
380
21
Maintenance capital expenditures
$
104
$
79
$
25 $
58 $
(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.
2018 Compared to 2017
Service revenue increased $1,089 million in 2018 compared to 2017. This 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 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. These increases were partially offset by ASC 606 classification changes
and other miscellaneous items.
Rental income increased $446 million in 2018 compared to 2017. This 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 $14 million in 2018 compared to 2017. This variance was primarily due to
ASC 606 classification changes.
Income from equity method investments increased $130 million in 2018 compared to 2017. This variance was
primarily due to the Joint-Interest Acquisition and the acquisition of MarEn Bakken.
Cost of revenues increased $31 million in 2018 compared to 2017. This variance was primarily due to an
additional $13 million from the acquisition of Refining Logistics and Fuels Distribution, $7 million from the
90
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 $386 million in 2018 compared to 2017. This 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 $77 million in 2018 compared to 2017. This variance was primarily due
to the acquisitions of Refining Logistics, Fuels Distribution and the Mt. Airy Terminal.
General and administrative expenses increased $36 million in 2018 compared to 2017. This 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 $14 million in 2018 compared to 2017 primarily due to the acquisition of Refining
Logistics and Fuels Distribution as well as the Ozark pipeline acquisition and expansion.
2017 Compared to 2016
Service revenue increased $194 million in 2017 compared to 2016 primarily due to an additional $64 million
from the acquisition of the Ozark pipeline; a $53 million increase from higher crude and product transportation
volumes; and the inclusion of $79 million of revenue generated by MPLXT and its subsidiaries in the first
quarter of 2017, as they were not formed as a business until April 1, 2016.
Rental income increased $44 million in 2017 compared to 2016 primarily due to an increase of $14 million from
HSM equipment revenue due to increased capacity as a result of acquisition or chartering of additional barges,
and the inclusion of $24 million of revenue generated by MPLXT and its subsidiaries in the first quarter of 2017,
as they were not formed as a business until April 1, 2016.
Income from equity method investments increased $36 million in 2017 compared to 2016 due to the Joint-
Interest Acquisition and the acquisition of MarEn Bakken.
Cost of revenues increased $81 million in 2017 compared to 2016 primarily due to an increase of $20 million due
to the inclusion of MPLXT and its subsidiaries in the first quarter of 2017, as they were not formed as a business
until April 1, 2016; an increase of $31 million from the acquisition of the Ozark pipeline; an $18 million increase
in expenses related to greater project spend; and a $4 million increase in HSM costs for chartering additional
barges, as well increased other miscellaneous expenses.
Purchases—related parties increased $53 million in 2017 compared to 2016 primarily due to an additional
$23 million related to the inclusion of MPLXT and its subsidiaries in the first quarter of 2017, as they were not
formed as a business until April 1, 2016, as well as general increases in employee costs due to headcount.
Depreciation and amortization increased $35 million in 2017 compared to 2016 primarily due to the inclusion of
MPLXT and the Ozark pipeline, as well as additions to in-service property plant and equipment.
General and administrative expenses increased $7 million in 2017 compared to 2016 primarily due to an increase
in acquisition costs, as well as employee costs related to the omnibus and employee services agreements with
MPC.
Other taxes increased $5 million in 2017 compared to 2016 primarily due to the inclusion of MPLXT and the
Ozark pipeline.
91
MPC Minimum Volume Commitments
During 2018 and 2017, MPC did not ship its minimum committed volumes on certain of our pipelines. As a result,
MPC was obligated to make $41 million and $45 million of deficiency payments in 2018 and 2017, respectively.
We record deficiency payments as “Deferred revenue-related parties” on the Consolidated Balance Sheets. During
2018 and 2017, we recognized revenue of $50 million and $38 million, respectively, related to volume deficiency
credits. At December 31, 2018 and 2017, the cumulative balance of “Deferred revenue-related parties” on our
Consolidated Balance Sheets related to volume deficiencies was $44 million and $53 million, respectively. The
following table presents the future expiration dates of the associated deferred revenue credits for 2018:
(In millions)
March 31, 2019
June 30, 2019
September 30, 2019
December 31, 2019
March 31, 2020
June 30, 2020
September 30, 2020
December 31, 2020
Total
$
$
9
9
17
9
—
—
—
—
44
We will recognize revenue for the deficiency payments in future periods at the earlier of when volumes are
transported in excess of the minimum quarterly volume commitments, when it becomes impossible to physically
transport volumes necessary to utilize the accumulated credits or upon expiration of the make-up period.
Deficiency payments are included in the determination of DCF in the period in which a deficiency occurs.
92
G&P Segment
(In millions)
Service revenue
Rental income
Product related revenue
Income/(loss) 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 from operations
Depreciation and amortization
Impairment expense
(Income)/loss 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
Segment Adjusted EBITDA(2)
2018
2017
$ Change
2016
$ Change
$
$
1,574
342
1,135
$
1,038
277
897
74
60
3,185
687
845
175
526
—
149
36
767
526
—
(74)
212
(5)
10
(18)
1,418
42
51
2,305
222
651
156
520
—
135
32
589
520
—
(42)
155
6
9
(8)
1,229
536
65
238
32
9
880
465
194
19
6
—
14
4
178
6
—
(32)
57
(11)
1
(10)
189
$
$
888
298
583
(74)
40
1,735
223
448
142
463
130
128
33
168
463
130
74
150
36
6
(3)
1,024
150
(21)
314
116
11
570
(1)
203
14
57
(130)
7
(1)
421
57
(130)
(116)
5
(30)
3
(5)
205
(2)
Maintenance capital expenditures
$
42
$
24
$
18
$
26
$
(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.
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.
(2)
2018 Compared to 2017
Service revenue increased $536 million in 2018 compared to 2017. This variance was primarily due to ASC 606
cost reimbursements of $369 million as well as higher fees from higher volumes in the Marcellus and Southwest
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 $238 million in 2018 compared to 2017. This variance was primarily due to
higher prices in the Southwest, Northeast and Marcellus 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 $32 million in 2018 compared to 2017. This variance was
primarily due to growth in the Jefferson Dry Gas joint venture as a result of an increase in dry gas gathering
93
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 $9 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 $465 million in 2018 compared to 2017. This 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 of $32 million.
Purchased product costs increased $194 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 with 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 $19 million in 2018 compared to 2017. This variance was primarily due to
employee-related costs.
Depreciation and amortization increased $6 million in 2018 compared to 2017. This 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 $14 million in 2018 compared to 2017. This variance was
primarily due to increases in labor and benefits costs and general increases in office expenses.
Other taxes increased $4 million in 2018 compared to 2017. This variance was primarily due to an increase in
property taxes.
2017 Compared to 2016
Service revenue increased $150 million in 2017 compared to 2016. This variance was primarily due to an
increase in fees on higher volumes due to new gathering and processing facilities in the Marcellus and Southwest
areas.
Rental income decreased $21 million in 2017 compared to 2016. This variance was primarily due to the impact
of recognizing rental income on a straight-line basis related to certain customer agreements.
Product related revenue increased $314 million in 2017 compared to 2016. This variance was primarily due to
increased pricing of approximately $252 million as well as higher volume growth of approximately $52 million
in the Marcellus and Southwest areas and unrealized derivative gains of $9 million due to a larger fractionation
spread.
Income from equity method investments increased $116 million in 2017 compared to 2016. This variance was
primarily due to an increase of $27 million from our equity method investments, mainly driven by increased
volumes in the Utica area. The year ended December 31, 2016 also included an impairment expense of
$89 million related to one of our equity method investments.
Other income increased $11 million in 2017 compared to 2016. This variance was primarily due to an increase in
management fees from our joint ventures.
94
Purchased product costs increased $203 million in 2017 compared to 2016. This variance was primarily due to
higher NGL and gas prices and purchase volumes in the Southwest area, offset with unrealized gains and losses
associated with derivatives of $10 million.
Purchases—related parties increased $14 million in 2018 compared to 2017. This variance was primarily due to
employee-related costs.
Depreciation and amortization increased $57 million in 2017 compared to 2016. This variance was primarily due
to $33 million of accelerated depreciation to decommission the Houston 1 facility and additions to in-service
property, plant and equipment.
Impairment expense decreased $130 million in 2017 compared to 2016. This variance was primarily due to an
impairment to goodwill during 2016.
SEGMENT NET OPERATING MARGIN
For the year ended December 31, 2018, we calculated the following approximate percentages of our Net
operating margin from the following types of contracts:
L&S
G&P
Total
Fee-Based
Other(1)
100%
87%
95%
—%
13%
5%
(1)
Includes percent-of-proceeds, keep-whole and other types of arrangements tied to NGL, condensate and
natural gas prices.
The following table presents a reconciliation of Net operating margin to income from operations, the most
directly comparable GAAP financial measure.
(In millions)
2018
2017
2016
Reconciliation to Income from operations from Net operating margin:
Service and rental revenues
Product related revenues
Purchased product costs
Derivative loss related to purchased product costs(1)
Net operating margin
Derivative loss related to purchased product costs(1)
Income/(loss) from equity method investments(2)
Other income
Other income—related parties
Cost of revenues (excludes items below)
Rental cost of sales
Rental cost of sales—related parties
Purchases—related parties
Depreciation and amortization
Impairment expense
General and administrative expenses
Other taxes
$
4,930 $
1,149
(845)
(9)
2,794 $
897
(651)
(19)
5,225
9
240
7
99
(948)
(135)
(5)
(860)
(766)
—
(291)
(72)
3,021
19
78
6
92
(528)
(62)
(2)
(455)
(683)
—
(241)
(54)
Income from operations
$
2,503 $
1,191 $
95
2,427
583
(448)
(27)
2,535
27
(74)
7
86
(454)
(57)
(1)
(388)
(591)
(130)
(227)
(50)
683
(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.
Includes an impairment expense of $89 million related to one of MPLX’s equity method investments for the
year ended December 31, 2016.
(2)
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Our cash, cash equivalents and restricted cash balance was $76 million at December 31, 2018, compared to
$9 million at December 31, 2017. 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
2018
2017
2016
$
$
2,826 $
(2,686)
(73)
1,907 $
(2,308)
171
1,491
(1,417)
113
67 $
(230) $
187
Cash Flows Provided by Operating Activities. Net cash provided by operating activities increased $919 million
in 2018 compared to 2017, the majority of which 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.
Net cash provided by operating activities increased $416 million in 2017 compared to 2016, the majority of
which is related to an increase in net income net of non-cash adjustments of approximately $240 million. This
favorable change was driven primarily by higher prices and volumes, as well as the inclusion of MPLXT, since it
was not formed as a business until April 1, 2016, and the acquisition of the Ozark pipeline. In addition, there was
an increase in distributions received from unconsolidated affiliates of $93 million due primarily to the acquisition
of an equity interest in MarEn Bakken and the Joint-Interest Acquisition from MPC. Working capital reflected
favorable changes of approximately $83 million compared to 2016.
Cash Flows Used in Investing Activities. Net cash used in investing activities increased $378 million in 2018
compared to 2017 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.
Net cash used in investing activities increased $891 million in 2017 compared to 2016, primarily due to the
acquisition of an equity interest in MarEn Bakken for $513 million, investments in other unconsolidated entities
of approximately $248 million, $219 million for the acquisition of the Ozark pipeline, $33 million for the
buy-out of an equity method investment partner, and an increase in cash used for additions to property, plant and
equipment related to various capital projects. Partially offsetting these items was a net increase of $97 million in
investment loans with MPC and a return of capital of $26 million from our acquisition of equity interests in
Sherwood Midstream and Sherwood Midstream Holdings LLC.
Cash Flows Used in and Provided by Financing Activities. The change in financing activities was a $73 million
use of cash in 2018 compared to a $171 million source of cash in 2017. The uses of cash in 2018 primarily
96
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.
Net cash provided by financing activities in 2017 was $171 million compared to $113 million in 2016. 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 increased distributions of $1.1 billion to unitholders and our general partner due mainly to the increase in
units outstanding, as well as a 12.1 percent increase in the distribution per limited partner unit.
The sources of cash in 2016 primarily consisted of $984 million in net proceeds from the issuance of preferred
units and $792 million of net cash proceeds from the issuance of common units and general partner units, as well
as contributions of $225 million from MPC as part of the Class A Reorganization. The uses of cash in 2016
primarily consisted of net repayments of long-term debt and distributions to unitholders.
Long-term debt borrowings and repayments were a net $6.3 billion source of cash in 2018 compared to a
$2.5 billion source of cash in 2017 and a $878 million use of cash in 2016. 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, 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. During
2016, we used proceeds from the issuance of preferred units to repay amounts outstanding under the MPLX
Credit Agreement. See Item 8. Financial Statements and Supplementary Data—Note 18.
Debt and Liquidity Overview
On November 20, 2014, we entered into a credit agreement with a syndicate of lenders which provided for a five-
year, $1 billion bank revolving credit facility and a $250 million term loan facility. In connection with the
MarkWest Merger, the aggregate capacity of the credit facility was extended to $2 billion and the maturity date
was extended to December 4, 2020. On July 21, 2017, we replaced the previously existing $2 billion revolving
credit facility and $250 million term loan with a $2.25 billion five-year bank revolving credit facility that expires
in July 2022 (“MPLX Credit Agreement”). 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 financial covenants and the interest rate terms
contained in the new credit agreement are substantially the same as those contained in the previous bank
97
revolving credit facility. Additionally, on July 19, 2017, we prepaid the entire outstanding principal amount of
the previously outstanding $250 million term loan with cash on hand.
The MPLX Credit Agreement includes letter of credit issuing capacity of up to $222 million and swingline
capacity of up to $100 million. The borrowing capacity under the MPLX Credit Agreement may be increased by
up to an additional $500 million, 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 2018, we borrowed $1,410 million under the MPLX Credit Agreement, at an average
interest rate of 3.464 percent, and repaid $1,915 million of borrowings under the MPLX Credit Agreement. At
December 31, 2018, we had no outstanding borrowings and $3 million in letters of credit outstanding under this
facility, resulting in total availability of approximately $2.2 billion, or 99.9 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, 2018, we were in compliance with this financial covenant with a
ratio of Consolidated Total Debt to Consolidated EBITDA of 3.8 to 1.0, as well as all other covenants contained
in the MPLX Credit Agreement. For further discussion, see Item 8. Financial Statements and Supplementary
Data—Note 18.
On January 2, 2018, MPLX entered into a term loan agreement with a syndicate of lenders providing for a
$4.1 billion, 364-day term loan facility. MPLX drew the entire amount of the term loan facility in a single
borrowing on February 1, 2018. The proceeds from the term loan facility were used to fund the cash portion of
the dropdown consideration for Refining Logistics and Fuels Distribution.
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 unsecured senior notes due March 2023,
$1.25 billion aggregate principal amount of 4.0 percent unsecured senior notes due March 2028, $1.75 billion
aggregate principal amount of 4.5 percent unsecured senior notes due April 2038, $1.5 billion aggregate principal
amount of 4.7 percent unsecured senior notes due April 2048, and $500 million aggregate principal amount of
4.9 percent unsecured senior notes due April 2058. The 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. On
February 8, 2018, $4.1 billion of the net proceeds were used to repay the 364-day term loan facility. The
remaining proceeds were used to repay outstanding borrowings under the MPLX Credit Agreement and the MPC
Loan Agreement, as well as for general business purposes.
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 unsecured senior notes due
February 2029 and $1.5 billion aggregate principal amount of 5.5 percent unsecured 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 proceeds were used
to repay outstanding borrowings under the MPLX Credit Agreement and the MPC Loan Agreement, to redeem
$750 million 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.
98
On December 10, 2018, MPLX redeemed all of the $750 million 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 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.
As of December 31, 2018, we had $13.9 billion in aggregate principal amount of senior notes outstanding. The
increase compared to year-end 2017 resulted from the February 2018 and November 2018 public offerings of
senior notes, offset by the redemption of the 5.5 percent senior notes due February 2023. As of December 31,
2018, minimum principal payments due during the next five years include $500 million to repay our
3.375 percent senior notes due March 2023 and $1 billion to repay our 4.5 percent senior notes due July 2023.
For further discussion, see Item 8. Financial Statements and Supplementary Data—Note 18.
Our intention is to maintain an investment grade credit profile. As of February 1, 2019, 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
Baa3 (stable outlook)
BBB- (positive 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 MPLX Credit Agreement does 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 to below investment grade ratings would,
among other things, increase the applicable interest rates and other fees payable under the MPLX Credit
Agreement and may limit our flexibility to obtain future financing.
Our liquidity totaled $3.3 billion at December 31, 2018, consisting of:
(In millions)
MPLX LP—bank revolving credit facility expiring 2022(1)
MPC Investment—loan agreement
Total
Cash and cash equivalents
Total liquidity
December 31, 2018
Total Capacity
Outstanding
Borrowings
Available
Capacity
$
$
2,250 $
1,000
3,250 $
(3) $
—
(3)
$
2,247
1,000
3,247
68
3,315
(1) Outstanding borrowings include $3 million in letters of credit outstanding under this facility.
We expect our ongoing sources of liquidity to include cash generated from operations, 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.
MPC manages our cash and cash equivalents on our behalf directly with third-party institutions as part of the
treasury services that it provides to us under our omnibus agreement. From time to time, we may also consider
utilizing other sources of liquidity, including the formation of joint ventures or sales of non-strategic assets.
99
Equity and Preferred Units Overview
The following table summarizes the changes in the number of units outstanding through December 31, 2018:
(In units)
Common
Class B
General Partner
Total
Balance at December 31, 2015
Unit-based compensation awards
Issuance of units under the ATM Program
Contribution of HSM
Class B Conversion
Class A Reorganization
Balance at December 31, 2016
Unit-based compensation awards
Issuance of units under the ATM Program
Contribution of HST/WHC/Terminals
Contribution of the Joint-Interest Acquisition
Class B Conversion
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
7,981,756
296,687,176
—
120,989
—
26,347,887
22,534,002
—
4,350,057 (3,990,878)
—
7,153,177
3,990,878
357,193,288
—
268,167
—
13,846,998
—
12,960,376
18,511,134
—
4,350,057 (3,990,878)
6,800,475
2,470
537,710
459,878
7,330
(436,758)
7,371,105
5,472
282,591
264,497
377,778
7,330
— 8,308,773
140
—
311,469,407
123,459
26,885,597
22,993,880
366,509
6,716,419
368,555,271
273,639
14,129,589
13,224,873
18,888,912
366,509
415,438,793
348,527
— 2,277,778
— (10,586,691)
113,888,889
264,413,309
—
— 794,089,518
407,130,020
348,387
111,611,111
275,000,000
794,089,518
For more details on equity activity, see Item 8. Financial Statements and Supplementary Data—Notes 8 and 9.
Preferred Units
On May 13, 2016, MPLX completed the private placement of approximately 30.8 million 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 preferred units rank senior to all common units with respect to distributions and rights upon liquidation. The
holders of the 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
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 preferred
unitholders during the years ended December 31, 2018, 2017 and 2016 were $71 million, $65 million and
$25 million, respectively.
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 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.
100
Reorganization Transactions
On September 1, 2016, MPLX and various affiliates initiated a series of reorganization transactions in order to
simplify MPLX’s ownership structure and its financial and tax reporting requirements. In connection with these
transactions, all issued and outstanding MPLX LP Class A units were either distributed to or purchased by MPC
in exchange for $84 million in cash, 21,401,137 MPLX LP common units and 436,758 MPLX LP general partner
units. MPC also contributed $141 million to facilitate the repayment of intercompany debt between MarkWest
Hydrocarbon, L.L.C. (“MarkWest Hydrocarbon”), and MarkWest. As a result of these transactions, the MPLX
LP Class A units were eliminated, are no longer outstanding and no longer participate in distributions of cash
from MPLX. See additional discussion in Item 8. Financial Statements and Supplementary Data—Notes 8
and 12.
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.
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 year ended December 31, 2018.
In 2017 and 2016, the sale of common units under the ATM Program generated net proceeds of approximately
$473 million and $776 million, respectively. 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 $208 million per
quarter, or $834 million per year, based on the number of common and general partner units. On January 25,
2019, we announced that the board of directors of our general partner had declared a distribution of $0.6475 per
common unit that was paid on February 14, 2019 to common unitholders of record on February 5, 2019. This
represents a 7 percent increase over the fourth quarter 2017 distribution. We have provided distribution growth
guidance of $.01 per unit each quarter for 2019. This increase in the distribution is consistent with our intent to
maintain an attractive distribution growth profile over the long term. 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.
MPC 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.
101
The allocation of total quarterly cash distributions to general and limited partners is as follows for the years
ended December 31, 2018, 2017 and 2016. 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.
(In millions)
Distribution declared:
Limited partner units—public
Limited partner units—MPC
General partner units—MPC
IDRs—MPC
Total GP & LP distribution declared
Redeemable 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,
Capital Expenditures
2018
2017
2016
$
$
$
$
732 $
1,253
—
—
1,985
75
2,060 $
0.6175 $
0.6275
0.6375
0.6475
2.5300 $
656 $
338
18
211
1,223
65
1,288 $
0.5400 $
0.5625
0.5875
0.6075
2.2975 $
533
159
18
187
897
41
938
0.5050
0.5100
0.5150
0.5200
2.0500
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.
102
Our capital expenditures for the past three years are shown in the table below:
(In millions)
Capital expenditures(1):
Maintenance
Growth
Total capital expenditures
Less: Increase (decrease) in capital accruals
Asset retirement expenditures
Additions to property, plant and equipment
Capital expenditures of unconsolidated subsidiaries(2)
Total gross capital expenditures
Less: Joint venture partner contributions
Total capital expenditures, net
Acquisition, net of cash acquired
Total Capital Expenditures, net and acquisitions
Less: Maintenance capital expenditures
Acquisition, net of cash acquired
Total growth capital expenditures
2018
2017
2016
$
$
146
1,884
2,030
104
7
1,919
421
2,340
196
2,144
451
2,595
146
451
1,998
$
$
103
1,381
1,484
71
2
1,411
384
1,795
169
1,626
249
1,875
108
249
1,518
$
$
84
1,213
1,297
(22)
6
1,313
131
1,444
64
1,380
—
1,380
88
—
1,292
(1)
(2)
Includes capital expenditures of the Predecessor for all periods presented.
Includes amounts related to unconsolidated, Partnership-operated subsidiaries. Contributions by MPLX to
our equity method investments in 2018, 2017 and 2016 totaled $341 million, $761 million and $87 million
respectively.
Our organic growth capital plan for 2019 is $2.2 billion. The L&S organic growth capital plan includes the
continued expansion of MPLX’s marine fleet. We also have other projects including long-haul crude oil, natural
gas and NGL pipelines as well as projects to increase our export capability which will further enhance our L&S
segment full value chain capture. The G&P segment organic growth capital plan includes the addition of
approximately 765 MMcf/d of processing capacity at five gas processing plants, two in the Marcellus and three
in the Southwest, which expands MPLX’s processing capacity in the Permian Basin and the STACK shale play
of Oklahoma. The G&P segment capital plan also includes the addition of approximately 100 mbpd of
fractionation capacity in the Marcellus and Utica basins. We continuously evaluate our capital plan and make
changes as conditions warrant.
103
Contractual Cash Obligations
The table below provides aggregated information on our consolidated obligations to make future payments under
existing contracts as of December 31, 2018:
(In millions)
Total
2019
2020 & 2021
2022 & 2023
Thereafter
Bank revolving credit facility(1)
Long-term debt(1)
Capital lease obligations
Operating leases(2)
Purchase obligations:
Contracts to acquire property,
plant & equipment
Other contracts
Total purchase obligations(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)
Total contractual cash
obligations
$
17 $
5 $
9 $
3 $
24,841
7
1,051
746
3,077
3,823
27
195
424
613
1
73
743
294
1,037
6
17
52
30
—
1,285
6
138
2,776
—
121
3
142
145
14
34
100
—
—
131
131
7
34
93
—
—
20,167
—
719
—
2,510
2,510
—
110
179
30
$
30,415 $
1,804 $
1,731 $
3,165 $
23,715
(1) Amounts represent outstanding borrowings at December 31, 2018, plus any commitment and administrative
fees and interest.
(2) Amounts relate primarily to leases associated with Refining Logistics as well as to our office, railcar, and
vehicle leases.
(3) Represents purchase orders and contracts related to the purchase or build out of property, plant and
equipment. Purchase obligations exclude current and long-term unrealized losses on derivative instruments
included on the accompanying Consolidated Balance Sheets, which represent the current fair value of
various derivative contracts and do not represent future cash purchase obligations. These contracts are
generally settled financially at the difference between the future market price and the contractual price and
may result in cash payments or cash receipts in the future, but generally do not require delivery of physical
quantities of the underlying commodity.
(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 17 for the fair value of the frac spread
sharing component). We use the estimated future frac spreads as of December 31, 2018 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 25 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 three to ten 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.
104
(7)
Excludes estimated accretion expense of $31 million. The total amount to be paid is approximately
$61 million.
In addition to the obligations included in the table above, we have an omnibus agreement and employee services
agreements with MPC. The omnibus agreement 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. Under the omnibus
agreement, we paid to MPC in equal monthly installments an annual amount of approximately $152 million in
2018 for the provision of services by MPC, such as information technology, engineering, legal, accounting,
treasury, human resources and other administrative services. The annual amount includes a fixed annual fee of
approximately $14 million for the provision of certain executive management services by certain officers of 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
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, including those in support of HST, WHC, MPLXT and HSM. We incurred
$640 million of expenses under the employee services agreements for 2018.
Off-Balance Sheet Arrangements
As of December 31, 2018, 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, 2018, 2017
or 2016. 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, 2018, MPC owned our general partner and approximately 63.6 percent limited partner
interest in us.
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 46 percent, 36 percent and 41 percent of our
total revenues and other income for 2018, 2017 and 2016, respectively. We provide crude oil and product
pipeline transportation services based on regulated tariff rates and storage services and inland marine
transportation based on contracted rates.
Of our total costs and expenses, MPC accounted for 27 percent, 22 percent and 23 percent for 2018, 2017 and
2016, respectively. MPC performed certain services for us related to information technology, engineering, legal,
accounting, treasury, human resources and other administrative services.
105
We believe that transactions with related parties were 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—Our
L&S Contracts with MPC and Third Parties and Item 8. Financial Statements and Supplementary Data—Note 6.
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 Clean Air Act 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 under the omnibus agreement.
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)
2018
2017
2016
Capital
Percent of total capital expenditures
Compliance:
Operating and maintenance
Remediation(1)
Total
$
$
$
27
1%
31
8
39
$
$
$
5
—%
26
4
30
$
$
$
12
1%
95
10
105
(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 $11 million in 2019. Actual expenditures
may vary as the number and scope of environmental projects are revised as a result of improved technology or
106
changes in regulatory requirements and could increase if additional projects are identified or additional
requirements are imposed. The amount of expenditures in 2019 is also dependent upon the resolution of the
matters described in Item 3—Legal Proceedings, which may require us to complete additional projects and
increase our actual environmental capital and operating expenditures.
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 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. 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 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.
107
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 16 for disclosures regarding our fair value
measurements.
Significant uses of fair value measurements include:
•
•
•
•
•
•
assessment of impairment of long-lived assets;
assessment of impairment of intangible assets:
assessment of impairment of goodwill;
assessment of impairment of equity method investments;
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 Net operating margins. Our estimates of future Net operating margins 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. These throughput assumptions depend, in part, on expected
commodity prices. Assumptions about our customers’ drilling activity and future commodity prices are
inherently subjective and contingent upon a number of variable factors, many of which are difficult to
forecast. Management considers the sustained reduction of commodity prices in forecasted cash flows.
• 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
108
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. We have 12 reporting
units, eight of which have goodwill allocated to them. At December 31, 2018, we had a total of $2.6 billion of
goodwill recorded on the Consolidated Balance Sheets. The fair value of our reporting units exceeded book value
for each of our reporting units in 2018.
MPLX had eight reporting units with goodwill totaling approximately $2.6 billion as of November 30, 2018. Step
1 of the annual impairment analysis resulted in the fair value of the reporting units exceeding their carrying value
by percentages ranging from approximately 14 percent to 5,330 percent. The reporting unit with fair value
exceeding its carrying value by approximately 14 percent has goodwill of $228 million at December 31, 2018.
An increase of one percentage point to the discount rate used to estimate the fair value of the reporting units
would not have resulted in a goodwill impairment charge as of November 30, 2018. Significant assumptions used
to estimate the reporting units’ fair value included estimates of future cash flows. If estimates for future cash
flows, which are impacted primarily by commodity prices and producer customers’ development plans (which
impact 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.
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. At December 31, 2018, we had $4.2 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.
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
109
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. See Item 8. Financial Statements and Supplementary Data—Note 16 for additional information on
fair value measurements.
Derivatives
We record all derivative instruments at fair value on the Consolidated Balance Sheets. 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, 2018, we believe there is a 90 percent and 80 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 2020, 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,
2018 would have affected income before taxes by $6.1 million for the year ended December 31, 2018. If the
probabilities of renewal for the Natural Gas Embedded Derivative were changed to 80 percent and 70 percent,
the liability would have been reduced by $3.9 million as of December 31, 2018. If the probabilities of renewal for
the Natural Gas Embedded Derivative were changed to 95 percent and 90 percent, the liability would have been
increased by $2.9 million as of December 31, 2018. Fair value estimation for all our derivative instruments is
discussed in Item 8. Financial Statements and Supplementary Data—Note 16 and Note 17. 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.
110
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 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 8. Financial Statements and Supplementary Data—
Note 25.
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,
2018, 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.
111
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. 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 primarily 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 primarily 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.
As a result of our derivative positions held during the fourth quarter, we have mitigated a portion of our expected
commodity price risk. 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,
these 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
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, 2018 and 2017, the estimated fair value of this contract was a liability of
$61 million and $64 million, respectively.
Open Derivative Positions and Sensitivity Analysis
As of December 31, 2018, we have no open commodity derivative contracts. 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, 2018 would not have affected income before income taxes for the
year ended December 31, 2018. 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.
112
Interest Rate Risk
Sensitivity analysis of the effect of a hypothetical 100-basis-point change in interest rates on long-term debt,
excluding capital leases, is provided in the following table. Fair value of cash and cash equivalents, receivables,
accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in
interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from
the table.
(In millions)
Long-term debt
Fixed-rate
Variable-rate
Fair Value as of
December 31,
2018(1)
Change in Fair
Value (2)
Change in Income
before income
taxes for the Year
Ended
December 31,
2018 (3)
$
$
13,169
—
$
1,357
N/A
$
N/A
2
(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, 2018.
(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, 2018.
At December 31, 2018, our portfolio of long-term debt consisted of fixed-rate instruments and variable-rate
instruments under our revolving credit facility, of which we had no outstanding balance at December 31, 2018.
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, 2018, 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 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. 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 are 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. These 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.
113
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
115
115
116
118
119
120
121
122
123
178
114
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/ Gary R. Heminger
/s/ Pamela K.M. Beall
/s/ C. Kristopher Hagedorn
Gary R. Heminger
Chairman of the Board of Directors
and Chief Executive Officer
of MPLX GP LLC
(the general partner of MPLX LP)
Pamela K.M. Beall
Director, Executive Vice President
and Chief Financial Officer
of MPLX GP LLC
(the general partner of MPLX LP)
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 Rules 13a-15(f) and 15d-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, 2018.
The effectiveness of MPLX LP’s internal control over financial reporting as of December 31, 2018 has been
audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their
report which is included herein.
/s/ Gary R. Heminger
/s/ Pamela K.M. Beall
Gary R. Heminger
Chairman of the Board of Directors
and Chief Executive Officer
of MPLX GP LLC
(the general partner of MPLX LP)
Pamela K.M. Beall
Director, Executive Vice President
and Chief Financial Officer of
MPLX GP LLC
(the general partner of MPLX LP)
115
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, 2018 and 2017, and the related consolidated statements of income,
comprehensive income, cash flows, and equity for each of the three years in the period ended December 31,
2018, 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, 2018, 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, 2018 and 2017, and the results of its operations and its
cash flows for each of the three years in the period ended December 31, 2018 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, 2018, 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
116
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 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.
/s/PricewaterhouseCoopers LLP
Toledo, Ohio
February 28, 2019
We have served as the Company’s auditor since 2012.
117
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/(loss) 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 $33 million, $32 million, and
$28 million, respectively)
Other financial costs
Income before income taxes
Provision/(benefit) 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: 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
$
$
$
$
2018
2017
2016
1,704 $
2,159
198
349
718
902
49
240
7
99
6,425
1,156 $
1,082
—
277
279
889
8
78
6
92
3,867
948
845
135
5
860
766
—
291
72
3,922
2,503
5
534
122
1,842
8
1,834
16
—
1,818
75
—
528
651
62
2
455
683
—
241
54
2,676
1,191
2
296
56
837
1
836
6
36
794
65
318
1,743 $
411 $
2.29 $
2.29 $
1.07 $
1.06 $
761
761
385
388
958
936
—
298
235
572
11
(74)
7
86
3,029
454
448
57
1
388
591
130
227
50
2,346
683
1
210
50
422
(12)
434
2
199
233
41
191
1
—
—
331
338
The accompanying notes are an integral part of these consolidated financial statements.
118
MPLX LP
Consolidated Statements of Comprehensive Income
(In millions)
Net income
Other comprehensive (loss)/income, 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
2018
2017
2016
$
1,834
$
836
$
(2)
1,832
16
—
—
836
6
36
Comprehensive income attributable to MPLX LP
$
1,816
$
794
$
The accompanying notes are an integral part of these consolidated financial statements.
434
—
434
2
199
233
119
(In millions)
Assets
Current assets:
Cash and cash equivalents
Receivables, net
Receivables—related parties
Inventories
Other current assets
Total current assets
Equity method investments
Property, plant and equipment, net
Intangibles, net
Goodwill
Long-term receivables—related parties
Other noncurrent assets
Total assets
Liabilities
Current liabilities:
Accounts payable
Accrued liabilities
Payables—related parties
Deferred revenue—related parties
Accrued property, plant and equipment
Accrued interest payable
Other current liabilities
Total current liabilities
Long-term deferred revenue
Long-term deferred revenue—related parties
Long-term debt
Deferred income taxes
Deferred credits and other liabilities
Total liabilities
MPLX LP
Consolidated Balance Sheets
December 31,
2018
2017
$
$
68
417
289
77
46
897
4,174
14,639
424
2,586
24
35
22,779
162
250
203
51
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
5
292
160
65
37
559
4,010
12,187
453
2,245
20
26
19,500
151
231
516
43
194
88
81
1,304
42
43
6,945
5
188
8,527
1,000
8,379
2,099
(637)
(14)
9,827
146
9,973
Commitments and contingencies (see Note 25)
Redeemable preferred units
Equity
Common unitholders—public (289 million and 289 million units issued and
outstanding)
Common unitholder—MPC (505 million and 118 million units issued and outstanding)
General partner—MPC (0 million and 8 million units issued and outstanding)
Accumulated other comprehensive loss
Total MPLX LP partners’ capital
Noncontrolling interests
Total equity
Total liabilities, preferred units and equity
$
22,779
$
19,500
The accompanying notes are an integral part of these consolidated financial statements.
120
MPLX LP
Consolidated Statements of Cash Flows
(In millions)
2018
2017
2016
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:
$
1,834
$
836
$
Amortization of deferred financing costs
Depreciation and amortization
Impairment expense
Deferred income taxes
Asset retirement expenditures
Loss/(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
Receivables from/liabilities to related parties
Prepaid other current assets from related parties
Deferred revenue
All other, net
59
766
—
8
(7)
2
(240)
400
(122)
(5)
(10)
100
(50)
7
39
45
53
683
—
(1)
(2)
—
(78)
241
8
(3)
6
48
63
(8)
33
28
434
46
591
130
(17)
(6)
(1)
74
148
(52)
(8)
43
102
(19)
—
10
16
Net cash provided by operating activities
2,826
1,907
1,491
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
Issuance of redeemable preferred units
Distributions to preferred unitholders
Distributions to MPC for acquisitions
Distributions to MPC from Predecessor
Distributions to unitholders and general partner
Distributions to noncontrolling interests
Contributions from MPC
Contributions from noncontrolling interests
Consideration payment to Class B unitholders
All other, net
Net cash (used in)/provided by financing activities
Net increase/(decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
$
(1,919)
(451)
—
8
(341)
16
1
(2,686)
13,186
(6,780)
3,962
(4,347)
(76)
—
—
(71)
(4,111)
—
(1,819)
(17)
—
11
—
(11)
(73)
67
9
76
(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
$
(1,313)
—
(17)
1
(87)
—
(1)
(1,417)
434
(1,312)
2,532
(2,540)
—
792
984
(25)
—
(104)
(845)
(3)
225
6
(25)
(6)
113
187
52
239
The accompanying notes are an integral part of these consolidated financial statements.
121
MPLX LP
Consolidated Statements of Equity
Partnership
Common
Unitholders
Public
Class B
Unitholders
Public
Common
Unitholder
MPC
General
Partner
MPC
Accumulated
Other
Comprehensive
Loss
Non-
controlling
Interests
Equity of
Predecessor
Total
$
7,691
$
266
$
465
$
819
$
— $
13
$
692
$ 9,946
(In millions)
Balance at December 31, 2015
Net (loss)/income (excludes
amounts attributable to
preferred units)
Unit issuances under ATM
Program
Class B unit conversion
Deferred income tax impact from
changes in equity
Allocation of MPC’s net
investment at acquisition
Distributions to:
MPC from Predecessor
Unitholders and GP
Noncontrolling interests
MPC of MarkWest
Hydrocarbon
Contributions from:
MPC
MPC (non-cash)
Noncontrolling interests
MPC of MarkWest
Hydrocarbon
Other
(5)
776
133
(2)
—
—
(513)
—
—
—
—
—
—
6
Balance at December 31, 2016
8,086
Net income (excludes amounts
attributable to 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 acquisitions
Unitholders and GP
Noncontrolling interests
MPC of cash received from
Joint-Interest Acquisition
entities
Contributions from:
MPC
Noncontrolling interests
Other
Balance at December 31, 2017
Net income (excludes amounts
attributable to preferred units)
Allocation of MPC’s net
investment at acquisition
Conversion of GP economic
interests
Distributions to:
MPC for acquisitions
Unitholders
Noncontrolling interests
Contributions from:
MPC
Noncontrolling interests
Other
301
473
133
—
—
—
(622)
—
—
—
—
8
8,379
667
—
—
—
(722)
—
—
—
12
—
—
(133)
—
—
—
—
—
—
—
—
—
—
—
133
—
—
(133)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
6
—
—
(13)
669
—
(142)
—
—
84
—
—
—
—
191
16
—
(2)
(337)
—
(190)
—
563
141
—
—
(188)
—
1,069
1,013
110
—
—
318
10
—
1,669
(266)
—
(537)
(212)
—
—
(1,394)
(286)
—
—
—
—
—
2,099
1,076
(32)
—
—
—
(637)
—
5,172
(4,126)
(7,926)
7,926
(936)
(1,097)
—
(3,164)
—
—
—
—
—
—
—
1
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(14)
—
—
(14)
—
—
—
—
—
—
—
—
(2)
2
—
—
—
—
—
—
(3)
—
—
—
6
—
—
18
6
—
—
—
—
—
—
(7)
—
—
129
—
146
16
—
—
—
—
(17)
—
11
—
199
—
—
—
(332)
(104)
—
—
—
—
336
—
—
—
791
36
—
—
(1,403)
(113)
—
—
—
—
689
—
—
—
—
(1,046)
—
—
—
—
1,046
—
—
393
792
—
(17)
—
(104)
(845)
(3)
563
225
336
6
(188)
6
11,110
771
483
—
—
(113)
(1,931)
(1,120)
(7)
(32)
675
129
8
9,973
1,759
—
—
(4,100)
(1,819)
(17)
1,046
11
11
Balance at December 31, 2018
$
8,336
$
— $
(1,612) $
— $
(16) $
156
$
— $
6,864
The accompanying notes are an integral part of these consolidated financial statements.
122
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.
MPLX is engaged in the gathering, processing and transportation of natural gas; the gathering, transportation,
fractionation, storage and marketing of NGLs; and the transportation, storage and distribution of crude oil and
refined petroleum products. 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.
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. 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 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—As a result of the adoption of the new revenue recognition standard, as described further
in Note 3, MPLX has updated its policies as they relate to 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,
123
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.
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 “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.
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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
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. At December 31, 2018 and 2017,
the amount of restricted cash included in “Other current assets” on the Consolidated Balance Sheets was
$8 million and $4 million, respectively.
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Receivables—Receivables primarily consist of customer accounts receivable, which are recorded at the invoiced
amount and generally do not bear interest. Management reviews the allowance quarterly. Past-due balances
over 90 days and other higher- risk amounts are 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.
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.
Interest costs for the construction or development of long-lived assets are capitalized and amortized over the
related asset’s estimated useful life.
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.
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 and compared to the
carrying value of the reporting unit. The fair value is calculated using the expected present value of future cash
flows method. Significant assumptions used in the cash flow forecasts include future Net operating margins,
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 implied fair value of goodwill is calculated. The excess, if any, of the
book value over the implied fair value of goodwill 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 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.
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There were no impairments as a result of MPLX’s November 30, 2018 and November 30, 2017 annual goodwill
impairment analyses. During 2016, impairment charges of approximately $130 million were recorded.
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.
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.
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 uses 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
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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, 2018, 2017 and 2016, 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.
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 16). Derivative instruments are recorded at fair value, based on available market information (see
Note 17).
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 16.
Equity-Based Compensation Arrangements—MPLX issues phantom units under its share-based compensation
plan as described further in Note 22. 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.
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 federal income tax purposes. As a result of the MarkWest
Merger, MarkWest was the surviving entity for tax purposes. MarkWest is not a taxable entity for federal income
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tax purposes. As such, MPLX does not directly pay federal 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 preferred unitholders based on a fixed distribution schedule, as discussed in Note 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, preferred units, certain equity-based
compensation awards and eliminated IDRs. Class B units are considered to be a separate class of common units
that do 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 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 will be 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.
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
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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. For all material acquisitions, management engages 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. 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 which 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.
3. Accounting Standards
Recently Adopted
ASU 2014-09, Revenue—Revenue from Contracts with Customers
In May 2014, the FASB issued ASU 2014-09, which created ASC Topic 606 (“ASC 606”), Revenue from
Contracts with Customers. The guidance in ASC 606 states that revenue is recognized when a customer obtains
control of a good or service. Recognition of revenue involves a multiple step approach including identifying the
contract, identifying the separate performance obligations, determining the transaction price, allocating the price to
the performance obligations and recognizing revenue as the obligations are satisfied. Additional disclosures are
required to provide adequate information to understand the nature, amount, timing and uncertainty of reported
revenues and revenues expected to be recognized. MPLX adopted the standard as of January 1, 2018 using the
modified retrospective method by recognizing the cumulative effect of initially applying the new revenue standard
as an adjustment to opening equity. The comparative information has not been restated and continues to be
reported under the accounting standards in effect for those periods. See Note 19 for further details.
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We also adopted the following standards during 2018, none of which had a material impact to our financial
statements or financial statement disclosures:
ASU
Effective Date
2017-09
2017-05 Gains and Losses from the Derecognition of Nonfinancial Assets—Clarifying the
Stock Compensation—Scope of Modification Accounting
January 1, 2018
January 1, 2018
Scope of Asset Derecognition Guidance
2017-01 Business Combinations—Clarifying the Definition of a Business
2016-18
2016-15
Statement of Cash Flows—Restricted Cash
Statement of Cash Flows—Classification of Certain Cash Receipts and Cash
Payments
Financial Instruments—Recognition and Measurement of Financial Assets and
Liabilities
2016-01
January 1, 2018
January 1, 2018
January 1, 2018
January 1, 2018
Not Yet Adopted
ASU 2017-12, Derivatives and Hedging - Targeted Improvements to Accounting for Hedging Activities
In August 2017, the FASB issued an ASU to amend the hedge accounting rules to simplify the application of
hedge accounting guidance and better portray the economic results of risk management activities in the financial
statements. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces
complexity in fair value hedges of interest rate risk, eliminates the requirement to separately measure and report
hedge ineffectiveness and eases certain hedge effectiveness assessment requirements. The guidance is effective
beginning in 2019 with early adoption permitted. We do not expect the adoption of this ASU to have a material
impact on our consolidated financial statements.
ASU 2017-04, Intangibles - Goodwill and Other - Simplifying the Test for Goodwill Impairment
In January 2017, the FASB issued an ASU which simplifies the subsequent measurement of goodwill by
eliminating Step 2 from the goodwill impairment test. Under the new guidance, the recognition of an impairment
charge is calculated based on the amount by which the carrying amount exceeds the reporting unit’s fair value,
which could be different from the amount calculated under the current method using the implied fair value of the
goodwill; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting
unit. The guidance should be applied on a prospective basis, and is effective for annual or any interim goodwill
impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or
annual goodwill impairment tests performed on testing dates after January 1, 2017.
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. MPLX does not
expect application of this ASU to have a material impact on our consolidated financial statements.
ASU 2016-02, Leases and related updates
In February 2016, the FASB issued an ASU requiring lessees to record virtually all leases on their balance sheets.
The ASU also requires expanded disclosures to help financial statement users better understand the amount,
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timing and uncertainty of cash flows arising from leases. For lessors, this amended guidance modifies the
classification criteria and the accounting for sales-type and direct financing leases. The guidance will be effective
for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption
permitted. As of January 1, 2019, we have transitioned to the new guidance.
As part of implementing this standard, MPLX evaluated the impact to our financial statements, disclosures,
internal controls and accounting policies. This evaluation process included reviewing all forms of leases,
performing a completeness assessment over the lease population and analyzing the practical expedients in order
to determine the best path of implementing changes to existing processes and controls. We have implemented a
third-party supported lease accounting information system to account for our lease population in accordance with
this new standard and established internal controls over the new system. We expect that adoption of the standard
will result in the recognition of right-of-use assets and lease liabilities for operating leases in the range of
$450 million to $550 million. The adoption of ASC 842 will not have a material impact on our consolidated
statements of income or cash flows, except for the potential effects from lease modifications as discussed below.
In addition, based on the changes presented in the standard, MPLX, as a lessor, may be required to re-classify
existing operating leases to sales-type leases upon modification and related reassessment of the leases. If such a
modification were to occur, it may result in the de-recognition of existing assets, recognition of a receivable in
the amount of the present value of fixed payments expected to be received by MPLX under the lease, and
recognition of a corresponding gain or loss in the period of change. MPLX will evaluate the impact of a lease
reassessment as modifications occur.
4. Acquisitions
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. The terminal includes 4 million barrels of
third-party leased storage capacity and a 120 mbpd dock. 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.
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
126
(17)
(7)
451
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 expand and construct an additional dock at the site. All
of the goodwill recognized related to this transaction is tax deductible.
132
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 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.
The Refining Logistics assets include 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-
133
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-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 LP 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 LP retaining the portion of
distributions beginning on the closing date. All amounts distributed to MPLX LP related to periods before the
acquisition have been paid to MPC. Additionally, MPLX LP 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 LP 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/(loss) from equity method investments” for the
twelve months ended December 31, 2018 and December 31, 2017 totaled $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.
134
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 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
135
Twelve Months
Ended
December 31,
2017
$
$
64
20
Assuming the acquisition of the Ozark pipeline had occurred on January 1, 2016, the consolidated pro forma
results would not have been materially different from reported results.
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/(loss) from equity method investments” for the twelve months ended
December 31, 2018 and December 31, 2017 totaled $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.
Acquisition of Hardin Street Marine LLC
On March 14, 2016, MPLX entered into a Membership Interests Contribution Agreement with MPLX GP,
MPLX Logistics and MPC Investment (each a wholly-owned subsidiary of MPC), related to the acquisition of
HSM, MPC’s inland marine business, from MPC. Pursuant to the agreement, the transaction was valued at
$600 million, consisting of a fixed number of common units and general partner units of 22,534,002 and
459,878, respectively. The general partner units maintained MPC’s two percent GP Interest in MPLX. The
acquisition closed on March 31, 2016 and the fair value of the common units and general partner units issued was
$669 million and $14 million, respectively. MPC agreed to waive distributions in the first quarter of 2016 on
common units issued in connection with this transaction. As a result of this waiver, MPC did not receive general
partner distributions or IDRs that would have otherwise accrued on such common units with respect to the first
quarter 2016 distributions. The value of these waived distributions was $15 million.
The inland marine business, comprised of 18 tow boats and 219 owned and leased barges as of the acquisition
date, which transport light products, heavy oils, crude oil, renewable fuels, chemicals and feedstocks in the
Midwest and Gulf Coast regions of the United States, accounted for nearly 60 percent of the total volumes MPC
shipped by inland marine vessels as of March 31, 2016. MPLX accounts for HSM within its L&S segment.
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5. Investments and Noncontrolling Interests
The following table presents MPLX’s equity method investments at the dates indicated:
(In millions, except ownership percentages)
Explorer
Illinois Extension Pipeline
LOCAP
LOOP
MarEn Bakken
Centrahoma Processing LLC
MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C.
MarkWest Utica EMG, L.L.C.
Sherwood Midstream LLC
Sherwood Midstream Holdings LLC
Other
Total
Ownership as of
December 31,
2018
25%
35%
59%
41%
25%
40%
67%
56%
50%
60%
$
$
Carrying value at
December 31,
2018
2017
90 $
275
27
226
498
160
236
2,039
366
157
100
4,174 $
89
284
24
225
520
121
164
2,139
236
165
43
4,010
Summarized financial information for MPLX’s equity method investments for the years ended December 31,
2018, 2017 and 2016 is as follows:
(In millions)
December 31, 2018
MarkWest Utica
EMG, L.L.C.
Other VIEs
Non-VIEs
Total
Revenues and other income
Costs and expenses
Income from operations
Net income
(Loss)/income from equity method investments(1)
$
$
238
184
54
53
(10)
(In millions)
Revenues and other income
Costs and expenses
Income from operations
Net income
Income from equity method investments(1)
(In millions)
MarkWest Utica
EMG, L.L.C.
$
$
187
97
90
90
10
MarkWest Utica
EMG, L.L.C.
Revenues and other income
Costs and expenses
Income/(loss) from operations
Net income/(loss)
Income/(loss) from equity method investments(1)
$
$
216
100
116
114
8
$
$
$
$
234
95
139
139
74
$
$
1,364 $
709
655
584
176 $
1,836
988
848
776
240
December 31, 2017
Other VIEs
Non-VIEs
Total
86
42
44
43
20
$
$
954 $
520
434
345
48 $
1,227
659
568
478
78
December 31, 2016
$
Other VIEs(2)
18
$
111
(93)
(93)
(89) $
$
Non-VIEs
Total
148 $
117
31
31
7 $
382
328
54
52
(74)
(1)
(2)
“Income/(loss) from equity method investments” includes the impact of any basis differential amortization
or accretion.
Includes an impairment charge of $89 million for the year ended December 31, 2016 related to MPLX’s
investment in Ohio Condensate Company, L.L.C., which does not appear separately in this table.
137
Summarized balance sheet information for MPLX’s equity method investments as of December 31, 2018 and
2017 is as follows:
(In millions)
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
(In millions)
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
MarkWest Utica
EMG, L.L.C.(1)
$
$
82 $
1,939
28
3 $
December 31, 2018
Other VIEs
Non-VIEs
Total
153 $
1,596
127
186 $
379 $
4,715
246
841 $
December 31, 2017
MarkWest Utica
EMG, L.L.C.(1)
Other VIEs
Non-VIEs
Total
$
$
65
2,077
39
3
$
$
46
930
44
11
$
$
399 $
4,624
220
904 $
614
8,250
401
1,030
510
7,631
303
918
(1) MarkWest Utica EMG, L.L.C (“MarkWest Utica EMG”), noncurrent assets include its investment in its
subsidiary Ohio Gathering Company, L.L.C. (“Ohio Gathering”), which does not appear elsewhere in this
table. The investment was $750 million and $790 million as of December 31, 2018 and 2017, respectively.
As of December 31, 2018 and 2017, the carrying value of MPLX’s equity method investments exceeded the
underlying net assets of its investees by $1.0 billion for the G&P segment. As of December 31, 2018 and 2017,
the carrying value of MPLX’s equity method investments in the L&S segment exceeded the underlying net assets
of its investees by $114 million and $118 million, respectively. This basis difference is being amortized into net
income over the remaining estimated useful lives of the underlying net assets, except for $459 million and
$39 million of excess related to goodwill for the G&P and L&S segments, respectively.
MarkWest Utica EMG
Effective January 1, 2012, MarkWest Utica Operating Company, L.L.C. (“Utica Operating”), a wholly-owned
and consolidated subsidiary of MPLX, and EMG Utica, LLC (“EMG Utica” and together with Utica Operating,
the “Members”) executed agreements to form a joint venture, MarkWest Utica EMG, to develop significant
natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure in eastern
Ohio. The related limited liability company agreement has been amended from time to time (the limited liability
company agreement currently in effect is referred to as the “Amended LLC Agreement”). The aggregate funding
commitment of EMG Utica was $950 million. Thereafter, Utica Operating was required to fund, as needed,
100 percent of future capital for MarkWest Utica EMG until the aggregate capital that had been contributed by
the Members reached $2.0 billion, which occurred prior to the MarkWest Merger. Until such time as the
investment balances of Utica Operating and EMG Utica are in the ratio of 70 percent and 30 percent, respectively
(such time being referred to as the “Second Equalization Date”), EMG Utica will have the right, but not the
obligation, to fund up to ten percent of each capital call for MarkWest Utica EMG, and Utica Operating will be
required to fund all remaining capital not elected to be funded by EMG Utica. After the Second Equalization
Date, Utica Operating and EMG Utica will have the right, but not the obligation, to fund their pro rata portion
(based on their respective investment balances) of any additional required capital and may also fund additional
capital that the other party elects not to fund. As of December 31, 2018, EMG Utica has contributed
approximately $1.2 billion and Utica Operating has contributed approximately $1.5 billion to MarkWest Utica
EMG.
138
Under the Amended LLC Agreement, prior to December 31, 2016, EMG Utica’s investment balance was
increased by a quarterly special non-cash allocation of income (“Preference Amount”) calculated based upon the
amount of capital contributed by EMG Utica in excess of $500 million. After December 31, 2016, no Preference
Amount will accrue to EMG Utica’s investment balance. EMG Utica received a Preference Amount totaling
approximately $16 million for the year ended December 31, 2016.
Under the Amended LLC Agreement, after December 31, 2016, cash generated by MarkWest Utica EMG that is
available for distribution will be allocated to the Members in proportion to their respective investment balances.
As of December 31, 2018, Utica Operating’s investment balance in MarkWest Utica EMG was approximately
56 percent.
MarkWest Utica EMG is deemed to be a VIE. Utica Operating is not deemed to be the primary beneficiary, due
to EMG Utica’s voting rights on significant matters. MPLX’s maximum exposure to loss as a result of its
involvement with MarkWest Utica EMG 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 MarkWest
Utica EMG that it was not contractually obligated to provide during the years ended December 31, 2018, 2017
and 2016. MPLX receives management fee revenue for engineering and construction and administrative services
for operating MarkWest Utica EMG, and is also reimbursed for personnel services (“Operational Service
revenue”). Operational Service revenue is reported as “Other income—related parties” on the Consolidated
Statements of Income. The amount of Operational Service revenue related to MarkWest Utica EMG for the years
ended December 31, 2018, 2017 and 2016 totaled $17 million, $17 million and $16 million, respectively.
Ohio Gathering
Ohio Gathering is a subsidiary of MarkWest Utica EMG and is engaged in providing natural gas gathering
services in the Utica Shale in eastern Ohio. Ohio Gathering is a joint venture between MarkWest Utica EMG and
Summit Midstream Partners, LLC. As of December 31, 2018, MPLX had an approximate 34 percent indirect
ownership interest in Ohio Gathering. As Ohio Gathering is a subsidiary of MarkWest Utica EMG, which is
accounted for as an equity method investment, MPLX reports its portion of Ohio Gathering’s net assets as a
component of its investment in MarkWest Utica EMG. MPLX receives Operational Service revenue for
operating Ohio Gathering which is reported as “Other income-related parties” on the Consolidated Statements of
Income. The amount of Operational Service revenue related to Ohio Gathering for the years ended December 31,
2018, 2017 and 2016 totaled $16 million, $16 million and $15 million, respectively.
Sherwood Midstream
Effective January 1, 2017, MarkWest Liberty Midstream & Resources, L.L.C. (“MarkWest Liberty Midstream”),
a wholly-owned and consolidated subsidiary of MPLX LP, and Antero Midstream Partners LP (“Antero
Midstream”) formed a joint venture, Sherwood Midstream LLC (“Sherwood Midstream”), to support Antero
Resources Corporation’s (“Antero Resources”) development in the Marcellus Shale. MarkWest Liberty
Midstream has a 50 percent ownership interest in Sherwood Midstream. Pursuant to the terms of the related
limited liability company agreement (the “LLC Agreement”), MarkWest Liberty Midstream contributed assets
then under construction with a fair value of approximately $134 million and cash of approximately $20 million.
Antero Midstream made an initial capital contribution of approximately $154 million.
Also effective January 1, 2017, MarkWest Liberty Midstream converted all of its ownership interests in
MarkWest Ohio Fractionation Company, L.L.C. (“Ohio Fractionation”), a previously wholly-owned subsidiary,
to Class A Interests and amended its LLC Agreement to create Class B-3 Interests, which were sold to Sherwood
Midstream for $126 million in cash. The Class B-3 Interests provide Sherwood Midstream with the right to
fractionation revenue and the obligation to pay expenses related to 20 mbpd of capacity in the Hopedale 3
fractionator. Sherwood Midstream accounts for its investment in Ohio Fractionation, which is a VIE, as an equity
139
method investment as Sherwood Midstream does not control Ohio Fractionation. MarkWest Liberty Midstream
has been deemed to be the primary beneficiary of Ohio Fractionation because it has control over the decisions
that could significantly impact its financial performance, and as a result, consolidates Ohio Fractionation. The
carrying amounts of assets and liabilities included on MPLX’s Consolidated Balance Sheets pertaining to Ohio
Fractionation at December 31, 2018, were current assets of $132 million, non-current assets of $550 million,
current liabilities of $75 million and $1 million of non-current liabilities. The creditors of Ohio Fractionation do
not have recourse to MPLX LP’s general credit through guarantees or other financial arrangements. The assets of
Ohio Fractionation are the property of Ohio Fractionation and cannot be used to satisfy the obligations of MPLX
LP. Sherwood Midstream’s interests are reflected in “Net income attributable to noncontrolling interests” on the
Consolidated Statements of Income and “Noncontrolling interests” on the Consolidated Balance Sheets.
Under the LLC Agreement, cash generated by Sherwood Midstream that is available for distribution will be
allocated to the members in proportion to their respective investment balances.
Sherwood Midstream is deemed to be a VIE. MarkWest Liberty Midstream is not deemed to be the primary
beneficiary, due to Antero Midstream’s voting rights on significant matters. MPLX’s maximum exposure to loss
as a result of its involvement with Sherwood Midstream includes its equity investment, any additional capital
contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its
compensation received for the performance of the operating services. MPLX did not provide any financial
support to Sherwood Midstream that it was not contractually obligated to provide during the years ended
December 31, 2018 and 2017. MPLX receives Operational Service revenue for operating Sherwood Midstream.
The amount of Operational Service revenue related to Sherwood Midstream for the years ended December 31,
2018 and 2017 totaled approximately $12 million and $8 million, respectively, and is reported as “Other income-
related parties” on the Consolidated Statements of Income.
Sherwood Midstream Holdings
Effective January 1, 2017, MarkWest Liberty Midstream and Sherwood Midstream formed a joint venture,
Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”), for the purpose of owning, operating
and maintaining all of the shared assets that support the operations of the gas plants and other assets owned by
Sherwood Midstream and the gas plants and de-ethanization facilities owned by MarkWest Liberty Midstream.
MarkWest Liberty Midstream initially contributed certain real property, equipment and facilities with a fair value
of approximately $209 million to Sherwood Midstream Holdings in exchange for a 79 percent initial ownership
interest. Sherwood Midstream contributed cash of approximately $44 million to Sherwood Midstream Holdings
in exchange for a 21 percent ownership interest. During the second quarter ended June 30, 2017, true-ups to the
initial contributions were finalized. MarkWest Liberty Midstream contributed certain additional real property,
equipment and facilities with a fair value of approximately $10 million to Sherwood Midstream Holdings and
Sherwood Midstream contributed cash of approximately $4 million to Sherwood Midstream Holdings.
Collectively, the real property, equipment, facilities and cash initially contributed, or that may be subsequently
constructed by or contributed, to Sherwood Midstream Holdings are referred to as the “Shared Assets.” The net
book value of the contributed assets was approximately $203 million. The contribution was determined to be an
in-substance sale of real estate. As such, MPLX only recognized a gain for the portion attributable to Antero
Midstream’s indirect interest of approximately $2 million, included in “Other income” on the Consolidated
Statements of Income. MarkWest Liberty Midstream’s portion of the gain attributable to its direct and indirect
interests of approximately $14 million is included in its investment in Sherwood Midstream Holdings and is
reported under the caption “Equity method investments” on the Consolidated Balance Sheets. In connection with
the initial contributions, MarkWest Liberty Midstream received a special distribution of approximately
$45 million. During the year ended December 31, 2018, MarkWest Liberty Midstream sold to Sherwood
Midstream six percent of its equity ownership in Sherwood Midstream Holdings for $15 million.
MarkWest Liberty Midstream’s and Sherwood Midstream’s ownership interests in Sherwood Midstream
Holdings will fluctuate over time. As new Shared Assets are constructed, the members will make additional
140
capital contributions to Sherwood Midstream Holdings. The amount that each member must contribute will be
based on the expected utilization of the Shared Assets, as defined in the LLC Agreement. Pursuant to the terms of
the LLC Agreement, MarkWest Liberty Midstream will serve as the operator for Sherwood Midstream Holdings.
MPLX accounts for Sherwood Midstream Holdings, which is a VIE, as an equity method investment as
Sherwood Midstream is considered to be the general partner and controls all decisions. MPLX’s maximum
exposure to loss as a result of its involvement with Sherwood Midstream Holdings includes its equity investment,
any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator
in excess of its compensation received for the performance of operating services. MPLX did not provide any
financial support to Sherwood Midstream Holdings that it was not contractually obligated to provide during the
years ended December 31, 2018 and 2017.
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 portion of Sherwood Midstream
Holdings’ net assets as a component of its investment in Sherwood Midstream. As of December 31, 2018, MPLX
has a 20.2 percent indirect ownership interest in Sherwood Midstream Holdings through Sherwood Midstream.
6. Related Party Agreements and Transactions
MPLX’s material related parties include:
• MPC, which refines, markets and transports crude oil and petroleum products, primarily in the Midwest,
Gulf Coast, East Coast and Southeast regions of the United States.
• MarkWest Utica EMG, in which MPLX LP has a 56 percent interest as of December 31, 2018. MarkWest
Utica EMG is engaged in natural gas processing and NGL fractionation, transportation and marketing in
Ohio.
• Ohio Gathering, in which MPLX LP has a 34 percent indirect interest as of December 31, 2018. Ohio
Gathering is a subsidiary of MarkWest Utica EMG providing natural gas gathering service in the Utica
Shale region of eastern Ohio.
•
•
Sherwood Midstream, in which MPLX LP has a 50 percent interest as of December 31, 2018. Sherwood
Midstream supports the development of Antero Resources’ Marcellus Shale acreage in the rich-gas corridor
of West Virginia.
Sherwood Midstream Holdings, in which MPLX LP has an 80 percent total direct and indirect interest as of
December 31, 2018. Sherwood Midstream Holdings owns certain infrastructure at the Sherwood Complex
that is shared by and supports the operation of both the Sherwood Midstream and MPLX gas processing
plants and de-ethanization facilities.
• MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”), in which MPLX LP
has a 67 percent interest as of December 31, 2018. Jefferson Dry Gas provides natural dry gas gathering and
related services in the Utica Shale region of Ohio.
Commercial Agreements
MPLX has various long-term, fee-based commercial agreements with MPC. Under these agreements, MPLX
provides transportation, terminal, fuels distribution, marketing and storage services to MPC. MPC has committed
to provide MPLX with minimum quarterly throughput volumes on crude oil and refined products systems in
addition to fees for storage capacity. 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.
141
The commercial agreements with MPC include:
• Fuels distribution services agreement—Fuels Distribution is a party to a services agreement with MPC in
connection with the dropdown of the fuels distribution services. Under this agreement, Fuels Distribution
provides services related to the scheduling and marketing of certain petroleum products to MPC. Fuels
Distribution does not provide the same services to third parties without the prior written consent of MPC.
This agreement has an initial term of 10 years, subject to a five-year renewal period under terms to be
renegotiated at that time.
Under the Fuels Distribution Services Agreement, 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 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.
Transportation services agreements—MPLX has various separate transportation services agreements with
terms ranging from five to 15 years, under which MPC pays MPLX fees for transporting crude oil and
refined products on various of MPLX’s crude oil and refined product pipelines. MPLX also has a five-year
agreement under which MPC pays MPLX fees for handling crude oil and products at MPLX’s Wood River,
Illinois barge dock, and a six-year transportation services agreement under which MPC pays MPLX fees for
providing marine transportation of crude oil, feedstocks and refined petroleum products, and related
services.
All of the transportation services agreements include automatic renewal terms ranging from two to five
years, unless terminated by either party. Under the terms of these agreements, with the exception of the
marine agreement, if MPC fails to transport its minimum throughput volumes during any quarter, then MPC
will pay MPLX a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then
in effect (the “Quarterly Deficiency Payment”). The amount of any Quarterly 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 any of the succeeding four quarters, or eight quarters in the case of
the transportation services agreements covering the Wood River to Patoka crude pipeline and the Wood
River barge dock, after which time any unused credits will expire. Upon the expiration or termination of a
transportation services agreement, MPC will have the opportunity to apply any such remaining credit
amounts until the completion of any such four-quarter or eight-quarter period, as applicable. Any such
remaining credits may be used against any volumes shipped by MPC on the applicable pipeline, without
regard to any minimum volume commitment that may have been in place during the term of the agreement.
Storage services agreements—MPLX has three storage services agreements, with 10-year, 10-year, and
17-year terms, under which MPC pays MPLX fees for providing storage services at MPLX’s Neal, West
Virginia butane cavern; Robinson, Illinois butane cavern; and Woodhaven, Michigan butane and propane
caverns, respectively. MPLX has various separate three-year storage services agreements under which MPC
pays MPLX fees for providing storage services at MPLX’s tank farms, and various separate three-year
storage services agreements under which MPC pays MPLX fees for providing storage services at MPLX’s
storage tanks associated with MPLX’s crude oil and refined product pipelines. MPLX also has various
separate storage services agreements with each of MPC’s refineries under which MPLX provides certain
services exclusively 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.
These agreements have initial terms of 10 years.
•
•
142
MPLX’s cavern storage services agreements with MPC contain various automatic renewal terms ranging
from zero to 10 years. MPLX’s tank farm storage services agreements with MPC automatically renew for
additional one-year terms unless terminated by either party. Under the terms of these agreements, MPLX is
obligated to make available to MPC, on a firm basis, the available storage capacity at MPLX LP’s tank
farms and caverns. MPC pays MPLX a per-barrel fee for such storage capacity, regardless of whether MPC
fully utilizes the available capacity. MPLX’s refinery storage services agreements with MPC are subject to
five-year renewal periods under terms to be renegotiated at that time. MPC pays MPLX monthly fees for
refinery storage and logistical services calculated as set forth in the agreements. The refinery storage and
logistical facilities subject to the agreements are to be allocated exclusively to MPC for the term of the
agreements.
•
Terminal services agreement—MPLX has a 10-year terminal services agreement under which MPC pays
MPLX fees for terminal storage for refined petroleum products.
The terminal services agreement with MPC includes automatic renewal terms ranging from two to five
years, unless terminated by either party. Under the terms of the agreement, MPC pays MPLX monthly based
on contractual fees relating to MPC product deliveries as well as any viscosity surcharges, loading,
handling, transfers or other related charges. If MPC fails to meet its quarterly minimum volume throughput
commitments, MPC will pay a deficiency payment equal to the volume of the deficiency multiplied by the
rate then in effect. If the average daily capacity of a terminal falls below the level of MPC’s commitment
during a quarter, depending on the cause of the reduction in capacity, MPC’s throughput commitment will
be reduced to equal the average daily capacity available during such quarter.
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 each of MPC’s refineries in connection with the
dropdown of the refining logistics assets. Under these agreements, 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 each of MPC’s refineries in connection with the dropdown of the
Refining Logistics assets. Under these agreements, 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 five years each
unless terminated by either party.
143
Omnibus Agreement
MPLX has an omnibus agreement with MPC that addresses its payment of a fixed annual fee 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. It also provides for
MPC’s indemnification of MPLX for certain matters, including environmental, title and tax matters; as well as
our indemnification of MPC for certain matters under this agreement.
Employee Services Agreements
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.
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 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 December 4, 2020. MPC Investment may demand payment of all or any portion of the
outstanding principal amount of the loan, together with all accrued and unpaid interest and other amounts (if
any), at any time prior to December 4, 2020. Borrowings under the loan will bear interest at LIBOR plus
1.50 percent.
During 2018, MPLX borrowed $4.0 billion and repaid $4.3 billion, resulting in no outstanding balance at
December 31, 2018. During 2017, MPLX borrowed $2.4 billion and repaid $2.0 billion, resulting in $386 million
outstanding balance at December 31, 2017, which is included in “Payables—related parties” on the Consolidated
Balance Sheets. Borrowings were at an average interest rate of 3.473 percent and 2.777 percent for 2018 and
2017, respectively.
Related Party Transactions
Related party sales to MPC consisted of crude oil and refined products pipeline transportation services based on
tariff 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.
Revenue received from related parties related to service, rental, and product sales were as follows:
(In millions)
Service revenue
MPC
Rental income
MPC
Product sales (1)
MPC
2018
2017
2016
$
$
2,159 $
1,082 $
718
279
49 $
8 $
936
235
11
(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
2018, 2017, and 2016, these sales totaled $440 million, $254 million and $46 million, respectively.
144
MPLX has operating agreements with MPC under which it receives a fee for operating MPC’s retained pipeline
assets, a fixed annual fee for providing oversight and management services required to run the marine business
and is also reimbursed for personnel services. MPLX also receives management fee revenue for engineering,
construction and administrative services for operating certain of its equity method investments. The revenue
received from these related parties, included in “Other income—related parties” on the Consolidated Statements
of Income, was as follows:
(In millions)
MPC
MarkWest Utica EMG
Ohio Gathering
Jefferson Dry Gas
Sherwood Midstream
Other
Total
2018
2017
2016
$
$
41 $
17
16
6
12
7
99 $
40 $
17
16
6
8
5
92 $
45
16
15
3
—
7
86
MPC provides executive management services and certain general and administrative services to MPLX under
the terms of an omnibus agreement. Expenses incurred under this agreement are shown in the table below by the
income statement line where they were recorded. Charges for services included in “Purchases—related parties”
primarily relate to services that support MPLX’s operations and maintenance activities, as well as compensation
expenses. Charges for services included in “General and administrative expenses” primarily relate to services
that support MPLX’s executive management, accounting and human resources activities. These charges were as
follows:
(In millions)
Rental cost of sales—related parties
Purchases—related parties
General and administrative expenses
Total
2018
2017
2016
$
$
2 $
164
68
1 $
67
37
234 $
105 $
1
39
45
85
MPLX obtains employee services from MPC under employee services agreements. Expenses incurred under
these agreements are shown in the table below by the income statement line where they were recorded. The costs
of personnel directly involved in or supporting operations and maintenance activities related to rental services are
classified as “Rental cost of sales—related parties.” The costs of personnel directly involved in or supporting
operations and maintenance activities related to other services are classified as “Purchases—related parties.” The
costs of personnel involved in executive management, accounting and human resources activities are classified as
“General and administrative expenses” on the Consolidated Statements of Income. These charges were as
follows:
(In millions)
Rental cost of sales—related parties
Purchases—related parties
General and administrative expenses
Total
2018
2017
2016
$
$
3 $
1 $
528
109
385
101
640 $
487 $
—
349
100
449
Also under terms of the omnibus and employee services agreements, some service costs related to engineering
services are associated with assets under construction. These costs added to “Property, plant and equipment, net”
were as follows:
(In millions)
MPC
2018
2017
2016
$
151 $
42 $
47
145
Purchases of products from MPC are classified as “Purchases—related parties.” These purchases include product
purchases, payments made to MPC in its capacity as general contractor to MPLX, and certain rent and lease
agreements. These purchases were as follows:
(In millions)
MPC
2018
2017
2016
$
168 $
3 $
—
Receivables from related parties were as follows:
(In millions)
MPC
Other
Total
December 31,
2018
2017
$
$
281 $
8
289 $
153
7
160
Long-term receivables with related parties, which includes straight-line rental income, were as follows:
(In millions)
MPC
Payables to related parties were as follows:
(In millions)
MPC(1)
MarkWest Utica EMG
Ohio Gathering
Sherwood Midstream
Other
Total
December 31,
2018
2017
24 $
20
December 31,
2018
2017
131 $
51
5
16
—
203 $
470
29
8
8
1
516
$
$
$
(1) Balance includes $386 million related to the MPC Loan Agreement as of December 31, 2017. There was no
outstanding balance on the MPC Loan Agreement as of December 31, 2018.
“Other current assets” included $1 million and $8 million of related party prepaid insurance as of December 31,
2018 and December 31, 2017, respectively.
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, 2018 and
2017 were $5 million and $11 million, respectively. Purchases from related parties during the years ended
December 31, 2018 and 2017 were approximately $8 million and $44 million, respectively.
During 2018 and 2017, MPC did not ship its minimum committed volumes on certain pipelines. Under MPLX’s
pipeline transportation services agreements, if MPC fails to transport its minimum throughput volumes during
any quarter, then MPC will pay MPLX a deficiency payment equal to the volume of the deficiency multiplied by
the tariff rate then in effect. The deficiency amounts are recorded as “Deferred revenue-related parties.” 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 the following four or eight quarters under the
terms of the applicable transportation services agreement. MPLX recognizes related party revenues for the
146
deficiency payments when credits are used for volumes transported in excess of minimum quarterly volume
commitments, when it becomes impossible to physically transport volumes necessary to utilize the credits or
upon the expiration of the credits. The use or expiration of the credits is a decrease in “Deferred revenue-related
parties.” In addition, capital projects MPLX is undertaking at the request of MPC are reimbursed in cash and
recognized in income over the remaining term of the applicable agreements. The “Deferred revenue-related
parties” balance associated with the minimum volume deficiencies and project reimbursements were as follows:
(In millions)
Minimum volume deficiencies—MPC
Project reimbursements—MPC
Total
December 31,
2018
2017
$
$
44 $
50
94 $
53
33
86
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. The classes of participating securities include common units, certain equity-based
compensation awards, Series A Convertible preferred units; and prior to 2018, general partner units and IDRs.
The HSM, HST, WHC and MPLXT acquisitions 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 2018, MPLX had dilutive potential common units consisting of certain equity-based compensation awards. In
2017 and 2016, 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, 2018, 2017 and 2016 were less than 1 million.
(In millions)
Net income attributable to MPLX LP
Less: Limited partners’ distributions declared on preferred units(1)
General partner’s distributions declared (includes IDRs)(1)(2)
Limited partners’ distributions declared on common units
(including common units of general partner)(1)
Undistributed net loss attributable to MPLX LP
2018
2017
2016
1,818 $
75
—
794 $
65
328
1,985
895
(242) $
(494) $
233
41
205
692
(705)
$
$
(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.
147
(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
Redeemable
Preferred
Units
Total
$
$
$
$
1,985
(242)
1,743
$
$
75 $
—
75 $
761
761
2.29
2.29
2,060
(242)
1,818
761
761
(In millions, except per unit data)
Basic and diluted net income attributable to MPLX
LP per unit:
Net income attributable to MPLX LP:
General
Partner
Limited Partners’
Common Units
Redeemable
Preferred Units
Total
2017
Distributions declared (including IDRs)
Undistributed net loss attributable to MPLX LP
Net income attributable to MPLX LP(1)
$
$
328
(10)
318
$
$
895
(484)
411
$
$
65 $
—
65 $
1,288
(494)
794
Weighted average units outstanding:
Basic
Diluted
Net income attributable to MPLX LP per limited
partner unit:
Basic
Diluted
8
8
$
$
385
388
1.07
1.06
393
396
148
(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
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
General
Partner
Limited Partners’
Common Units
Redeemable
Preferred Units
Total
2016
$
$
205
(14)
191
$
$
692
(691)
1
$
$
41
—
41
$
$
7
7
$
$
331
338
—
—
938
(705)
233
338
345
(1) Allocation of net income/(loss) attributable to MPLX LP assumes all earnings for the period were
distributed based on the current period distribution priorities.
8. Equity
Units Outstanding—MPLX had 794,089,518 common units outstanding as of December 31, 2018. Of that
number, 504,701,934 were owned by MPC, which also owns the non-economic GP interest as described below.
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.
Reorganization Transactions—On September 1, 2016, MPLX and various affiliates initiated a series of
reorganization transactions in order to simplify MPLX’s ownership structure and its financial and tax reporting
requirements (the “Class A Reorganization”). In connection with these transactions, all of the issued and
outstanding MPLX LP Class A units, all of which were held by MarkWest Hydrocarbon, L.L.C. (“MarkWest
Hydrocarbon”), were either distributed to, or purchased by, MPC in exchange for $84 million in cash, 21,401,137
MPLX LP common units and 436,758 MPLX LP general partner units. Following these initial transactions, the
MPLX LP Class A units were exchanged on a one-for-one basis for newly issued common units representing
limited partner interests in MPLX LP. MPC also contributed $141 million to facilitate the repayment of
intercompany debt between MarkWest Hydrocarbon and MarkWest. As a result of these transactions, the MPLX
LP Class A units were eliminated, are no longer outstanding and no longer participate in distributions of cash
from MPLX. Cash that is derived from or attributable to MarkWest Hydrocarbon’s operations is now treated in
the same manner as cash derived from or attributable to other operations of MPLX and its subsidiaries.
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
149
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 MPLX. M&R may
freely transfer such converted units, and M&R has the right to demand that MPLX LP 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 LP 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 year ended December 31, 2018, MPLX issued no common units under the
ATM Program. During the years ended December 31, 2017 and 2016, MPLX issued an aggregate of 13,846,998
and 26,347,887 common units, respectively, under our ATM Program, generating net proceeds of approximately
$473 million and $776 million, respectively. 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,
2016, 2017, and 2018:
(In units)
Common
Class B
Balance at December 31, 2015
Unit-based compensation awards
Issuance of units under the ATM Program
Contribution of HSM (See Note 4)
Class B Conversion
Class A Reorganization
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
296,687,176
120,989
26,347,887
22,534,002
4,350,057
7,153,177
357,193,288
268,167
13,846,998
7,981,756
—
—
—
(3,990,878)
—
3,990,878
—
—
General
Partner(1)
6,800,475
2,470
537,710
459,878
7,330
(436,758)
7,371,105
5,472
282,591
Total
311,469,407
123,459
26,885,597
22,993,880
366,509
6,716,419
368,555,271
273,639
14,129,589
12,960,376
—
264,497
13,224,873
18,511,134
4,350,057
407,130,020
348,387
111,611,111
275,000,000
794,089,518
—
(3,990,878)
377,778
7,330
18,888,912
366,509
—
—
8,308,773
140
415,438,793
348,527
—
2,277,778
— (10,586,691)
113,888,889
264,413,309
—
— 794,089,518
(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.
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.
150
Net Income Allocation—In preparing the Consolidated Statements of Equity, net income attributable to MPLX
LP is allocated to 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
LP, 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
2017
2016
$
794 $
65
310
419
8
310
General partner’s GP Interest in net income attributable to MPLX LP
$
318 $
233
41
191
1
—
191
191
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 25, 2019, MPLX declared a quarterly cash distribution,
based on the results of the fourth quarter of 2018, totaling $514 million, or $0.6475 per common unit; this rate
was also received by preferred unitholders. These distributions were paid on February 14, 2019 to unitholders of
record on February 5, 2019. Distributions for the fourth quarter of 2017 were $0.6075 per common unit while
distributions for the twelve months ended December 31, 2018 and 2017 were $2.5300 and $2.2975 per common
unit, respectively.
The allocation of total quarterly cash distributions to general, limited, and preferred unitholders is as follows for
the years ended December 31, 2018, 2017 and 2016. 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
Preferred unit distributions
2018
2017
2016
— $
—
—
1,985
75
25 $
303
328
895
65
Total cash distributions declared
$
2,060 $
1,288 $
18
187
205
692
41
938
(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.
9. Redeemable Preferred Units
Private Placement of Preferred Units—On May 13, 2016, MPLX LP 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
151
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.
Preferred Unit Distribution Rights—The preferred units rank senior to all common units with respect to
distributions and rights upon liquidation. The holders of the 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 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. For the income earned in the second through fourth quarters of 2018, the distribution rate declared to
common unitholders was greater than $0.528125 per unit; accordingly, the preferred unitholders received the
common unit rates in lieu of the lower $0.528125 base amount.
The changes in the redeemable preferred balance for 2018 and 2017 are summarized below:
(In millions)
Balance at beginning of period
Net income allocated
Distributions received by preferred unitholders
Balance at end of period
2018
2017
1,000 $
75
(71)
1,004 $
1,000
65
(65)
1,000
$
$
The holders may convert their preferred units into common units at any time after the third anniversary of the
issuance date or prior to liquidation, dissolution or winding up of the Partnership, in full or in part, subject to
minimum conversion amounts and conditions. After the fourth anniversary of the issuance date, MPLX may
convert the preferred units into common units at any time, in whole or in part, subject to certain minimum
conversion amounts and conditions, if the closing price of MPLX LP common units is greater than $48.75 for the
20-day trading period immediately preceding the conversion notice date. The conversion rate for the 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 preferred units are entitled to vote on an as-converted basis with the common
unitholders and will have certain other class voting rights with respect to any amendment to the Partnership
Agreement that would adversely affect any rights, preferences or privileges 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 preferred units to common units at the then applicable change of control conversion
rate.
The 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 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 preferred units. As the 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 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 and refined petroleum products.
152
• G&P—gathers, processes and transports natural gas; gathers, transports, fractionates, stores and markets
NGLs.
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 total assets for
our reportable segments:
(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)
Maintenance capital expenditures
Growth capital expenditures
G&P
Service revenue
Rental income
Product related revenue
Income/(loss) from equity method investments(3)
Other income
Total segment revenues and other income(1)
Segment Adjusted EBITDA(2)
Maintenance capital expenditures
Growth capital expenditures
2018
2017
2016
$
$
2,289 $
725
14
166
46
3,240
2,057
104
452
1,574
342
1,135
74
60
3,185
1,200 $
279
—
36
47
1,562
775
79
433
1,038
277
897
42
51
2,305
1,418
42
1,432 $
1,229
24
948 $
1,006
235
—
—
53
1,294
395
58
493
888
298
583
(74)
40
1,735
1,024
26
720
(1) Within the total segment revenues and other income amounts presented above, third party revenues for the
L&S segment were $313 million, $160 million and $77 million for 2018, 2017 and 2016, respectively. Third
party revenues for the G&P segment were $3,087 million, $2,246 million and $1,684 million for 2018, 2017
and 2016, respectively.
See below for the reconciliation from Segment Adjusted EBITDA to “Net income.”
Includes an impairment expense of $89 million related to one of MPLX’s equity method investments for the
year ended December 31, 2016.
(2)
(3)
153
(In millions)
Segment Assets
Cash and cash equivalents
L&S(1)
G&P(1)
Total assets
December 31,
2018
2017
$
$
68 $
6,566
16,145
22,779 $
5
4,611
14,884
19,500
(1)
Equity method investments included in L&S assets were $1.12 billion at December 31, 2018 and
$1.15 billion at December 31, 2017. Equity method investments included in G&P assets were $3.05 billion
at December 31, 2018 and $2.86 billion at December 31, 2017.
The table below provides a reconciliation between “Net income” and Segment Adjusted EBITDA.
2018
2017
2016
(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/(loss) from equity method investments(2)
Distributions/adjustments related to equity method
investments
Unrealized derivative gains/(losses)(3)
Acquisition costs
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to Predecessor(4)
$
2,057
1,418
3,475
(766)
(8)
(59)
(46)
(19)
—
(556)
240
(447)
5
(3)
18
—
$
775
1,229
2,004
(683)
(1)
(53)
—
(15)
—
(301)
78
(231)
(6)
(11)
8
47
395
1,024
1,419
(591)
12
(46)
—
(10)
(130)
(215)
(74)
(150)
(36)
1
3
251
434
Net income
$
1,834
$
836
$
(1) Depreciation and amortization attributable to L&S was $240 million, $163 million and $128 million for the
years ended 2018, 2017 and 2016, respectively. Depreciation and amortization attributable to G&P was
$526 million, $520 million and $463 million for 2018, 2017 and 2016, respectively.
Includes an impairment expense of $89 million related to one of MPLX’s equity method investments for the
year ended December 31, 2016.
(2)
(3) 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.
The Adjusted EBITDA adjustments related to Predecessor are excluded from Adjusted EBITDA attributable
to MPLX LP prior to the acquisition date.
(4)
154
11. Major Customers and Concentration of Credit Risk
MPC accounted for 48 percent, 37 percent and 39 percent of MPLX’s operating revenues for 2018, 2017 and
2016, respectively. Operating revenues consist of service revenue, rental income and product sales. MPC
accounted for 46 percent, 36 percent and 41 percent of total revenues and other income for 2018, 2017 and 2016,
respectively. The revenues are accounted for primarily within the L&S segment. 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.
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. Income Tax
MPLX is not a taxable entity for United States federal income tax purposes or for the majority of states that
impose an income tax. Taxes on MPLX’s net income generally are borne by its partners through the allocation of
taxable income. On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. While the new law
included several key changes to tax law for United States tax payers, as MPLX is not a taxable entity, the new
legislation has no impact on MPLX for federal tax purposes.
MPLX’s income tax provision/(benefit) primarily results from state and local activity in the states of Texas,
Ohio, Kentucky and Tennessee.
As a result of the Class A Reorganization discussed in Note 8, MarkWest Hydrocarbon and MarkWest
Hydrocarbon, Inc. (prior to the Class A Reorganization) is no longer a tax paying entity for federal income tax
purposes or for the majority of states that impose an income tax effective September 1, 2016. Prior to the Class A
Reorganization, in addition to paying tax on its own earnings, MarkWest Hydrocarbon recognized a tax expense
or a tax benefit on its proportionate share of Partnership income or loss resulting from MarkWest Hydrocarbon’s
ownership of Class A units of MPLX, even though for financial reporting purposes such income or loss was
eliminated in consolidation. The deferred income tax component prior to the reorganization related to the change
in the temporary book to tax basis difference in the carrying amount of the investment in MPLX, which resulted
primarily from timing differences in MarkWest Hydrocarbon’s proportionate share of the book income or loss as
compared with the MarkWest Hydrocarbon’s proportionate share of the taxable income or loss of MPLX. MPLX
recorded a residual tax provision during the year ended December 31, 2017 related to MarkWest Hydrocarbon’s
2016 income taxes. In connection with the Class A Reorganization, MPC assumed $377 million of MPLX LP’s
deferred tax liabilities.
MPLX and MarkWest Hydrocarbon recorded income tax expense of $8 million, $1 million and a benefit of
$12 million for the years ended December 31, 2018, 2017 and 2016, respectively. The effective tax rate was less
than one percent for 2018 and 2017 and five percent for 2016.
155
The components of the “Provision/(benefit) for income taxes” are as follows:
(In millions)
Current income tax expense:
Federal
State
Total current
Deferred income tax expense/(benefit):
Federal
State
Total deferred
December 31,
2018
2017
2016
$
— $
—
—
—
8
8
— $
2
2
—
(1)
(1)
Provision/(benefit) for income taxes
$
8 $
1 $
4
1
5
(16)
(1)
(17)
(12)
A reconciliation of the “Provision/(benefit) for income taxes” and the amount computed by applying the federal
statutory rate of 35 percent to the income before income taxes for the year ended December 31, 2016 is as
follows:
(In millions)
(Loss)/income before (benefit)/provision
for income tax
Federal statutory rate
Federal income tax at statutory rate
State income taxes net of federal benefit
Provision on income from MPLX LP
Class A units
Change in state statutory rate
Other
MarkWest
Hydrocarbon(1)
Partnership
Eliminations
Consolidated
December 31, 2016
$
$
(41)
35%
461
$
—%
$
2
—%
(14)
(2)
3
(1)
1
—
1
—
—
—
1
—
—
—
—
—
$
— $
422
(14)
(1)
3
(1)
1
(12)
(Benefit)/provision for income taxes
$
(13)
$
(1) MarkWest Hydrocarbon paid tax on its share of MPLX’s income or loss as a result of its ownership of
MPLX LP Class A units through September 1, 2016.
In taxable jurisdictions, MPLX recorded deferred income taxes on all temporary differences between the book
and tax basis of assets and liabilities. MPLX has a net deferred tax liability of $13 million and $5 million for the
years ended December 31, 2018 and 2017, respectively. The net deferred tax liability is principally derived from
the difference in the book and tax basis of property, plant and equipment.
Significant judgment is required in evaluating tax positions and determining MPLX and MarkWest Hydrocarbon’s
provision for income taxes. During the ordinary course of business, there may be transactions and calculations for
which the ultimate tax determination is uncertain. However, MPLX and MarkWest Hydrocarbon did not have any
material uncertain tax positions for the years ended December 31, 2018, 2017 or 2016.
Any interest and penalties related to income taxes were recorded as a part of the provision for income taxes. Such
interest and penalties were a net expense of less than $1 million in 2018, and a net benefit of less than $1 million
in 2017 and 2016. As of December 31, 2018, 2017 and 2016, no interest and penalties were accrued related to
income taxes. In addition, MPLX and MarkWest Hydrocarbon’s former corporate entity have federal tax years
2015 through 2016 and state tax years 2013 through 2017 open to examination.
156
13. Inventories
Inventories consist of the following:
(In millions)
NGLs
Line fill
Spare parts, materials and supplies
Total inventories
14. Property, Plant and Equipment
December 31,
2018
2017
$
$
9 $
9
59
77 $
4
8
53
65
Property, plant and equipment with associated accumulated depreciation is shown below:
(In millions)
Natural gas gathering and NGL transportation pipelines and
Estimated
Useful Lives
December 31,
2018
2017
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
$
5 - 30 years
10 - 40 years
15 - 51 years
20 years
4 - 30 years
5 - 30 years
3 - 35 years
5,926 $
5,336
2,560
620
1,178
938
957
801
18,316
3,677
Property, plant and equipment, net
$
14,639 $
5,178
3,893
2,253
490
821
—
770
1,057
14,462
2,275
12,187
Property, plant and equipment includes gross assets acquired under capital leases of approximately $25 million at
December 31, 2018 and 2017, with related amounts in accumulated depreciation of approximately $9 million at
December 31, 2018 and 2017.
15. 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. MPLX has 12 reporting units, eight of which had goodwill totaling approximately
$2.6 billion as of November 30, 2018. MPLX performed its annual impairment tests, and no impairments in the
carrying value of goodwill were identified. 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
commodity prices and producer customers’ development plans (which impact volumes and capital requirements).
During the first quarter of 2016, MPLX determined that an interim impairment analysis of the goodwill recorded
in connection with the MarkWest Merger was necessary based on consideration of a number of first quarter
events and circumstances, including (i) continued deterioration of near term commodity prices as well as longer
term pricing trends, (ii) recent guidance on reductions to forecasted capital spending, the slowing of drilling
activity and the resulting reduced production growth forecasts released or communicated by MPLX’s producer
157
customers and (iii) increases in cost of capital. The combination of these factors was considered to be a triggering
event requiring an interim impairment test. Based on the first step of the interim goodwill impairment analysis,
the fair value for the three reporting units to which goodwill was assigned in connection with the MarkWest
Merger was less than the respective carrying value. In step two of the impairment analysis, the implied fair
values of the goodwill were compared to the carrying values within those reporting units. Based on this
assessment, it was determined that goodwill was impaired in two of the three reporting units. Accordingly,
MPLX recorded an impairment charge of approximately $129 million in the first quarter of 2016. In the second
quarter of 2016, MPLX completed its purchase price allocation, which resulted in an additional $1 million of
impairment expense that would have been recorded in the first quarter of 2016 had the purchase price allocation
been completed as of that date. This adjustment to the impairment expense was the result of completing an
evaluation of the deferred tax liabilities associated with the MarkWest Merger and their impact on the resulting
goodwill that was recognized.
The fair value of the reporting units for the interim goodwill impairment analysis described above was
determined based on applying the discounted cash flow method, which is an income approach, and the guideline
public company method, which is a market 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 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 10.5 percent to 11.5 percent. The
fair value of the intangibles was determined based on applying the multi-period excess earnings method, which is
an income approach. Key assumptions included attrition rates by reporting unit ranging from 5.0 percent to
10.0 percent and discount rates by reporting unit ranging from 11.5 percent to 12.8 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)
L&S
G&P
Total
Gross goodwill as of December 31, 2016
Accumulated impairment losses
Balance as of December 31, 2016
Impairment losses
Acquisitions
Balance as of December 31, 2017
Impairment losses
Acquisitions
Balance as of December 31, 2018
Gross goodwill as of December 31, 2018
Accumulated impairment losses
Balance as of December 31, 2018
$
162 $
—
$
2,213
(130)
162
—
—
162
—
341
503
503
—
2,083
—
—
2,083
—
—
2,083
2,213
(130)
$
503 $
2,083
$
2,375
(130)
2,245
—
—
2,245
—
341
2,586
2,716
(130)
2,586
158
Intangible Assets
MPLX’s intangible assets are comprised of customer contracts and relationships, gross intangible assets with
accumulated amortization as of December 31, 2018 and 2017 is shown below:
(In millions)
Useful Life
Gross
December 31, 2018
Accumulated
Amortization(1)
Net
Gross
December 31, 2017
Accumulated
Amortization(1)
Net
L&S
G&P
4-6 years
11-25 years
$
$
9 $
533
— $
(118)
542 $
(118) $
9 $
415
424 $
— $
533
533 $
— $
(80)
(80) $
—
453
453
(1) Amortization expense attributable to the G&P segment for the years ended December 31, 2018 and 2017
was $38 million in both years.
Estimated future amortization expense related to the intangible assets at December 31, 2018 is as follows:
(In millions)
2019
2020
2021
2022
2023
Thereafter
Total
16. Fair Value Measurements
Fair Values—Recurring
$
$
40
40
40
39
39
226
424
Fair value measurements and disclosures relate primarily to MPLX’s derivative positions as discussed in Note
17. The following table presents the financial instruments carried at fair value on a recurring basis as of
December 31, 2018 and 2017 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)
Significant unobservable inputs (Level 3)
Commodity contracts
Embedded derivatives in commodity contracts
Total carrying value in Consolidated Balance Sheets
December 31, 2018
December 31, 2017
Assets
Liabilities
Assets
Liabilities
$
$
— $
—
— $
— $
(61)
(61) $
— $
—
— $
(2)
(64)
(66)
Level 3 instruments include all NGL transactions and embedded derivatives in commodity contracts. The
embedded derivative liability relates to a natural gas purchase agreement embedded in a keep-whole processing
agreement. The fair value calculation for Level 3 instruments at December 31, 2018 used significant
unobservable inputs including: (1) NGL prices interpolated and extrapolated due to inactive markets ranging
from $0.58 to $1.01 and (2) the probability of renewal of 90 percent for the first five-year term and 80 percent for
the second five-year term of the gas purchase agreement and related keep-whole processing agreement. For
commodity contracts, increases in forward NGL prices result in a decrease in the fair value of the derivative
159
assets and an increase in the fair value of derivative liabilities. Increases or decreases in the fractionation spread
result in an increase or decrease in the fair value of the embedded derivative liability. An increase in the
probability of renewal would result in an increase in the fair value of the related embedded derivative liability.
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)
Fair value at beginning of period
Total gains/(losses) (realized and unrealized) included
$
in earnings(1)
Settlements
Fair value at end of period
2018
2017
Commodity
Derivative
Contracts (net)
Embedded
Derivatives in
Commodity
Contracts (net)
Commodity
Derivative
Contracts (net)
Embedded
Derivatives in
Commodity
Contracts (net)
(2) $
(64) $
(6) $
6
(4)
—
(9)
12
(61)
(5)
9
(2)
(54)
(19)
9
(64)
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
$
— $
(8) $
(2) $
(6)
(1) Gains and losses on commodity derivatives classified as Level 3 are recorded in “Product sales” on the
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, 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 17).
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 capital leases, and SMR liability.
(In millions)
Long-term debt
SMR liability
December 31,
2018
2017
Fair Value
Carrying Value
Fair Value
Carrying Value
$
13,169
92
$
13,484
86
$
7,718
104
$
6,966
91
160
17. Derivative Financial Instruments
As of December 31, 2018, 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, these 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 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, 2018 and
2017, the estimated fair value of this contract was a liability of $61 million and $64 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, 2018 and 2017, 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)
December 31, 2018
December 31, 2017
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
Asset
Liability
Asset
Liability
$
$
— $
—
— $
(7) $
(54)
(61) $
— $
—
— $
(14)
(52)
(66)
(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 16. See Note 2 for a discussion of derivatives MPLX uses and
the reasons for them. MPLX does not designate any of its commodity derivative positions as hedges for
accounting purposes.
161
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/(losses)
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 losses
Unrealized gains
Total derivative losses related to cost of revenues
December 31,
2018
2017
2016
$
$
4
2
6
(9) $
4
(5)
(12)
3
(9)
—
—
—
(9)
(10)
(19)
—
—
—
Total derivative losses
$
(3) $
(24) $
2
(15)
(13)
(5)
(22)
(27)
(3)
1
(2)
(42)
18. Debt
MPLX’s outstanding borrowings at December 31, 2018 and 2017 consisted of the following:
(In millions)
MPLX LP:
Bank revolving credit facility due 2022
5.500% senior notes due February 2023
3.375% senior notes due March 2023
4.500% senior notes due July 2023
4.875% senior notes due December 2024
4.000% senior notes due February 2025
4.875% senior notes due June 2025
4.125% senior notes due March 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
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
Capital lease obligations due 2020
Total
Unamortized debt issuance costs
Unamortized discount
Amounts due within one year
December 31,
2018
2017
$
— $
—
500
989
1,149
500
1,189
1,250
1,250
750
1,750
1,000
1,500
1,500
500
23
6
13,856
(97)
(366)
(1)
505
710
—
989
1,149
500
1,189
1,250
—
—
—
1,000
—
—
—
63
7
7,362
(27)
(389)
(1)
6,945
Total long-term debt due after one year
$
13,392
$
162
The following table shows five years of scheduled debt payments.
(In millions)
2019
2020
2021
2022
2023
Credit Agreements
$
$
1
5
—
—
1,500
On July 21, 2017, MPLX entered into a syndicated credit agreement to replace its previously outstanding
$2 billion five-year bank revolving credit facility and $250 million term loan with a $2.25 billion five-year bank
revolving credit facility that expires in July 2022 (the “MPLX Credit Agreement”). 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. On July 19, 2017, MPLX prepaid the previously outstanding principal of
the term loan with cash on hand. The borrowings under the term loan facility bore interest between January 1,
2017 and July 19, 2017 at an average interest rate of 2.407 percent.
The MPLX Credit Agreement includes letter of credit issuing capacity of up to $222 million and swingline
capacity of up to $100 million. The borrowing capacity under the MPLX Credit Agreement may be increased by
up to an additional $500 million, 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, 2018, MPLX was in compliance with the covenants contained in the MPLX Credit Agreement.
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 letters of credit outstanding under the
new facility, resulting in total availability of $2.2 billion, or 99.9 percent of the borrowing capacity.
During 2017, MPLX had no borrowings under the previous bank revolving credit facility. During the year ended
December 31, 2017, MPLX borrowed $670 million under the MPLX Credit Agreement, at a weighted average
interest rate of 2.748 percent, and repaid $165 million of these borrowings. At December 31, 2017, MPLX had
$505 million outstanding borrowings and $3 million letters of credit outstanding under this facility, resulting in
total unused loan availability of $1.7 billion, or 77.4 percent of the borrowing capacity.
163
Senior Notes
Interest on each series of MPLX LP and MarkWest senior notes is payable semi-annually in arrears, according to
the table below.
Senior Notes
Interest payable semi-annually in arrears
3.375% senior notes due 2023
4.500% senior notes due 2023
4.875% senior notes due 2024
4.000% senior notes due 2025
4.875% senior notes due 2025
4.125% senior notes due 2027
4.000% senior notes due 2028
4.800% senior notes due 2029
4.500% senior notes due 2038
5.200% senior notes due 2047
4.700% senior notes due 2048
5.500% senior notes due 2049
4.900% senior notes due 2058
March 15th and September 15th
January 15th and July 15th
June 1st and December 1st
February 15th and August 15th
June 1st and December 1st
March 1st and September 1st
March 15th and September 15th
February 15th and August 15th
April 15th and October 15th
March 1st and September 1st
April 15th and October 15th
February 15th and August 15th
April 15th and October 15th
On December 10, 2018, MPLX redeemed all of the $750 million 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 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 unsecured senior notes due
February 2029 and $1.5 billion aggregate principal amount of 5.5 percent unsecured 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 proceeds were used
to repay outstanding borrowings under the MPLX Credit Agreement and the MPC Loan Agreement and to
redeem the $750 million 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 unsecured senior notes due March 2023,
$1.25 billion aggregate principal amount of 4.0 percent unsecured senior notes due March 2028, $1.75 billion
aggregate principal amount of 4.5 percent unsecured senior notes due April 2038, $1.5 billion aggregate principal
amount of 4.7 percent unsecured senior notes due April 2048, and $500 million aggregate principal amount of
4.9 percent unsecured 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 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.
On February 10, 2017, MPLX completed a public offering of $1.25 billion aggregate principal amount of 4.125
percent unsecured senior notes due March 2027 (the “2027 Senior Notes”) and $1.0 billion aggregate principal
164
amount of 5.200 percent unsecured senior notes due March 2047 (the “2047 Senior Notes”). The 2027 Senior
Notes and the 2047 Senior Notes were offered at a price to the public of 99.834 percent and 99.304 percent of
par, respectively. The net proceeds were used to fund the $1.5 billion cash portion of the consideration paid to
MPC for the dropdown of assets on March 1, 2017, as well as for general business purposes.
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, 2018 and 2017, the following amounts related to the SMR
are included in the accompanying Consolidated Balance Sheets:
(In millions)
Assets
Property, plant and equipment, net
Liabilities
Accrued liabilities
Deferred credits and other liabilities
19. Revenue
Effect of ASC 606 Adoption
December 31,
2018
December 31,
2017
$
$
51
$
5
81
$
56
5
86
MPLX adopted ASC 606 on January 1, 2018 for all contracts that were not yet completed as of the date of
adoption. The details of significant changes and quantitative impact of the new revenue standard are disclosed
below.
•
Third-party reimbursements—Third-party reimbursements, such as electricity costs, are presented gross on
the income statement rather than net within cost of revenues. The gross-up for third-party reimbursements
(e.g., increase in “Service revenue”; increase in “Cost of revenues”) was $369 million for the year ended
December 31, 2018.
MPLX updated the allocation between lease and non-lease components for implicit leases as a result of this
ASC 606 gross up. As a result, “Rental income” and “Rental cost of sales” increased by $65 million for the
year ended December 31, 2018.
• Noncash consideration—Under certain processing agreements, MPLX is entitled to retain NGLs or other
liquids from the customer. We obtain control of these NGLs and are able to direct the use of the goods.
Service revenues are recorded based on the value of the NGLs received on the date the services are
performed. Historically, revenue was not recorded on these arrangements until the product was sold. The
impact to this change was an increase of $52 million to “Service revenue—product related” for the year
ended December 31, 2018. NGL inventory related to keep-whole volumes was also revalued as a result of
this change, with a cumulative effect adjustment of $1 million and an increase to inventory of $2 million as
of December 31, 2018. The increase in the inventory basis increased “Purchased product costs” by
$50 million for the year ended December 31, 2018.
165
• Percent-of-proceeds revenues—MPLX’s percentage of proceeds revenue received was historically recorded
in product revenues. Upon adoption of ASC 606, these revenues have been classified in service revenue, as
the performance obligation related to these contracts is to provide gathering and processing services.
Revenues will continue to be recorded net under these arrangements as MPLX does not control the product
prior to sale. For the year ended December 31, 2018, $146 million was recorded in “Service revenue—
product related” as opposed to “Product sales.”
•
Imbalances—Historically, all imbalances were recorded net. In certain instances, MPLX’s arrangements are
structured such that imbalances are cashed-out each period end which results in the transfer of control of a
commodity and creates a purchase and/or sale of a commodity under ASC 606. Thus, certain imbalances
will be grossed up as a result of adoption. The impact of this change was an increase of $55 million to
“Product sales” and “Purchased product costs” for the year ended December 31, 2018.
• Aid in construction—Historically, all aid in construction amounts received were deferred and recognized
into revenue. Payments received from non-customers will no longer be deferred as the accounting will not
be subject to ASC 606. Such payments will be recorded as a reduction to “Property, plant and equipment,
net.” The cumulative adjustment wrote down $3 million of “Property, plant and equipment, net.”
• Oil Allowances—Historically, oil allowances were recorded when received as consideration for services
performed. Under ASC 606, MPLX does not believe such amounts represent consideration from a customer.
Any excess product obtained and sold as a result of these allowances is recorded as product sales. This
change decreased “Service revenues” and “Service revenues—related party” by $7 million, and increased
“Product sales” and “Product sales related party” by $7 million for the year ended December 31, 2018.
The cumulative effect of the changes made to our consolidated January 1, 2018 balance sheet for the adoption of
ASC 606 was as follows:
(In millions)
Assets
Inventories
Property, plant and equipment, net
Liabilities
Long-term deferred revenue
Equity
Common unitholders—public
Balance at
December 31, 2017
ASC 606
Adjustment
Balance at
January 1, 2018
$
$
65
12,187
$
42
$
1
(3)
(3)
66
12,184
39
8,379
$
1
$
8,380
166
Aside from the adjustments to the opening balances noted above, the impact of adoption on the Consolidated
Balance Sheets for the year ended December 31, 2018 was approximately a $2 million adjustment to
“Inventories.” The disclosure of the impact of adoption on the Consolidated Statements of Income for the year
ended December 31, 2018 was as follows:
(In millions)
Revenues and other income:
Service revenue
Service revenue—related parties
Service revenue—product related
Rental income
Product sales(1)
Product sales—related parties
Costs and expenses:
Cost of revenues(2)
Purchased product costs
Rental cost of sales
Depreciation and amortization
Net income
December 31, 2018
ASC 606 Balance ASC 605 Balance
Effect of Change
Higher/ (Lower)
$
$
1,704
2,159
198
349
897
49
948
845
135
766
$
1,342
2,166
—
284
982
42
579
740
70
767
$
1,834
$
1,832
$
362
(7)
198
65
(85)
7
369
105
65
(1)
2
(1) G&P “Product sales” for the year ended December 31, 2018 excludes approximately $5 million of impact
(2)
related to derivative gains and mark-to-market adjustments.
Excludes “Purchased product costs,” “Rental cost of sales,” “Purchases,” “Depreciation and amortization,”
“General and administrative expenses,” and “Other taxes.”
Disaggregation of Revenue
The following table represents a disaggregation of revenue for each reportable segment for the year ended
December 31, 2018:
(In millions)
Revenues and other income:
Service revenue
Service revenue—related parties
Service revenue—product related
Product sales(1)
Product sales—related parties
December 31, 2018
L&S
G&P
Total
$
$
130
2,159
—
7
7
1,574
—
198
890
42
2,704
$
$
1,704
2,159
198
897
49
5,007
1,418
6,425
Total revenues from contracts with customers
$
2,303
$
Non-ASC 606 revenue(2)
Total revenues and other income
(1) G&P “Product sales” for the year ended December 31, 2018 excludes approximately $5 million of impact
related to derivative gains and mark-to-market adjustments.
(2) Non-ASC 606 Revenue includes rental income, income from equity method investments, derivative gains
and losses, mark-to-market adjustments, and other income.
167
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
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 year ended December 31, 2018:
(In millions)
Balance at
January 1, 2018(1)
Additions/
(Deletions)
Revenue
Recognized(2)
Balance at
December 31, 2018
Contract assets
Deferred revenue
Deferred revenue—related parties
Long-term deferred revenue
Long-term deferred revenue—related parties
$
$
4 $
5
42
5
43 $
— $
8
40
5
(1) $
— $
(9)
(32)
—
— $
4
4
50
10
42
(1) Balance represents ASC 606 portion of each respective line item.
(2)
$1 million revenue was recognized related to past performance obligations in the current year.
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, 2018, the amounts allocated to contract assets and contract liabilities on the Consolidated
Balance Sheets are $105 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 25 years. Further, MPLX does not disclose
variable consideration due to volume variability in the table below.
(In millions)
2019
2020
2021
2022
2023 and thereafter
Total revenue on remaining performance obligations(1)(2)(3)
168
$
$
1,146
1,152
1,166
1,151
5,524
10,139
(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.
Practical Expedients
We do not disclose information on the future performance obligations for any contract with an original expected
duration of one year or less.
20. Supplemental Cash Flow Information
(In millions)
Cash and cash equivalents
Restricted cash(1)
Cash, cash equivalents and restricted cash(2)
December 31,
2018
December 31,
2017
$
$
68 $
8
76 $
5
4
9
(1)
The restricted cash balance is included within “Other current assets” on the Consolidated Balance Sheets.
(2) As a result of the adoption of ASU 2016-18, Statement of Cash Flows—Restricted Cash, the Consolidated
Statements of Cash Flows now explain the change during the period of both “Cash and cash equivalents”
and “Restricted cash.”
(In millions)
2018
2017
2016
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)
Income taxes paid
Non-cash investing and financing activities:
Net transfers of property, plant and equipment from materials and
supplies inventories
Contribution—fixed assets to joint venture(1)
Contribution—common units issued(2)
$
$
484 $
1
263 $
3
2
—
4,236 $
6
337
1,133 $
213
4
(3)
—
669
(1) Contribution of assets to Sherwood Midstream and Sherwood Midstream Holdings. See Note 5.
(2)
For 2016, includes limited partner units issued to MPC as consideration in the acquisition of HSM. 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. 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)
2018
2017
2016
Increase/(decrease) in capital accruals
$
104 $
71 $
(22)
169
21. 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, 2016 through December 31, 2018:
(In millions)
Balance at December 31, 2016
Joint-Interest Acquisition
Balance at December 31, 2017(1)
Other comprehensive loss—remeasurements(2)
Balance as of December 31, 2018(1)
Pension Benefits
Other Post-
Retirement
Benefits
$
$
— $
(13)
(13)
(1)
— $
(1)
(1)
(1)
(14) $
(2) $
Total
—
(14)
(14)
(2)
(16)
(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.
22. 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.
170
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 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 LP, MPLX LP’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, 2018 and 2017 were $4 million and $4 million, respectively.
The fair values of phantom units are based on the fair value of MPLX LP 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 LP 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 2016 have a three-year performance period of January 1,
2016 through December 31, 2018. The payout of the award is dependent on the total unitholder return of MPLX
LP common units as compared to the total unitholder return of a selected group of peer partnerships. The final
per unit payout will be based on the average of the results of four measurement periods during the period. 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 LP’s DCF during the last twelve months of the performance period, and a market condition based on
MPLX LP’s total unitholder return over the entire three-year performance period.
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.
Outstanding Phantom Unit Awards
The following is a summary of phantom unit award activity of MPLX LP common units in 2018:
Outstanding at December 31, 2017
Granted
Settled
Forfeited
Outstanding at December 31, 2018
Vested and expected to vest at December 31, 2018
Non-forfeitable at December 31, 2018(1)
171
Phantom Units
Weighted
Average
Fair Value
Aggregate
Intrinsic Value (In
millions)
34.53
33.84
34.38
34.50
34.34
34.34 $
34.59 $
35
10
Number
of Units
1,351,523 $
437,092
(509,570)
(124,710)
1,154,335
1,139,877
321,638 $
(1) Represents a subset of phantom units held by our non-employee directors and certain of our officers and
non-officer 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:
2018
2017
2016
Phantom Units
Intrinsic Value of
Units Issued
During the Period
(in millions)
Weighted Average
Grant Date Fair
Value of Units
Granted During
the Period
$
$
18 $
15
5 $
33.84
36.26
29.42
As of December 31, 2018, unrecognized compensation cost related to phantom unit awards was $17 million,
which is expected to be recognized over a weighted average period of 1.8 years.
Outstanding Performance Unit Awards
The following table presents a summary of the 2018 activity for performance unit awards to be settled in MPLX
LP common units:
Outstanding at December 31, 2017
Granted
Settled
Forfeited
Outstanding at December 31, 2018
Performance Units
Number of Units
Weighted
Average
Fair Value
2,536,594 $
—
(538,594)
(56,250)
1,941,750 $
0.85
—
1.04
0.90
0.80
The number of common units that would be issued upon target vesting, using the closing price of our common
units on December 31, 2018 would be 64,084 common units.
As of December 31, 2018, 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 1.0 year.
Performance units paying out in MPLX LP 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
2018
N/A
N/A
N/A
N/A
2017
2016
1.52%
2.83 years
49.34%
$0.90
0.96%
2.83 years
47.59%
$0.63
The assumption for expected volatility of our unit price reflects the historical volatility of MPLX LP 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.
172
Total Unit-Based Compensation Expense
Total unit-based compensation expense for awards settling in MPLX LP common units was $22 million in 2018,
$18 million in 2017 and $10 million in 2016.
MPC’s Stock-based Compensation
Stock-based compensation expenses charged to MPLX LP under our employee services agreement with MPC
were $6 million, $2 million and $5 million for 2018, 2017 and 2016, respectively.
23. Lease Operations
Based on the terms of fee-based transportation and storage services agreements with MPC as well as 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. MPLX’s primary natural gas implicit
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. The transportation and storage services agreements with MPC are described
further in Note 6. MPLX’s revenue from its implicit lease arrangements, excluding executory costs, totaled
approximately $928 million in 2018, $601 million in 2017 and $586 million in 2016.
MPLX’s implicit lease arrangements related to the processing facilities contain contingent rental provisions
whereby MPLX receives additional fees if the producer customer exceeds the monthly minimum processed
volumes. During the years ended December 31, 2018 and 2017, MPLX received contingent lease payments of
$9 million. During the year ended December 31, 2016, MPLX received $7 million of contingent lease payments.
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
$
$
748
750
627
627
616
2,321
5,689
$
$
160
159
150
148
142
1,111
1,870
$
$
908
909
777
775
758
3,432
7,559
173
The following schedule summarizes MPLX’s investment in assets held for operating lease by major classes as of
December 31, 2018 and 2017:
(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
Property, plant and equipment, net
24. Asset Retirement Obligations
December 31,
2018
2017
$
$
964
1,398
266
619
1,178
938
162
189
5,714
2,038
3,676
$
$
851
573
253
491
822
—
44
85
3,119
1,056
2,063
MPLX’s assets subject to AROs are primarily certain gas-gathering pipelines and processing facilities, a crude
oil pipeline and other related pipeline assets. MPLX also has land leases that require MPLX to return the land to
its original condition upon termination of the lease. MPLX reviews current laws and regulations governing
obligations for asset retirements and leases, as well as MPLX’s leases and other agreements.
The following is a reconciliation of the changes in the ARO from January 1, 2017 to December 31, 2018:
(In millions)
AROs at beginning of period
Liabilities incurred
Accretion expense
AROs at end of period
2018
2017
$
$
28
1
1
30
$
$
25
2
1
28
At December 31, 2018 and 2017, there were no assets legally restricted for purposes of settling AROs. The
AROs have been recorded as part of “Deferred credits and other liabilities” on the accompanying Consolidated
Balance Sheets.
In addition to recorded AROs, MPLX has other AROs related to certain gathering, processing and other assets as
a result of environmental and other legal requirements. MPLX is not required to perform such work until it
permanently ceases operations of the respective assets. Because MPLX considers the operational life of these
assets to be indeterminable, an associated ARO cannot be estimated and is not recorded.
25. Commitments and Contingencies
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.
174
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, 2018 and 2017, accrued liabilities for remediation totaled $14 million and $13 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, 2017, there was less than
$1 million in payables to MPC for indemnification of environmental costs related to incidents occurring prior to
the asset drops. At December 31, 2018, there was no balance with MPC for these costs.
MarkWest Liberty Midstream and its affiliates agreed to pay a cash penalty of approximately $0.6 million and to
undertake certain supplemental environmental projects with an estimated cost of approximately $2.4 million,
related to civil enforcement allegations associated with permitting and other regulatory obligations for launcher/
receiver and compressor station facilities in southeastern Ohio and western Pennsylvania. On April 24, 2018,
MarkWest Liberty Midstream and its affiliates entered into a Consent Decree with the EPA and the Pennsylvania
Department of Environmental Protection resolving these issues. The Consent Decree was approved by the court
on July 9, 2018 and the penalty has been paid.
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 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 a number of other environmental enforcement matters arising in the ordinary course of
business. While the outcome and impact on MPLX LP cannot be predicted with certainty, management believes
the resolution of these environmental matters will not, individually or collectively, have a material adverse effect
on its consolidated results of operations, financial position or cash flows.
Other Lawsuits—MPLX, MarkWest, MarkWest Liberty Midstream, MarkWest Liberty Bluestone, L.L.C., Ohio
Fractionation and MarkWest Utica EMG (collectively, the “MPLX Parties”) are 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 relate 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. With respect to work performed by Westcon at the
Mobley and Bluestone processing complexes, one or more of the MPLX Parties have asserted breach of contract,
fraud, and with respect to work performed at the Mobley processing complex, MarkWest Liberty Midstream has
also asserted negligent misrepresentation claims against Westcon. Westcon has also asserted claims against one
or more of the MPLX Parties regarding these construction projects for breach of contract, unjust enrichment,
promissory estoppel, fraud and constructive fraud, tortious interference with contractual relations, and civil
conspiracy. Collectively, in the several cases, the MPLX Parties seek in excess of $10 million, plus an
unspecified amount of punitive damages. Collectively, in the several cases, Westcon seeks in excess of
$40 million, plus an unspecified amount of punitive damages. It is possible that, in connection with these
lawsuits, the MPLX Parties will incur material amounts of damages. While the ultimate outcome and impact to
MPLX cannot be predicted with certainty, MPLX does not consider it reasonably possible that a loss resulting
from such lawsuits or other proceedings in excess of any amounts accrued has been incurred that is expected to
have a material adverse effect on its consolidated financial position, results of operations, or cash flows.
175
In 2003, the State of Illinois brought an action against the Premcor Refining Group, Inc. (“Premcor”) and Apex
Refining Company (“Apex”) asserting claims for environmental cleanup related to the refinery owned by these
entities in the Hartford/Wood River, Illinois area. In 2006, Premcor and Apex filed third-party complaints against
numerous owners and operators of petroleum products facilities in the Hartford/Wood River, Illinois area,
including Marathon Pipe Line LLC (“MPL”). These complaints, which have been amended since filing, assert
claims of common law nuisance and contribution under the Illinois Contribution Act and other laws for
environmental cleanup costs that may be imposed on Premcor and Apex by the State of Illinois. On September 6,
2016, the trial court approved a settlement between Apex and the State of Illinois whereby Apex agreed to settle
all claims against it for a $10 million payment. Premcor filed a motion for permissive appeal and requested a stay
to the proceeding until the motion is ruled upon. Premcor reached a settlement with the State of Illinois in the
second quarter of 2018, which has been objected to by certain third-party defendants, including MPL, and is
subject to court approval. Several third-party defendants in the litigation including MPL have asserted cross-
claims in contribution against the various third-party defendants. This litigation is currently pending in the Third
Judicial Circuit Court, Madison County, Illinois. The trial concerning Premcor’s claims against third-party
defendants, including MPL, previously scheduled to commence September 10, 2018, has been postponed and a
new trial date has not been set. While the ultimate outcome and impact to MPLX cannot be predicted with
certainty, MPLX does not consider it reasonably possible that a loss resulting from such lawsuits or other
proceedings in excess of any amounts accrued has been incurred that is expected to have a material adverse effect
on its consolidated financial position, results of operations, or cash flows. Under the omnibus agreement, MPC
will indemnify MPLX for the full cost of any losses should MPL be deemed responsible for any damages in this
lawsuit.
MPLX is also a party to a number of other lawsuits and other proceedings arising in the ordinary course of
business. While the ultimate outcome and impact to MPLX cannot be predicted with certainty, MPLX believes
the resolution of these other lawsuits and proceedings will not have a material adverse effect on its consolidated
financial position, results of operations 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.
Contractual Commitments and Contingencies—At December 31, 2018, MPLX’s contractual commitments to
acquire property, plant and equipment totaled $746 million. These commitments were primarily related to plant
expansion projects for the Marcellus and Southwest Operations. 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 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, 2018, 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.
Lease and 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 9 to 11 years. After the minimum volume commitments are met in the transportation and terminalling
176
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, 2018 are as follows:
(In millions)
2019
2020
2021
2022
2023
2024 and thereafter
Total
$
$
52
52
48
46
46
180
424
MPLX has various non-cancellable operating lease agreements, most of these leases include renewal options.
MPLX also leases certain pipelines under a capital lease that has a fixed price purchase option in 2020. 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
Operating lease rental expense was:
(In millions)
Minimum rental expense
Capital
Lease
Obligations
Operating
Lease
Obligations
$
$
73
70
67
64
58
719
$
1,051
$
2
5
—
—
—
—
7
1
6
2018
2017
2016
$
85
$
64
$
57
177
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 18 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)
2019
2020
2021
2022
2023
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
Select Quarterly Financial Data (Unaudited)
$
$
17
17
17
17
17
110
195
75
34
86
5
81
2018
2017
(In millions, except per unit data)
1st Qtr.
Total revenues and other income $ 1,420 $ 1,578 $ 1,712 $ 1,715 $
Income from operations
Net income
Net income attributable to
672
516
666
439
608
456
557
423
2nd Qtr.
3rd Qtr.
4th Qtr.
1st Qtr.
2nd Qtr.
3rd Qtr.
886 $
265
187
916 $
280
191
4th Qtr.
980 $ 1,085
335
311
241
217
421
453
510
434
150
190
216
238
MPLX LP
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
Distributions declared:
Limited partner units—Public
Limited partner units—MPC
General partner units—MPC
IDRs—MPC
Redeemable preferred units
Total distributions
declared
0.61
0.61
—
0.55
0.55
—
0.62
0.62
—
0.52
0.52
—
0.20
0.19
—
0.26
0.26
—
0.29
0.29
—
0.31
0.31
—
0.6175
0.6275
0.6375
0.6475
0.5400
0.5625
0.5875
0.6075
179
288
—
—
16
181
316
—
—
20
185
322
—
—
19
187
327
—
—
20
149
49
5
60
16
162
56
6
70
17
170
62
7
81
16
175
171
—
—
16
$
483 $
517 $
526 $
534 $
279 $
311 $
336 $
362
178
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, 2018. Based on this evaluation, MPLX’s management, including our Chief
Executive Officer and Chief Financial Officer, concluded that as of December 31, 2018, 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, 2018, 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
179
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 Marathon Petroleum Corporation
(“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.
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.
Name
Gary R. Heminger
Michael J. Hennigan
Pamela K.M. Beall
Michael L. Beatty
Gregory J. Goff
Timothy T. Griffith
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(a)
Rick D. Hessling(a)
Brian K. Partee(a)
David L. Whikehart(a)
Timothy J. Aydt(a)
Molly R. Benson(a)
Peter Gilgen(a)
C. Kristopher Hagedorn
Kristina A. Kazarian(a)
Shawn M. Lyon(a)
(a) Corporate officer
Age as of
January 31, 2019
Position with MPLX GP LLC
65
59
62
71
62
49
64
67
70
67
59
64
55
55
59
53
58
52
45
59
55
52
62
42
36
51
Chairman of the Board of Directors and Chief Executive Officer
Director and President
Director, Executive Vice President and Chief Financial Officer
Director
Director
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
180
Gary R. Heminger, 65, was appointed Chairman of the Board and Chief Executive Officer in June 2012. He has
served as MPC’s Chairman of the Board since April 2016 and as its Chief Executive Officer since 2011. He was
also MPC’s President from 2011 to 2017. Mr. Heminger has also served as Chairman of the Board and Chief
Executive Officer of Tesoro Logistics GP, LLC, a wholly-owned subsidiary of MPC and the general partner of
Andeavor Logistics LP, since October 2018. He 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 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 a member of The Ohio State
University Board of Trustees and past Chairman 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 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
(since 2018); Fifth Third Bancorp (since 2006); PPG Industries, Inc. (since 2017)
Michael J. Hennigan, 59, was appointed President and elected a member of the Board in June 2017. He has also
served on the Tesoro Logistics GP, LLC Board of Directors since October 2018. 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. Before that, from 2012 to 2017, he served as President and Chief
Executive Officer of Sunoco Logistics Partners L.P., an oil and gas transportation, terminalling and storage
company, where he was responsible for all operations and business activities, including setting the direction,
strategy and vision for the company. Mr. Hennigan joined Sunoco Logistics as Vice President, Business
Development in 2009, was named President and Chief Operating Officer in 2010 and was named President and
Chief Executive Officer in 2012. He 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 35 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 (since 2018); Sunoco Partners LLC (2010 to
2017); Niska Gas Storage Partners LLC (2014 to 2016)
Pamela K.M. Beall, 62, has served as our Executive Vice President and Chief Financial Officer since 2016, and
was elected a member of the Board in January 2014. She has also served on the Tesoro Logistics GP, LLC Board
of Directors since October 2018. Ms. Beall began her career with Marathon in 1978 as an auditor, and then went
on to serve 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;
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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 (since 2018); National Retail Properties, Inc.
(since 2016)
Michael L. Beatty, 71, 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,
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 to 2015); MarkWest Energy GP, L.L.C.
(2008 to 2015)
Gregory J. Goff, 62, was elected a member of the Board effective October 1, 2018, upon the conclusion of
MPC’s acquisition of Andeavor. He has also served as Executive Vice Chairman of MPC and as a member of
MPC’s Board of Directors since October 2018 and continues his service as a member of the Tesoro Logistics GP,
LLC Board of Directors. Prior to MPC’s acquisition of Andeavor, Mr. Goff served as Chief Executive Officer
and President of Andeavor beginning in May 2010, and as its Chairman of the Board beginning in December
2014. He also served as Chairman of the Board and Chief Executive Officer of Tesoro Logistics GP, LLC from
December 2010 to October 2018. Prior to joining Andeavor, Mr. Goff served as Senior Vice President,
Commercial for ConocoPhillips, an international, integrated energy company, from 2008 to 2010, and held a
number of other positions at ConocoPhillips from 1981 to 2008, including Managing Director and CEO of
Conoco JET Nordic; Chairman and Managing Director of Conoco Limited, a UK-based refining and marketing
affiliate; President of ConocoPhillips Europe and Asia Pacific downstream operations; President of
ConocoPhillips U.S. Lower 48 and Latin America exploration and production business; and President of
ConocoPhillips’ specialty businesses and business development. Mr. Goff serves on the National Advisory Board
of the University of Utah Business School and previously served as Chairman of the Board of AFPM. He holds a
bachelor’s degree in science and a master’s degree in business administration from the University of Utah.
Qualifications: Mr. Goff brings to the Board a deep understanding of and unique perspective on our business,
operations and market environment, as well as leadership, industry, strategic planning and operations experience.
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Other Public Company Directorships: Marathon Petroleum Corporation (since 2018); Tesoro Logistics GP, LLC
(since 2010); PolyOne Corporation (since 2011); Andeavor (2010 to 2018); Western Refining Logistics GP, LLC
(2017); QEP Midstream Partners, LP (2014 to 2015); DCP Midstream LP (2008 to 2010)
Timothy T. Griffith, 49, was elected a member of the Board in March 2015. He has served as Senior Vice
President and Chief Financial Officer of MPC since 2015. He has also served on the Tesoro Logistics GP, LLC
Board of Directors since October 2018. Mr. Griffith previously served as Vice President, Finance and Investor
Relations, and Treasurer of MPC and MPLX GP from 2014 to 2015, as Vice President, Finance and Treasurer of
MPC from 2011 to 2014 and in that same capacity for MPLX GP from 2012 to 2014. Prior to joining MPC,
Mr. Griffith served as Vice President and Treasurer of Smurfit-Stone Container Corporation, where he had
executive responsibility for the company’s investor interface and treasury operations, including capital structure,
cash management, insurance and investment oversight. Mr. Griffith also served as Vice President and Treasurer
of Cooper-Standard Automotive; as Assistant Treasurer of Lear Corporation; as the Capital Planning Officer for
Comerica Incorporated and as a derivatives specialist with Citicorp Securities. Mr. Griffith holds a bachelor’s
degree in economics from Michigan State University and a master’s degree in business administration from the
University of Michigan, and he has attended the Oxford Institute for Energy Studies. He is also a chartered
financial analyst, a designation he has held since 1995.
Qualifications: Mr. Griffith brings to the Board extensive experience gained from a variety of roles in finance
over the course of his career, including roles of increasing responsibility at several publicly traded and privately
sponsored businesses and continuing with the management of the financial affairs of MPC and us. Mr. Griffith
has been deeply involved in our strategy formation and execution.
Other Public Company Directorships: Tesoro Logistics GP, LLC (since 2018)
Christopher A. Helms, 64, 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 Range
Resources Corporation Board of Directors and 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 (since 2014); Questar Corporation (2013 to
2016)
Garry L. Peiffer, 67, 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
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Valley Health System and the Findlay-Hancock County Community Foundation and serves on the Blanchard
Valley Port Authority Board. Mr. Peiffer 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 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
Dan D. Sandman, 70, 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)
Frank M. Semple, 67, 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 as a member of the MPC Board of Directors from
December 2015 until October 2018, and has served on the Tesoro Logistics GP, LLC Board of Directors since
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,
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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: Tesoro Logistics GP, LLC (since 2018); Marathon Petroleum Corporation
(2015 to 2018); MarkWest Energy GP, L.L.C. (2003 to 2015)
J. Michael Stice, 59, 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 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 to 2015); MarkWest Energy GP L.L.C. (2015); SandRidge Energy, Inc. (2015 to 2016); Williams Partners
GP LLC (2012 to 2015)
John P. Surma, 64, 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 board of the Federal Reserve Bank of
Cleveland. 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.
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Other Public Company Directorships: Marathon Petroleum Corporation (since 2011); Concho Resources Inc.
(since 2014); Ingersoll-Rand plc (since 2012); United States Steel Corporation (2001 to 2013)
Donald C. Templin, 55, was elected a member of the Board in June 2012. He has served as President, Refining,
Marketing and Supply of MPC since October 2018. He has also served on the Tesoro Logistics GP, LLC Board
of Directors since October 2018. Mr. Templin joined MPC as Senior Vice President and Chief Financial Officer
in 2011 and was subsequently appointed as Vice President and Chief Financial Officer of MPLX GP in 2012,
Executive Vice President, Supply, Transportation and Marketing of MPC in 2015, President of MPLX GP and
Executive Vice President of MPC in 2016 and President of MPC in 2017. 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.
Other Public Company Directorships: Tesoro Logistics GP, LLC (since 2018); Calgon Carbon Corporation
(2013 to 2018)
Gregory S. Floerke, 55, is Executive Vice President, Gathering and Processing. He joined us in December 2015,
at the time of the MarkWest Merger, as Executive Vice President and Chief Commercial Officer, MarkWest
Assets. He was named Executive Vice President and Chief Operating Officer, MarkWest Operations in 2016 and
assumed his current position in 2018. Prior to joining us, Mr. Floerke served as Executive Vice President and
Chief Commercial Officer at MarkWest beginning in 2015, and as Senior Vice President, Northeast region at
MarkWest from 2013 to 2015. Previously, Mr. Floerke held senior management positions at Access Midstream
Partners, L.P., a gathering and processing master limited partnership, from 2011 until 2013.
John S. Swearingen, 59, is Executive Vice President, Logistics and Storage. He was previously our Vice
President, Crude Oil and Refined Products Pipelines and Chief Operating Officer, Pipeline Operations and served
as MPC’s Senior Vice President, Transportation and Logistics beginning in 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.
Suzanne Gagle, 53, has served as our General Counsel since October 2017, and as the General Counsel of MPC
since March 2016. She was also appointed as the General Counsel of Tesoro Logistics GP, LLC in October 2018.
Prior to her role as General Counsel, Ms. Gagle was 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.
Raymond L. Brooks, 58, has served as our Senior Vice President since February 2018, and as MPC’s Executive
Vice President, Refining since October 2018, having served as MPC’s Senior Vice President, Refining beginning
in March 2016. Prior to that, Mr. Brooks was General Manager of MPC’s Galveston Bay, Texas refinery
beginning in February 2013, its Robinson, Illinois refinery beginning in 2010 and its St. Paul Park, Minnesota
refinery beginning in 2006.
Rick D. Hessling, 52, has served as our Senior Vice President, and MPC’s Senior Vice President, Crude Oil
Supply and Logistics since October 2018. Prior to that, Mr. Hessling was Manager, Crude Oil & Natural Gas
Supply and Trading beginning in September 2014. Previously Mr. Hessling served as Crude Oil Logistics &
Analysis Manager beginning in July 2011.
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Brian K. Partee, 45, has served as our Senior Vice President, and MPC’s Senior Vice President, Marketing
since October 2018. Prior to that, Mr. Partee was MPC’s Vice President, Business Development beginning in
February 2018. Previously, Mr. Partee was 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.
David L. Whikehart, 59, has served as our Senior Vice President, and MPC’s Senior Vice President, Light
Products, Supply and Logistics since October 2018. Prior to that, Mr. Whikehart served as MPC’s Vice
President, Environment, Safety and Corporate Affairs beginning in February 2016 and Director, Product Supply
and Optimization beginning in March 2011.
Timothy J. Aydt, 55, has served as our Vice President, Business Development since November 2018, having
served as our Vice President, Operations and as President of Marathon Pipe Line LLC beginning in January
2017. Prior to that, he served as MPC’s Terminal, Transport and Rail General Manager beginning in 2013, and
the Project Director for the Detroit Heavy Oil Upgrade Project beginning in 2008.
Molly R. Benson, 52, has served as our Vice President, Chief Compliance Officer and Corporate Secretary since
March 2016, and as Chief Securities and Governance Officer since June 2018. Ms. Benson has served in these
same capacities with MPC and Tesoro Logistics GP, LLC beginning in March 2016 and October 2018,
respectively. Previously, Ms. Benson was MPC’s Assistant General Counsel, Corporate and Finance beginning in
April 2012 and Group Counsel, Corporate and Finance beginning in 2011.
Peter Gilgen, 62, has served as our Vice President and Treasurer since February 2017. Prior to that, Mr. Gilgen
was our Assistant Treasurer beginning in 2012 and the Assistant Treasurer of MPC beginning in 2011.
C. Kristopher Hagedorn, 42, joined us in 2017 as Vice President and Controller. Prior to that, Mr. Hagedorn
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 served as 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.
Kristina A. Kazarian, 36, has served as our Vice President, Investor Relations since April 2018. Ms. Kazarian
has also served as the Vice President, Investor Relations of MPC and of Tesoro Logistics GP, LLC beginning in
April and October of 2018, respectively. Previously, Ms. Kazarian 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 she worked at Deutsche Bank, a global investment bank and
financial services company, as Managing Director of MLP, Midstream and Natural Gas Equity Research
beginning in September 2014, and as an analyst specializing on various energy industry subsectors with Fidelity
Management & Research Company, a privately held investment manager, beginning in 2005.
Shawn M. Lyon, 51, has served as our Vice President, Operations and President, Marathon Pipe Line LLC since
November 2018. Prior to that, he was Vice President of Operations for Marathon Pipe Line LLC since 2011.
GOVERNANCE FRAMEWORK
Our Governance Principles provide the functional framework of our Board. They address, among other things,
the Board’s primary roles, responsibilities and oversight functions, director independence, committee
composition, the process for director selection and director qualifications, director compensation and director
retirement and resignation.
We have adopted a Code of Ethics for Senior Financial Officers that is specifically applicable to the CEO, the
CFO, the Controller and persons performing similar functions, as well as to those designated as Senior Financial
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Officers by our Chairman and CEO or our Audit Committee. In addition, we have a Code of Business Conduct
that applies to all of our directors, officers and employees. Copies of these documents are available on our
website and printed copies are also available upon request to our Corporate Secretary. We will post on our
website any amendments to, or waivers from, either of our Codes requiring disclosure under applicable rules
within four business days following the date of the 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
the confidential, anonymous submission by employees or others of concerns regarding questionable accounting
or auditing matters.
Copies of the Governance Principles, the Code of Ethics for Senior Financial Officers, the Code of Business
Conduct and the Whistleblowing as to Accounting Matters Policy are available on our website at
www.mplx.com under the heading “Investors” and the subheading “Corporate Governance.”
DIRECTOR INDEPENDENCE
The Board currently consists of thirteen 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, Stice and Surma meets the independence standards in our
Governance Principles, has no material relationship with us other than as a director, and satisfies the
independence requirements of the NYSE and applicable SEC rules. Mr. Daberko, who retired from the Board
effective April 25, 2018, also met these independence standards during his service on the Board in 2018.
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 is elected Chairman, the Board may appoint 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 our website at www.mplx.com under the heading “Investors” and the subheading “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.
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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 each of Messrs.
Helms and Peiffer qualifies as an “audit committee financial expert,” as defined by SEC rules, based on the
attributes, education and experience further described in their biographies under “Directors and Executive
Officers of MPLX GP LLC,” above.
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 2018 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 Public Company Accounting Oversight Board’s standard, Auditing Standard No. 1301. The
Committee has received the written disclosures and the letter from PricewaterhouseCoopers LLP required by the
applicable requirements of the Public Company Accounting Oversight Board for independent auditor
communications with audit committees 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, 2018, 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.
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COMMUNICATING WITH THE BOARD
All interested parties, including unitholders, may communicate directly with our independent directors by writing
to:
Board of Directors (non-management members)
c/o Corporate Secretary, MPLX GP LLC
200 East Hardin Street
Findlay, Ohio 45840
Interested parties may communicate with the Chairs of our Audit Committee or Conflicts Committee by sending
an email to:
auditchair@mplx.com
conflictschair@mplx.com
Interested parties may communicate with the independent directors, individually or as a group, by sending an
e-mail to:
non-managedirectors@mplx.com
The 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 our affairs.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Exchange Act requires our directors, executive officers, and holders of more than 10% of a
registered class of our equity securities to file with the SEC initial reports of beneficial ownership and reports of
changes in beneficial ownership of our equity securities. Based solely on our review of the reporting forms and
written representations provided by the individuals required to file reports, we believe that during the year ended
December 31, 2018, our directors, executive officers and greater-than-10% beneficial holders filed the required
reports on a timely basis under Section 16(a).
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Item 11. Executive Compensation
COMPENSATION DISCUSSION AND ANALYSIS
This compensation discussion and analysis (“CD&A”) describes the material components of the executive
compensation program for our named executive officers (our “NEOs”). We also provide an overview of our
compensation philosophy and objectives and explain how and why 2018 compensation decisions were made. We
recommend that this section be read in conjunction with the tables and related disclosures in the “Executive
Compensation Tables” section of this Item 11.
NAMED EXECUTIVE OFFICERS
Our NEOs consist of our principal executive officer, principal financial officer and our next three most highly
compensated executive officers:
Name
Title
Gary R. Heminger
Pamela K.M. Beall
Michael J. Hennigan
Gregory S. Floerke
John S. Swearingen
Chairman of the Board and Chief Executive Officer
Executive Vice President and Chief Financial Officer
President
Executive Vice President, Gathering and Processing
Executive Vice President, Logistics and Storage
COMPENSATION DECISIONS AND ALLOCATION
We do not directly employ any of the personnel responsible for managing and operating our business. 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 the omnibus agreement, described in Part I, Item 1. Business, we pay MPC a fixed
amount in return for these services, including services provided by our NEOs.
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 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 Disclosure
Mr. Heminger, our CEO and 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 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 represent all of the material elements of his compensation
attributable to the services he provides to our business. All components of Mr. Heminger’s compensation,
including those disclosed in this CD&A and those provided directly by MPC, will be disclosed in MPC’s proxy
statement for 2019.
As Ms. Beall and Messrs. Hennigan, Floerke and Swearingen devoted most of their total business time to us in
2018, this CD&A discloses all components of their compensation, with the non-equity elements of
Mr. Swearingen’s compensation generally prorated at 75% to reflect the percent allocated to us.
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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.
ELEMENTS OF COMPENSATION
2018 Base Salary
MPC pays our NEOs a base salary for their services to MPC and its affiliates, including us. Taking into
consideration peer group data, each individual’s experience, contribution and demonstrated performance, MPC’s
current and future succession needs, business results, external competitiveness and internal pay equity, MPC’s
Compensation Committee made the following adjustments to our NEOs’ base salaries for 2018:
Name
Beall
Hennigan
Floerke
Swearingen(a)
Previous Base Salary ($)
Base Salary
Effective Apr. 1, 2018 ($)
Increase (%)
525,000
800,000
450,000
375,000
545,000
900,000
525,000
393,750
3.8
12.5
16.7
5.0
(a) As noted above in “Compensation Decisions and Allocation,” certain elements of Mr. Swearingen’s
compensation, including his base salary, were allocated to us 75% for 2018 and are reflected as such in this
table and in the “Salary” column of the “2018 Summary Compensation Table” below.
MPC’s Compensation Committee’s decisions to increase Messrs. Hennigan’s and Floerke’s base salaries in
particular were based on each NEO’s continued strong performance and the Committee’s determination to bring
each NEO closer to the market median for his position. The decisions to increase the base salaries of Ms. Beall
and Mr. Swearingen reflect annual merit program increases to maintain market competitiveness.
As noted above in “Compensation Decisions and Allocation,” we reimburse MPC a fixed amount in return for
Mr. Heminger’s services to us. For 2018, that amount was $1,350,000, which is reflected under “Salary” in the
“2018 Summary Compensation Table” below.
2018 Annual Cash Bonus Program
Our NEOs are eligible to earn an annual bonus under MPC’s Annual Cash Bonus (“ACB”) program for the
services they provide to MPC and its affiliates, including us. MPC determines awards to our NEOs under the
ACB program without input from our Board or us. Under the omnibus agreement, no portion of any bonus paid
to our NEOs under the ACB is charged back to us.
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2018 ACB Program Structure
In February 2018, MPC’s Compensation Committee, based on MPC management’s recommendation, approved
the ACB program for 2018. Awards under the ACB program for our NEOs are calculated as follows:
Annualized
Base Salary X
Bonus Target
X
Performance
=
Final Award
Bonusp opportunities are
expressed as a percentage of
each NEO’s base salary.
MPC’s Compensation
Committee approves target
bonus opportunities for our
NEOs based on analysis of
market-competitive data of
MPC’s compensation peer
group, while also taking into
consideration each
executive’s experience,
relative scope of
responsibility and potential,
internal pay equity
considerations and any other
information the Committee
deems relevant in its
discretion.
At the beginning of the
performance year, MPC’s
Compensation Committee
establishes the performance
metrics.
After the end of the
performance year, MPC’s
Compensation Committee
reviews and assesses MPC’s
performance against the
pre-established performance
metrics, as well as other
factors the Committee deems
relevant in its discretion.
MPC’s Compensation
Committee also reviews and
assesses each NEO’s
organizational and
individual performance.
Following this review,
MPC’s Compensation
Committee makes a final
annual bonus decision for
each NEO. Payout results
may be above or below
target based on actual MPC
and individual performance.
Awards under the ACB program are generally capped at 200% of each NEO’s target award. MPC does
not guarantee minimum bonus payments to our NEOs.
2018 MPC 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%, as reflected in the table below. The remaining 30% is driven by 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.
The threshold, target and maximum levels of performance for each performance metric were established for 2018
by evaluating factors such as performance achieved in the prior year(s), anticipated challenges for 2018, MPC’s
business plan and overall strategy. At the time the performance levels were set for 2018, the threshold levels
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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 table below provides the goals for each metric, target
weighting and MPC’s performance achieved in 2018 ($ in millions):
Category
Performance Metric
Threshold
50%
Payout
Target
100%
Payout
Maximum
200%
Payout
Financial
Operating Income Per
Barrel(a)
Controllable Costs(b)
5th or 6th
Position
7,015
3rd or 4th
Position
6,680
1st or 2nd
Position
6,510
Distributable Cash Flow at
MPLX LP(c)
EBITDA(d)
2,335
2,595
2,725
3,400
5,700
7,500
Operational Mechanical Availability(e)
Marathon Safety
Performance Index(f)
Process Safety Events
Rate(g)
Designated Environmental
Incidents(h)
Quality Incidents(i)
0.94
1.00
0.60
82
0.95
0.65
0.39
59
0.96
0.40
0.23
36
500,000
250,000
125,000
Result
4th Position
(100% of target)
$6,498
(200% of target)
2,781
(200% of target)
8,001
(200% of target)
0.959
(190% of target)
1.07
(0% of target)
0.27
(175% of target)
23
(200% of target)
—
(200% of target)
Target
Weighting
Performance
Achieved
15%
10%
10%
5%
10%
5%
5%
5%
5%
15%
20%
20%
10%
19%
—
8.8%
10%
10%
Total
70%
112.8%
(a) Measures MPC’s operating income per barrel of crude oil throughput, adjusted for unusual business items
and accounting changes, compared to a group of peer companies, which for 2018 were: BP p.l.c.; Chevron
Corporation; ExxonMobil Corporation; HollyFrontier Corporation; PBF Energy; Phillips 66; and Valero
Energy Corporation.
(b) Costs generally not subject to change based on production volume, purchases of commodities, sales,
throughputs or changes in commodity prices. These costs are adjusted to exclude costs related to
acquisitions and divestitures, capital projects in excess of $500 million, and employee bonus accruals.
(c) Represents the cash flow available to be paid to our common unitholders, as disclosed in our consolidated
financial statements.
(d) Derived from MPC’s consolidated financial statements and adjusted for certain items. This non-GAAP
performance metric is calculated as earnings before interest and financing costs, interest income, income
taxes, depreciation and amortization expense adjusted to exclude the effects of impairment expenses,
pension settlement gains/losses, inventory market valuation adjustments, certain non-cash charges and
credits and the effects of acquisitions and divestitures.
(e) Measures the mechanical availability of the processing equipment in MPC’s refineries and the critical
equipment in MPC’s midstream assets.
(f) 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.
(g) Measures MPC’s ability to identify, understand and control certain process hazards.
(h) Measures certain internal environmental performance metrics.
(i)
Shown in absolute dollars. Measures the impact of product quality incidents and cumulative costs to MPC.
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NEO Individual Performance
At the beginning of the year, each NEO develops individual performance goals relative to his or her respective
organizational responsibilities, which are directly related to MPC’s business objectives. The subjective goals
used to evaluate the individual performance of our NEOs for 2018 fell into the following general categories:
Goals
Beall Hennigan Floerke Swearingen
Talent development, retention, succession and acquisition
Enhancement of unitholder value through return of capital and
unlocking midstream asset value
Excellence in environmental, personal safety and process safety
improvement
System integration, optimization and removing bottlenecks
Growth through organic expansion and acquisition opportunities
Progress on diversity initiatives
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
Following the end of 2018, our CEO reviewed the organizational and individual performance of the other NEOs
and made annual bonus recommendations to MPC’s Compensation Committee. Key factors considered for 2018
included:
• Reported record full-year net income of $1.8 billion, an increase of $1.0 billion compared to 2017;
• Executed on our strategic vision by significantly growing our business, enhancing the stability of our cash
flow profile, and simplifying our financial structure; and
• Returned nearly $2.1 billion to our unitholders.
Bonus Payments for 2018
In February 2019, MPC’s Compensation Committee certified the results of the performance metrics for the 2018
ACB program and, taking into consideration MPC’s performance relative to the pre-established metrics, each
NEO’s organizational and individual performance, and the key factors discussed above, awarded the following
amounts under the ACB program to our NEOs for 2018:
Name
Beall
Hennigan
Floerke
Swearingen(a)
2018 Year-End
Base Salary ($)
Bonus Target as a %
of Base Salary
Target Bonus
($)
Final Award as
a % of Target Final Award ($)
545,000
900,000
525,000
393,750
70
100
70
70
381,500
900,000
367,500
275,625
176
178
166
166
670,000
1,600,000
610,000
457,500
(a) As noted above in “Compensation Decisions and Allocation,” certain elements of Mr. Swearingen’s
compensation, including his 2018 bonus payment, were allocated to us 75% for 2018 and are reflected as
such in this table and in the “Non-Equity Incentive Plan Compensation” column of the “2018 Summary
Compensation Table” below.
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 equity performance and
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 Chairman and
the independent directors (the “MPLX Committee”) following a recommendation by MPC’s Compensation
Committee. For 2018, 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.
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LTI awards represent a compensation opportunity. The actual long-term compensation value realized by our
NEOs will depend on the price of our underlying common units at the time of settlement. The 2018 LTI awards
were based on an intended dollar value rather than a specific number of performance units or phantom units.
Each form of LTI award is discussed in more detail below.
MPLX Performance Units
The MPLX Committee believes that performance unit awards align our NEOs’ interests with the interests of our
unitholders. Performance units granted in 2016 are based on Total Unitholder Return (“TUR”) relative to a peer
group of midstream companies, as further described below. In 2017, the MPLX Committee added a
DCF-per-MPLX-common-unit metric to our performance unit program to align it with contemporary industry
program design. The MPLX Committee believes the TUR and DCF metrics are important indicators of
performance as they are commonly used by unitholders to measure a master limited partnership’s (“MLP”)
performance against others within the same industry. Achieving above-target payouts would require at least one
of these two metrics to achieve above-target performance.
TUR for MPLX and each peer group MLP is measured over a 36-month performance cycle. Each performance
cycle has four equally weighted measurement periods: (i) the first 12 months, (ii) the second 12 months, (iii) the
third 12 months, and (iv) the entire 36-month period. The MPLX Committee believes this structure is appropriate
as maximum payout based on TUR may only be achieved by outperforming the TUR peer group for all four
measurement periods.
Each peer group member’s TUR is determined by the following formula:
(Ending Unit Price – Beginning Unit Price) + Cumulative Cash Distributions
Beginning Unit Price
The beginning and ending unit prices used for MPLX and each peer group member in the TUR calculation are
the averages of each company’s closing unit price for the 20 trading days immediately preceding the beginning
or ending date of the applicable measurement period. This helps mitigate significant market fluctuations in unit
price at the beginning or end of a performance cycle and discourages excessive or inappropriate risk-taking near
the end of a performance cycle by limiting the impact on the overall payout of the award.
Our TUR performance percentile within the peer group is measured for each measurement period, with the
related payout percentage determined as follows:
TUR Percentile
100th (Highest)
50th
25th(b)
Below 25th(b)
Payout (% of Target) (a)
200%
100%
50%
0%
(a)
(b)
Payout for performance between quartiles will be determined using linear interpolation.
Increased to the 30th percentile for awards granted in 2018 and thereafter.
Each performance unit is denominated in dollars with a target value of $1.00. The actual payout may vary from
$0.00 to $2.00 (0% to 200% of target). The MPLX Committee believes that capping the maximum payout at
200% mitigates excessive or inappropriate risk-taking. In addition, if our TUR is negative for a measurement
period, the payout percentage for that measurement period is capped at target (100%) regardless of actual relative
TUR performance percentile. These awards settle 25% in common units and 75% in cash. Holders of unvested
performance units do not receive cash distributions and do not have voting rights.
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Performance units granted in 2016 had a performance cycle of January 1, 2016 through December 31, 2018. The
peer group for these performance units was: Andeavor Logistics LP, Buckeye Partners, L.P., Enbridge Energy
Partners, L.P., Energy Transfer Partners, L.P., Enterprise Products Partners L.P., Magellan Midstream Partners,
L.P., ONEOK Partners, L.P., Phillips 66 Partners LP, Plains All American Pipeline, L.P., Sunoco Logistics
Partners L.P., Valero Energy Partners LP, Western Gas Partners, LP and Williams Partners L.P. Due to industry
consolidations, ONEOK Partners, L.P. and Sunoco Logistics Partners L.P. were removed from the group
effective January 1, 2017, and Enbridge Energy Partners, L.P., Energy Transfer Partners, L.P. and Williams
Partners L.P. were removed from the group effective January 1, 2018.
In January 2019, the MPLX Committee certified the final TUR results for the four applicable measurement
periods as follows:
Measurement Period
Actual TUR (%)
Position
Percentile
Ranking (%)
Payout
(% of target)
January 1, 2016—December 31, 2016
January 1, 2017—December 31, 2017
January 1, 2018—December 31, 2018
January 1, 2016—December 31, 2018
3.2
17.5
(4.2)
15.7
12th
1st
6th
4th
15.38
100.00
37.50
62.50
Average:
0.00
200.00
75.00
125.00
100.00
The final value of the 2016 performance unit awards was determined by multiplying the simple average of the
payout percentages for the four measurement periods by the number of performance units granted. Based on the
resulting average, each performance unit granted was multiplied by $1.00, and the MPLX Committee approved
the following payouts to our NEOs:
Name
Heminger
Beall
Swearingen
Target Number of Performance Units MPLX Committee Approved Payout ($)
1,100,000
212,500
100,000
1,100,000
212,500
100,000
For performance unit awards granted in 2017 and 2018, the final value will be based 50% on our TUR, as
described above, and 50% on a DCF-per-MPLX-common-unit metric. This metric measures the growth of
MPLX’s full-year DCF over the three-year performance cycle. The MPLX Committee added this metric in 2017
as it believes unitholders view DCF as an important measure of an MLP’s performance relative to others in the
same industry.
Threshold, target and maximum DCF levels for the awards granted in 2017 are calculated by applying
pre-determined compound annual growth rates of 8%, 10% and 12%, respectively, over the DCF per MPLX
common unit for 2016 as follows:
Award Year
2017
Metric
DCF per common unit at
12/31/2019
Threshold (a)
(50% Payout)
Target (a)
(100% Payout)
Maximum (a)
(200% Payout)
$2.9559
$3.1232
$3.2967
(a) Payout for performance between these levels will be determined using linear interpolation.
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Threshold, target and maximum DCF levels for the awards granted in 2018 are determined at the beginning of
each year of the performance cycle by the MPLX Committee based on the annual business plan. The levels for
2018 were (in millions):
Award Year
2018
Metric
Threshold(a)
(50% Payout)
Target(a)
(100% Payout)
Maximum(a)
(200% Payout)
DCF at 12/31/2018
$2,335
$2,595
$2,725
(a)
Payout will be based on achievement of DCF in each year of the performance cycle as compared with the
threshold, target and maximum levels. Payout for performance between these levels will be determined
using linear interpolation.
Performance units granted to our NEOs in 2017 and 2018 remain outstanding. See the “Outstanding Equity at
2018 Fiscal Year-End” table below for additional information about these awards, including the amount granted,
the performance cycle and the applicable peer group.
MPLX Phantom Units
Grants of phantom units promote increased ownership by our NEOs of our common units, which strengthens
alignment between our NEOs’ interests and the interests of our unitholders. The value of phantom unit awards is
variable, based on the value of an underlying common unit. Awards generally vest in equal installments on the
first, second and third anniversaries of the grant date and are settled in common units. Distribution equivalents
accrue on the phantom unit awards and are paid upon vesting. Holders of unvested phantom units have no voting
rights. NEOs are required to hold all common units received upon vesting of phantom units for at least one year.
This requirement applies to units net of taxes at the time of vesting or distribution. See the “2018 Grants of Plan-
Based Awards” table below for the number of phantom units granted to our NEOs in 2018.
MPC Long-Term Incentive Compensation
As part of their total equity package, our NEOs also receive LTI awards from MPC. For 2018, 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 stock options and 20% in the form of restricted stock.
LTI awards represent a compensation opportunity. The actual long-term compensation value realized by our
NEOs will depend on the price of MPC’s underlying stock at the time of settlement. The 2018 LTI awards were
based on an intended dollar value rather than a specific number of performance units, stock options or shares of
restricted stock. Each form of LTI award is discussed in more detail below.
MPC Performance Units
MPC’s Compensation Committee believes that Total Shareholder Return (“TSR”) is the best overall
pay-for-performance metric to align our NEO’s interests with shareholder interests. MPC performance units
evaluate MPC’s TSR relative to a peer group of oil industry competitors and a market index. This relative
evaluation recognizes the cyclical nature of MPC’s business and commodity prices (crude oil) and prevents
volatility from directly advantaging or disadvantaging the payout of the award beyond that of MPC’s peers. MPC
performance units are designed to ensure above target compensation is paid only when MPC’s TSR is above the
median of the peer group.
TSR for MPC and each of the peer group companies is measured over a 36-month performance cycle. Each
performance cycle has four equally weighted measurement periods: (i) the first 12 months, (ii) the second 12
months, (iii) the third 12 months, and (iv) the entire 36-month period. MPC’s Compensation Committee believes
that this structure is appropriate as maximum payout based on TSR may only be achieved by outperforming the
TSR peer group for all four measurement periods.
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Each peer group member’s TSR for a measurement period is determined by the following formula:
(Ending Stock Price - Beginning Stock Price) + Cumulative Cash Dividends
Beginning Stock Price
The beginning and ending stock prices used for MPC and each peer group member in the TSR calculation are the
averages of each company’s closing stock price for the 20 trading days immediately preceding the beginning and
ending date of the applicable measurement period. This helps mitigate significant market fluctuations in stock
price at the beginning or end of a performance cycle and discourages excessive or inappropriate risk-taking near
the end of a performance cycle by limiting the impact on the overall payout of the award.
MPC’s TSR performance percentile within the peer group is measured for each measurement period, with the
related payout percentage determined as follows:
TSR Percentile
100th (Highest)
50th
25th(b)
Below 25th(b)
Payout (% of Target) (a)
200%
100%
50%
0%
(a)
(b)
Payout for performance between quartiles will be determined using linear interpolation.
Increased to the 30th percentile for awards granted in 2018 and thereafter.
Each performance unit is denominated in dollars with a target value of $1.00. The actual payout may vary from
$0.00 to $2.00 (0% to 200% of target). MPC’s Compensation Committee believes that capping the maximum
payout at 200% mitigates excessive or inappropriate risk-taking. In addition, if MPC’s TSR is negative for a
measurement period, the payout percentage for that measurement period is capped at target (100%) regardless of
actual relative TSR performance percentile. The final value of the performance unit award will be determined by
multiplying the simple average of the payout percentages for the four measurement periods by the number of
performance units granted. These awards settle 25% in MPC common stock and 75% in cash. Unvested
performance units do not receive dividends and do not have voting rights.
Performance units granted in 2016 had a performance cycle of January 1, 2016, through December 31, 2018. The
peer group for these performance units was: Andeavor, Chevron Corporation, HollyFrontier Corporation, PBF
Energy, Phillips 66, Valero Energy Corporation and the S&P 500 Energy Index. Due to its acquisition by MPC,
Andeavor was removed from the group effective January 1, 2018.
In January 2019, MPC’s Compensation Committee certified the final TSR results for the four applicable
measurement periods as follows:
Measurement Period
Actual TSR (%)
Position
January 1, 2016—December 31, 2016
January 1, 2017—December 31, 2017
January 1, 2018—December 31, 2018
January 1, 2016—December 31, 2018
(1.8)
34.6
(4.6)
25.4
5th
3rd
4th
3rd
Percentile
Ranking (%)
Payout
(% of Target)
42.86
71.43
50.00
66.67
Average:
85.72
142.86
100.00
133.34
115.48
199
Based on the resulting average, each performance unit granted was multiplied by $1.1548, and MPC’s
Compensation Committee approved the following payouts to our NEOs:
Name
Beall
Swearingen
Target Number of Performance Shares
MPC Compensation Committee Approved
Payout ($)
170,000
320,000
196,316
369,536
MPC performance units granted to our NEOs in 2017 and 2018 remain outstanding. See the “Outstanding Equity
at 2018 Fiscal Year-End” table below for additional information about these awards, including the amount
granted, the performance cycle, and the applicable peer group.
MPC Stock Options
MPC’s Compensation Committee awards MPC stock options to our NEOs to provide a direct but variable link
between their long-term compensation and the long-term value MPC’s shareholders receive by investing in MPC.
MPC’s Compensation Committee believes stock options are inherently performance-based as option holders
realize benefits only if the value of MPC’s stock increases for all shareholders after the grant date. The exercise
price of MPC’s stock options is generally equal to the per-share closing price of MPC’s common stock on the
grant date. Stock options generally vest in equal installments on the first, second and third anniversaries of the
grant date and expire 10 years following the grant date. Option holders do not have voting rights or receive
dividends on the underlying stock. See the “2018 Grants of Plan-Based Awards” table below for the number of
MPC stock options granted to our NEOs in 2018.
MPC Restricted Stock
MPC’s Compensation Committee awards restricted stock to our NEOs to promote their ownership of actual
shares of MPC’s common stock, to help them comply with MPC’s stock ownership guidelines and to promote
NEO retention. Awards generally vest in equal installments on the first, second and third anniversaries of the
grant date. Unvested restricted stock awards accrue dividends, which are paid upon vesting. Holders of unvested
restricted stock have voting rights. See the “2018 Grants of Plan-Based Awards” table below for the number of
shares of MPC restricted stock granted to our NEOs in 2018.
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 payable under MPC’s
qualified and nonqualified plans are described in more detail in “Post-Employment Benefits” and “Nonqualified
Deferred Compensation.”
200
Severance Benefits
Neither we nor MPC have entered into employment agreements with our NEOs. However, MPC’s Amended and
Restated Executive Change in Control Severance Benefits Plan and our Executive Change in Control Severance
Benefits Plan accomplish several objectives, including:
•
•
providing and preserving an economic motivation for participating executives to consider a business
combination that might result in an executive’s job loss, and
competing effectively in attracting and retaining executives in an industry that features frequent mergers,
acquisitions and divestitures.
These change in control benefits are described in more detail in “Potential Payments Upon Termination or
Change in Control.”
Perquisites
MPC offers limited perquisites to our NEOs, and believes the perquisites offered are consistent with those
offered by MPC’s peer group companies.
Our NEOs are eligible for reimbursement 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. MPC’s
Compensation Committee believes this benefit is appropriate due to the complexities of income tax preparation
for our NEOs, who may, for example, be required to make personal income tax filings in multiple states as a
result of receiving MPLX LP common units.
MPC also offers enhanced annual physical health examinations to senior management, including our NEOs, to
promote their health and well-being. Under this program, these officers 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.
The primary use of corporate aircraft is for business purposes and must be authorized by MPC’s CEO or another
executive officer designated by MPC’s Board or CEO. Occasionally, spouses or other guests may accompany our
NEOs or other executive officers on corporate aircraft when space is available on business-related flights. When
a spouse’s or guest’s travel does not meet the Internal Revenue Service standard for business use, the cost of that
travel is imputed as income to the NEO or other executive officer. Mr. Hennigan was granted limited personal
use of the aircraft when otherwise available during the first 12 months of his employment as MPLX President.
Reportable values for these perquisite programs, based on the incremental costs to MPC, are included in the “All
Other Compensation” column of the “2018 Summary Compensation Table.”
MPC does not provide income tax assistance or tax gross-ups on executive perquisites.
201
COMPENSATION GOVERNANCE
Unit Ownership Guidelines
Our Board has established unit ownership guidelines for our executive officers, including our NEOs, intended to
align their 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
Number of Units to Be Held
Chairman of the Board and Chief Executive Officer
President
Executive Vice Presidents
Senior Vice Presidents
Vice Presidents
25,000
20,000
15,000
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. As of December 31,
2018, all of our executive officers, including our NEOs, had met their ownership guidelines.
Prohibition on Derivatives and Hedging
We prohibit hedging transactions related to our units, and pledging or creating security interests in our units,
including units in excess of a unit ownership guideline requirement. This ensures that our executive officers,
including our NEOs, bear the full risk of MPLX LP common unit ownership.
Recoupment/Clawback Policy
Our NEOs are subject to recoupment provisions under MPC’s ACB and LTI programs in the case of certain
forfeiture events. In addition, the MPLX 2012 Plan provides that all awards granted thereunder will be subject to
clawback or recoupment in the case of certain forfeiture events. If we are required, as a result of a determination
made by the SEC or our Audit Committee, 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 detrimental 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 a payment has
previously been made to the executive officer 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 the requirements under Section 304 of the Sarbanes-Oxley Act of
2002, which require the CEO and CFO to reimburse us for incentive-based or equity-based compensation, as
well as any related profits received in the 12-month period prior to the filing of an accounting restatement due to
noncompliance with financial reporting requirements as a result of misconduct. Additionally, all equity grants
made since 2013 include provisions making them subject to any clawback provisions required by the Dodd-Frank
Wall Street Reform and Consumer Protection Act, and to any other “clawback” provisions as required by law or
by the applicable listing standards of the NYSE.
202
Compensation-Based Risk Assessment
The MPLX Committee reviews 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. The MPLX
Committee completed its review of our 2018 programs in February 2019, 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 CEO, and the independent directors
of our Board. Mr. Heminger is also an executive officer and director of MPC. During 2018, 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 an independent director on our Board.
COMPENSATION COMMITTEE REPORT
Our Chairman and independent directors have reviewed and discussed the Compensation Discussion and
Analysis for 2018 with management and, based on such review and discussions, recommended to the Board that
the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the fiscal year
ended December 31, 2018.
Gary R. Heminger, Chairman
Michael L. Beatty
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
J. Michael Stice
John P. Surma
203
EXECUTIVE COMPENSATION TABLES
2018 SUMMARY COMPENSATION TABLE
The following table provides information regarding compensation for our 2018 NEOs for the years shown:
Salary (a)
Bonus (b)
Stock
Awards
(c)(d)
Option
Awards
(c)
Non-Equity
Incentive Plan
Compensation
(e)
Change in
Pension Value
and
Nonqualified
Deferred
Compensation
Earnings (f)
All Other
Compensation
(g)
Year
($)
($)
($)
($)
($)
($)
($)
Total
($)
2018 1,350,000
— 1,512,459
2017 1,310,000
— 2,282,185
2016 1,220,000
— 1,797,853
—
—
—
—
—
—
—
—
—
— 2,862,459
— 3,592,185
— 3,017,853
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
2016
499,667
— 529,759 170,008
550,000
226,408
86,067
2,061,909
2018
875,000
— 1,949,566 525,008
1,600,000
152,366
143,772
5,245,712
2017
429,589 1,000,000 5,000,052
—
800,000
126,322
157,086
7,513,049
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
2016
415,000
—
—
—
425,000
62,847
55,179
958,026
2018
389,063
— 557,058 150,007
457,500
—
61,608
1,615,236
Name and Principal
Position
Gary R. Heminger
Chairman of the
Board and Chief
Executive Officer
Pamela K.M. Beall
Executive Vice
President and Chief
Financial Officer
Michael J.
Hennigan
President
Gregory S.
Floerke
Executive Vice
President,
Gathering and
Processing
John S.
Swearingen
Executive Vice
President, Logistics
and Storage
(a) With respect to Mr. Heminger, amounts reflect the annualized fixed fee we pay MPC for Mr. Heminger’s
services under the Omnibus Agreement. With respect to Mr. Swearingen, amounts reflect the portion of his
compensation that was allocated to us for 2018 (75%). With respect to the other NEOs, amounts reflect
actual salary earned during the fiscal year covered. Compensation is reviewed after the end of each year, and
salary increases, if any, are generally effective April 1 of the following year. See “Executive Compensation
Discussion and Analysis—Elements of Compensation—Base Salary” for additional information on base
salaries for 2018.
The amount shown for Mr. Hennigan reflects a cash sign-on bonus.
The amounts shown in these columns 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 22 for assumptions used in the calculation of the amounts related
to MPLX equity for the year ended December 31, 2018 and Note 23 to MPC’s financial statements included
(b)
(c)
204
(d)
(e)
(f)
in its Annual Report on Form 10-K for the year ended December 31, 2018 for valuation assumptions used to
determine the value of these awards.
The maximum value of the performance units granted in 2018, assuming the highest level of performance is
achieved, is: Mr. Heminger, MPLX—$2,700,000; Ms. Beall, MPLX—$500,000 and MPC—$500,000;
Mr. Hennigan, MPLX—$1,750,000 and MPC—$1,750,000; Mr. Floerke, MPLX—$500,000 and MPC—
$500,000; and Mr. Swearingen, MPLX—$500,000 and MPC—$500,000.
For Mr. Swearingen, reflects 75% of the total value of his ACB award. For the other NEOs, reflects the total
value of ACB awards earned for the year indicated. ACB awards are generally paid in the year following the
year in which they are earned.
The amounts shown in this column reflect the annual change in actuarial present value of accumulated
benefits under the MPC retirement plans. See “Post-Employment Benefits for 2018” in this Item 11 for
more information regarding the defined benefit plans and the assumptions used in the calculation of these
amounts. There are no deferred compensation earnings reported in this column as the nonqualified deferred
compensation plans do not provide above-market or preferential earnings.
(g) MPC offers limited perquisites to our NEOs which, together with contributions to defined contribution
plans, comprise the amounts reported in this column. See “Executive Compensation Discussion and
Analysis—Other Benefits—Perquisites” for a description of each of these items.
Personal Use of
Company
Aircraft ($) (h)
Company
Physicals ($)
Tax and Financial
Planning ($)
—
—
22,688
—
—
—
3,769
3,769
3,769
3,769
—
8,000
—
3,125
—
Company
Contributions to
Defined
Contribution
Plans ($) (i)
—
84,888
117,315
77,456
57,839
Total All Other
Compensation ($)
—
96,657
143,772
84,350
61,608
Name
Heminger
Beall
Hennigan
Floerke
Swearingen
(h)
(i)
The amounts shown in this column reflect MPC’s aggregate incremental cost of personal use of corporate
aircraft by our NEOs, their spouses or other guests for 2018, estimated using the average costs of operating
the aircraft, such as fuel costs, trip-related maintenance, crew travel expenses, trip-related fees, storage
costs, communications charges and other miscellaneous variable costs. Fixed costs, such as pilot
compensation, the purchase and lease of aircraft and maintenance not related to travel are excluded from
this calculation. We believe this method provides a reasonable estimate of MPC’s incremental cost;
however, it overstates the actual incremental cost when a flight has a primary business purpose, space is
available to transport an officer or his or her guest not traveling for business purposes and no incremental
cost is realized by MPC. No income tax assistance or gross-ups are provided for personal use of corporate
aircraft.
The amounts shown in this column reflect MPC’s contributions under our tax-qualified retirement plans and
related nonqualified deferred compensation plans. For Mr. Swearingen, these amounts reflect the portion of
his compensation that was allocated to us for 2018 (75%). See “Post-Employment Benefits for 2018” for
more information.
205
2018 GRANTS OF PLAN-BASED AWARDS
The following table provides information regarding all plan-based awards, including cash-based incentive awards
and equity-based awards, granted to our NEOs in 2018.
Name
Type of Award
Grant Date
(a)
Threshold
($)
Target
($)
Maximum
($)
Threshold
($)
Target
($)
Maximum
($)
Estimated Future Payouts
Under Non-Equity Incentive
Plan Awards (b)
Estimated Future Payouts
Under Equity Incentive Plan
Awards (c)
Heminger MPLX Phantom Units
3/1/2018
MPLX Phantom Units(e) 12/20/2018
MPLX Performance
Units
3/1/2018
Beall
MPLX Phantom Units
3/1/2018
MPLX Performance
Units
3/1/2018
MPC Stock Options
3/1/2018
MPC Restricted Stock
3/1/2018
168,750 1,350,000 2,700,000
31,250
250,000
500,000
MPC Performance Units
3/1/2018
31,250
250,000
500,000
MPC Annual Cash
Bonus
N/A
N/A
381,500
763,000
Hennigan MPLX Phantom Units
3/1/2018
MPLX Performance
Units
3/1/2018
MPC Stock Options
3/1/2018
MPC Restricted Stock
3/1/2018
109,375
875,000 1,750,000
MPC Performance Units
3/1/2018
109,375
875,000 1,750,000
MPC Annual Cash
Bonus
N/A
N/A
900,000 1,800,000
Floerke
MPLX Phantom Units
3/1/2018
MPLX Performance
Units
3/1/2018
MPC Stock Options
3/1/2018
MPC Restricted Stock
3/1/2018
31,250
250,000
500,000
MPC Performance Units
3/1/2018
31,250
250,000
500,000
MPC Annual Cash
Bonus
N/A
N/A
367,500
735,000
Swearingen MPLX Phantom Units
3/1/2018
MPLX Performance
Units
3/1/2018
MPC Stock Options
3/1/2018
MPC Restricted Stock
3/1/2018
31,250
250,000
500,000
MPC Performance Units
3/1/2018
31,250
250,000
500,000
MPC Annual Cash
Bonus
N/A
N/A
275,625
551,250
206
All
Other
Stock
Awards:
Number
of
Shares
of Stock
or Units
(#)
38,694
5,265
7,166
1,544
25,079
5,403
7,166
1,544
7,166
1,544
All Other
Option
Awards:
Number of
Securities
Underlying
Options
(#)
Exercise
or Base
Price of
Option
Awards
($)
Grant
Date Fair
Value of
Stock and
Option
Awards (d)
($)
1,350,034
162,425
—
250,022
—
8,636
64.79
150,007
100,036
207,000
875,006
—
30,225
64.79
525,008
350,060
724,500
250,022
—
8,636
64.79
150,007
100,036
207,000
250,022
—
8,636
64.79
150,007
100,036
207,000
(a)
(b)
(c)
The approval date for MPLX phantom unit and performance unit awards was February 28, 2018. The
approval date for MPC stock options, restricted stock and performance unit awards was February 27, 2018.
The approval date for Mr. Heminger’s 12/20/2018 award was December 20, 2018.
Target amounts reflect the target annual incentive opportunity. No threshold amount is disclosed as MPC’s
Compensation Committee has discretion to award no annual incentive under the ACB program. Each NEO
may generally earn a maximum of 200% of the target.
Target amounts reflect the number of performance units granted. Each performance unit has a target value
of $1.00. The threshold for the award is the minimum possible payout of the award, which is 12.5%. The
threshold is achieved when the payout percentage is 50% for one measurement period and 0% for the other
three measurement periods, thus an average payout percentage of 12.5% for the performance cycle. The
maximum payout for this award is 200% of target.
(d) Amounts reflect the total grant date fair value calculated in accordance with FASB ASC Topic 718. The
Black-Scholes value used for the stock options was $17.37 per share. The restricted stock value was based
on the closing price of $64.79 per share of MPC common stock on the grant date. The MPC performance
units have a grant date fair value of $0.83 per unit as calculated using a Monte Carlo valuation model.
Assumptions used in the calculation of these amounts are included in Note 23 to MPC’s financial statements
included in its Annual Report on Form 10-K for the year ended December 31, 2018. The phantom unit value
was based on the closing price of $34.89 per unit of MPLX common units on the grant date. See Item 8.
Financial Statements and Supplementary Data, Note 22 for assumptions used in the calculation of these
amounts. No total grant date fair value for the MPLX performance units has been determined under FASB
ASC Topic 718 because the MPLX Committee sets the DCF levels for these awards at the beginning of each
performance year; thus, the DCF levels for the second and third performance years have not yet been set.
This award was granted to Mr. Heminger as part of the correction of an erroneous 2018 payment of his
outstanding MPLX phantom unit awards, which was fully corrected in 2018 pursuant to applicable Internal
Revenue Service guidance. Mr. Heminger took no part in the decision to make the erroneous payment. The
correction restored him to the same economic position that he would have been in had the payment not
occurred.
(e)
207
OUTSTANDING EQUITY AWARDS AT 2018 FISCAL YEAR-END
The following table provides information regarding the outstanding equity awards held by our NEOs as of
December 31, 2018.
Option Awards (a)
Stock Awards
Number of
Securities
Underlying
Unexercised
Options
Exercisable
(#)
Number of
Securities
Underlying
Unexercised
Options
Unexercisable
(#)
Grant
Date
Option
Exercise
Price
($)
Option
Expiration
Date
Number of
Shares or
Units of
Stock That
Have Not
Vested (b)
(#)
Market
Value of
Shares or
Units of
Stock That
Have Not
Vested (c)
($)
Equity Incentive
Plan Awards:
Number of Unearned
Shares, Units or
Other Rights that
Have Not Vested (d)
(#)
Equity Incentive
Plan Awards:
Market or Payout
Value of Unearned
Shares, Units or
Other Rights that
Have Not Vested (e)
($)
MPLX
75,655
2,292,347
2,550,000
3,150,000
Name
Heminger
Beall
3/1/2016
11,368
5,684
34.63
3/1/2026
3/1/2017
1,592
3,184
50.99
3/1/2027
3/1/2018
—
8,636
64.79
3/1/2028
Hennigan
3/1/2018
12,960
17,504
MPLX
15,798
478,679
MPC
2,808
165,700
—
—
30,225
64.79
3/1/2028
30,225
MPLX 126,326
3,827,678
MPC
21,725
1,281,992
590,000
318,000
875,000
875,000
760,000
436,943
875,000
1,166,638
Floerke
3/1/2017
1,498
2,997
50.99
3/1/2027
3/1/2018
—
8,636
64.79
3/1/2028
1,498
11,633
MPLX
49,254
1,492,396
MPC
1,963
115,837
570,000
314,000
730,000
430,848
Swearingen
3/1/2017
4,681
9,364
50.99
3/1/2027
3/1/2018
—
8,636
64.79
3/1/2028
4,681
18,000
MPLX
12,807
388,052
MPC
2,852
168,297
500,000
450,000
625,000
638,085
(a) MPC stock options have a maximum term for exercise of ten years from the grant date. They generally
become exercisable in one-third increments on the first, second and third anniversaries of the grant date.
(b) Amounts reflect the number of unvested MPLX phantom units and shares of MPC restricted stock held on
December 31, 2018. Phantom units and restricted stock generally vest in one-third increments on the first,
second and third anniversaries of the grant date. MPC restricted stock and MPLX phantom unit awards to
our NEOs generally provide for full vesting upon termination of employment due to “Mandatory
Retirement,” which refers to MPC’s general policy that officers retire on the first day of the month after
they attain age 65. Mr. Heminger became eligible for Mandatory Retirement on October 1, 2018. Under
applicable tax rules, this eligibility for Mandatory Retirement caused him to “vest” in his phantom unit
awards for payroll tax purposes, notwithstanding that he continues to be employed, because on and after
such dates no substantial risk of forfeiture applies to 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 Stock Vested in 2018” table below.
208
Name
Heminger
Beall
Hennigan
Floerke
Swearingen
Grant Date
3/1/2016
3/1/2017
3/1/2018
12/20/2018
3/1/2016
3/1/2017
3/1/2018
7/1/2017
7/1/2017
3/1/2018
12/18/2015
3/1/2017
3/1/2018
3/1/2016
3/1/2017
3/1/2018
MPLX LP Phantom Units
MPC Restricted Stock
Number of
Unvested Units
Vesting Dates
Grant
Date
Number of
Unvested Shares
Vesting Dates
13,266
20,197
37,139
5,053
75,655
2,670
5,962
7,166
15,798
31,153
70,094
25,079
126,326
36,476
5,612
7,166
49,254
1,257
4,384
7,166
12,807
3/1/2019
3/1/2019, 3/1/2020
3/1/2019, 3/1/2020, 3/1/2020
3/1/2019, 3/1/2020, 3/1/2020
3/1/2019
3/1/2019, 3/1/2020
3/1/2019, 3/1/2020, 3/1/2020
3/1/2016
3/1/2017
3/1/2018
7/1/2019, 7/1/2020
7/1/2020
3/1/2019, 3/1/2020, 3/1/2020
7/1/2017
7/1/2017
3/1/2018
Upon termination without cause
3/1/2019, 3/1/2020
3/1/2019, 3/1/2020, 3/1/2020
3/1/2017
3/1/2018
3/1/2019
3/1/2019, 3/1/2020
3/1/2019, 3/1/2020, 3/1/2020
3/1/2017
3/1/2018
3/1/2019
3/1/2019, 3/1/2020
3/1/2019, 3/1/2020, 3/1/2020
7/1/2019, 7/1/2020
7/1/2020
3/1/2019, 3/1/2020, 3/1/2020
3/1/2019, 3/1/2020
3/1/2019, 3/1/2020, 3/1/2020
3/1/2019, 3/1/2020
3/1/2019, 3/1/2020, 3/1/2020
819
445
1,544
2,808
5,022
11,300
5,403
21,725
419
1,544
1,963
1,308
1,544
2,852
(c) Amounts reflect the aggregate value of all unvested MPLX LP phantom units and MPC restricted stock held on
December 31, 2018, using the MPLX closing unit price of $30.30 and the MPC closing stock price of $59.01 on
that date.
(d) Amounts reflect the number of unvested MPC and MPLX performance units held on December 31, 2018.
The MPLX performance unit grants awarded in 2017 and 2018 have a 36-month performance cycle and are
designed to settle 25% in MPLX common units and 75% in cash. Each performance unit is dollar
denominated with a target value of $1.00. Payout may vary from $0.00 to $2.00 per unit and will be
determined (i) 50% based on MPLX’s TUR as compared to the applicable peer group, which for 2017 and
2018 were: Andeavor Logistics LP, Buckeye Partners, L.P., Enbridge Energy Partners, L.P., Energy
Transfer Partners, L.P., 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 Gas Partners, LP and
Williams Partners L.P., (due to industry consolidations, Enbridge Energy Partners, L.P., Energy Transfer
Partners, L.P. and Williams Partners L.P. were removed from the group effective January 1, 2018) and (ii)
50% based on a DCF-per-MPLX-common-unit metric which measures the growth of MPLX’s full-year
DCF over the three-year performance cycle.
The MPC performance unit grants awarded in 2017 and 2018 have a 36-month performance cycle and are
designed to settle 25% in MPC common stock and 75% in cash. Each performance unit is dollar
denominated with 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, which for performance units granted in 2017 and
2018 was: Andeavor, Chevron Corporation, HollyFrontier Corporation, PBF Energy, Phillips 66, Valero
Energy Corporation and the S&P 500 Energy Index (due to MPC’s acquisition of Andeavor, it was removed
from the group effective January 1, 2018).
209
MPLX Performance Units
MPC Performance Units
Grant
Date
Number of Unvested
Units
Performance Period
Ending Date
Grant
Date
Number of
Unvested Units
Performance Period
Ending Date
Name
Heminger
Beall
3/1/2017
3/1/2018
3/1/2017
3/1/2018
Hennigan
3/1/2018
Floerke
Swearingen
3/1/2017
3/1/2018
3/1/2017
3/1/2018
1,200,000
1,350,000
2,550,000
340,000
250,000
590,000
875,000
875,000
320,000
250,000
570,000
250,000
250,000
500,000
12/31/2019
12/31/2020
12/31/2019
12/31/2020
3/1/2017
3/1/2018
12/31/2020
3/1/2018
12/31/2019
12/31/2020
3/1/2017
3/1/2018
12/31/2019
12/31/2020
3/1/2017
3/1/2018
68,000
250,000
318,000
875,000
875,000
64,000
250,000
314,000
200,000
250,000
450,000
12/31/2019
12/31/2020
12/31/2020
12/31/2019
12/31/2020
12/31/2019
12/31/2020
(e) Amounts for MPC reflect the aggregate value of all performance units held on December 31, 2018,
assuming a payout of $1.5238 per unit for the March 1, 2017 award and $1.3333 per unit for the March 1,
2018 award, which is the next higher performance achievement that exceeds the performance for these
grants’ performance period that ended December 31, 2018. Amounts shown for MPLX reflect the aggregate
value of all performance units held on December 31, 2018, assuming a payout of $1.5000 per unit for the
March 1, 2017 award and $1.0000 per unit for the March 1, 2018 award, which is the next higher
performance achievement that exceeds the performance for these grants’ performance period that ended
December 31, 2018.
OPTION EXERCISES AND UNITS VESTED IN 2018
The following table provides information regarding MPLX phantom units and MPC restricted stock that vested
in 2018.
Name
Heminger
Beall
Hennigan
Floerke
Swearingen
MPLX
MPLX
MPC
MPLX
MPC
MPLX
MPC
MPLX
MPC
Stock Awards
Number of Units/Shares Acquired on Vesting (a)
(#)
Value Realized on Vesting (b)
($)
31,969
5,996
1,932
15,576
2,511
11,630
20,070
3,693
3,086
1,097,278
207,821
125,310
528,961
175,268
383,857
1,197,470
127,999
200,158
(a) As discussed in footnote (b) to the “Outstanding Equity at 2018 Fiscal Year-End” table, during 2018, certain
awards held by Mr. Heminger vested for income tax and payroll tax (e.g., FICA taxes) purposes due to his
retirement eligibility under the applicable plans and agreements. Amounts in this column for Mr. Heminger
include 3,167 MPLX phantom units used to pay the associated taxes.
(b) Amounts reflect the actual pre-tax gain realized upon vesting of MPLX phantom units and MPC restricted
stock, which is the fair market value of the units or stock on the vesting date.
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POST-EMPLOYMENT BENEFITS FOR 2018
Pension Benefits
MPC provides tax-qualified retirement benefits to its employees, including our NEOs, under the Marathon
Petroleum Retirement Plan. In addition, MPC sponsors the Marathon Petroleum Excess Benefit Plan for the
benefit of a select group of management or highly compensated employees.
2018 Pension Benefits Table
The following table reflects the actuarial present value of accumulated benefits payable to our NEOs under the
Marathon Petroleum Retirement Plan and the defined benefit portion of the Marathon Petroleum Excess Benefit
Plan as of December 31, 2018. These values have been determined using actuarial assumptions consistent with
those used in MPC’s financial statements.
Plan Name
Number of Years of
Credited Service (a)
Present Value of
Accumulated
Benefit (b) ($)
Payments During
Last Fiscal
Year ($)
Name
Beall
Hennigan
Floerke
Marathon Petroleum Retirement Plan
Marathon Petroleum Excess Benefit Plan
16.67 years
16.67 years
835,035
1,654,435
Marathon Petroleum Retirement Plan
Marathon Petroleum Excess Benefit Plan
Marathon Petroleum Retirement Plan
Marathon Petroleum Excess Benefit Plan
1.58 years
1.58 years
3.0 years
3.0 years
48,425
230,263
69,532
165,218
Swearingen (c)
Marathon Petroleum Retirement Plan
Marathon Petroleum Excess Benefit Plan
37.58 years
37.58 years
1,388,855
2,283,521
—
—
—
—
—
—
—
—
(a) Represents the number of years the NEO has participated in the plan. However, plan participation service
(b)
used for the purpose of calculating each participant’s benefit under the Marathon Petroleum Retirement Plan
legacy final average pay formula was frozen as of December 31, 2009.
The present value of accumulated benefit for the Marathon Petroleum Retirement Plan was calculated
assuming a discount rate of 4.20%, the RP2000 mortality table for lump sums, a 96% lump sum election
rate and retirement at age 62 (or current age, if later). In accordance with the Marathon Petroleum
Retirement Plan provisions and actuarial assumptions, the discount rate for lump sum calculations varied
between 0.75% to 1.50% based on anticipated year of retirement.
(c) Dollar values for Mr. Swearingen reflect the portion of his compensation that was allocated to us for 2018
(75%).
Marathon Petroleum Retirement Plan
In general, our NEOs are immediately eligible to participate in the Marathon Petroleum Retirement Plan, which
is a tax-qualified defined benefit retirement plan that is primarily designed to provide participants with income
after retirement. Prior to January 1, 2010, the monthly benefit under the Marathon Petroleum Retirement Plan
was equal to the following formula:
[ 1.6% ×
Monthly
Final
Average
Pay
Years of
Participation] — [ 1.33% ×
×
Monthly Estimated
Primary Social
Security Benefit
(calculated as of
December 31, 2012)
×
Years of
Participation]
We refer to this formula as the Marathon legacy benefit formula. Effective January 1, 2010, the Marathon legacy
benefit formula was amended to (i) cease future accruals of additional years of participation, and (ii) as applied to
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eligible NEOs, cease further compensation updates. No more than 37.5 years of participation may be recognized
under the Marathon legacy benefit formula. Eligible earnings under the Marathon Petroleum Retirement Plan
include, but are not limited to, pay for hours worked, pay for allowed hours, military leave allowance,
commissions, 401(k) contributions to the Marathon Petroleum Thrift Plan and incentive compensation bonuses.
Age continues to be updated under the Marathon legacy benefit formula.
Benefit accruals for years beginning in 2010 are determined under a cash balance formula. Under the cash
balance formula, each year plan participants receive pay credits equal to a percentage of compensation based on
their plan points. Plan points equal the sum of a participant’s age and cash balance service:
•
•
•
Participants with less than 50 points receive a 7% pay credit;
Participants with at least 50 but less than 70 points receive a 9% pay credit; and
Participants with 70 or more points receive an 11% pay credit.
Participants in the Marathon Petroleum Retirement Plan become fully vested upon the completion of three years
of vesting service. Normal retirement age for both the Marathon legacy benefit and cash balance formulas is 65.
However, retirement-eligible participants are able to retire and receive an unreduced benefit under the Marathon
legacy benefit formula after reaching age 62.
The forms of benefit available under the Marathon Petroleum Retirement Plan 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 Marathon legacy benefit formula is reduced as follows:
Age at Retirement
Early Retirement Factor
61
56
62
100% 97% 94% 91% 87% 83% 79% 75% 71% 67% 63% 59% 55%
57
53
52
58
51
50
54
59
55
60
There are no early retirement subsidies under the cash balance formula. Of our NEOs providing a majority of
their services to our business, only Ms. Beall and Mr. Swearingen have accrued a benefit under the Marathon
legacy benefit formula. Ms. Beall and Mr. Swearingen are currently eligible for early retirement benefits under
the Marathon legacy benefit formula.
Under the cash balance formula, plan participants receive pay credits based on age and cash balance service. For
2018, Ms. Beall 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.
Marathon Petroleum Excess Benefit Plan (Defined Benefit Portion)
The Marathon Petroleum 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 Marathon Petroleum Retirement Plan were it not for Internal Revenue Code limitations. For our
NEOs, eligible earnings under this Plan include the items listed above, excluding bonuses, for the Marathon
Petroleum 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.
212
Marathon Petroleum Thrift Plan
The Marathon Petroleum 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 Thrift Plan. The purpose of
the Thrift Plan is to assist employees in maintaining a steady program of savings to supplement their retirement
income and to meet other financial needs.
The Thrift Plan allows eligible employees, such as our NEOs, to make elective deferral contributions to their
plan 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 ($275,000 for
2018). Employer matching contributions are made on such elective deferrals at a rate of 117% up to a maximum
of 6% of an employee’s plan-considered gross pay. All employee elective deferrals and all employer matching
contributions made are fully vested.
NONQUALIFIED DEFERRED COMPENSATION
The following table provides information regarding MPC’s nonqualified savings and deferred compensation
plans.
Name
Plan
Executive
Contributions
in Last Fiscal
Year
($)(a)
MPC
Contributions
in Last Fiscal
Year
($)(b)
Aggregate
Earnings in
Last Fiscal
Year
($)
Aggregate
Withdrawals/
Distributions
($)(c)
Aggregate
Balance at
Last Fiscal
Year-End
($)(c)
MPLX LP 2012 Incentive
Compensation Plan(d)
Marathon Petroleum Excess Benefit Plan
Marathon Petroleum Deferred
Compensation Plan
—
—
—
—
3,395
65,583
(28,037)
3,003,635
— 108,919
2,529,330
Marathon Petroleum Deferred
Compensation Plan
Marathon Petroleum Deferred
Compensation Plan
Swearingen(e) Marathon Petroleum Excess Benefit Plan
Marathon Petroleum Deferred
Compensation Plan
334,231
98,010
(77,818)
—
—
—
58,151
(13,536)
—
3,369
43,361
(14,807)
—
—
—
—
—
—
139,328
938,751
748,415
136,103
138,248
254,510
Heminger
Beall
Hennigan
Floerke
(a) Amounts shown are also included in the “Salary” and “Non-Equity Incentive Plan Compensation” columns
of the “2018 Summary Compensation Table.”
(b) Amounts shown are also included in the “All Other Compensation” column of the “2018 Summary
Compensation Table.”
(c) As discussed in footnote (b) to the “Outstanding Equity Awards at 2018 Fiscal Year-End” table, during
2018, certain awards held by Mr. Heminger vested for income tax and payroll tax (e.g., FICA taxes)
purposes due to his retirement eligibility under the applicable plans and agreements. 3,167 MPLX phantom
units were withheld for such taxes as of December 20, 2018. Using the average of the high and low MPLX
common unit prices on that date ($31.26), the taxes totaled $99,000. As of December 31, 2018,
Mr. Heminger had 75,655 vested, but as yet unpaid, MPLX phantom units.
(d) Amounts represent the value of Mr. Heminger’s MPLX phantom units and accrued distribution equivalents.
The Company Contributions amount is calculated using the average of the high and low MPLX common
unit prices on his October 1, 2018 ($35.24) and December 20, 2018 ($31.26) vesting dates. The Aggregate
Balance amount is calculated using the December 31, 2018 closing price of MPLX common units ($30.30).
(e) Amounts for Mr. Swearingen reflect the portion of his compensation that was allocated to us for 2018
(75%).
213
Marathon Petroleum 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 Marathon Petroleum Deferred Compensation Plan (described below), are eligible to
receive defined contribution accruals under the Marathon Petroleum Excess Benefit Plan. The defined
contribution formula in the Marathon Petroleum Excess Benefit Plan allows eligible employees to receive
employer matching contributions equal to the amount they would have otherwise received under the tax-qualified
Marathon Petroleum Thrift Plan were it not for Internal Revenue Code limitations.
Defined contribution accruals in the Marathon Petroleum Excess Benefit Plan are credited with interest equal to
that paid in the “Marathon Stable Value Fund” investment option of the Marathon Petroleum Thrift Plan. The
annual rate of return on this investment option for the year ended December 31, 2018, was 2.49%. All
distributions from the plan are paid in the form of a lump sum following the participant’s separation from
service.
Our NEOs no longer participate in the defined contribution formula of the Marathon Petroleum Excess Benefit
Plan; all nonqualified employer matching contributions for our NEOs now accrue under the Marathon Petroleum
Deferred Compensation Plan.
Marathon Petroleum Amended and Restated Deferred Compensation Plan
The Marathon Petroleum Amended and Restated Deferred Compensation Plan (referenced in the “Non-Qualified
Deferred Compensation” table above as the “Marathon Petroleum Deferred Compensation Plan”) is an unfunded
nonqualified deferred compensation plan maintained for the benefit of a select group of management or highly
compensated employees. The Plan provides participants, including our NEOs, the opportunity to supplement
their retirement savings by deferring up to 20% of their salary and bonus each year in a tax-advantaged
manner. Participant deferral elections are made in December of each year for amounts to be earned in the
following year and are irrevocable. Participants are fully vested in their deferrals under the Plan. The Plan credits
a matching contribution on a participant’s deferrals equal to the match percentage under the Marathon Petroleum
Thrift Plan, which is currently 117% of deferrals. The Plan also credits an amount to a participant equal to the
employer matching contributions the participant would have otherwise received under the Marathon Petroleum
Thrift Plan were it not for Internal Revenue Code limitations or any compensation limit imposed on deferrals
under the Thrift Plan. Participants are fully vested in these matching contributions under the Plan. Plan
participants may make notional investments of their notional Plan accounts from among certain of the investment
options offered to participants under the Marathon Petroleum Thrift Plan, and participants’ notional Plan
accounts are credited with notional earnings and losses based on the result of those investment elections. Plan
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
214
December 31, 2018, 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.
Name
Scenario
Heminger Retirement(g)
Resignation(g)
Involuntary Termination
without Cause or with Good
Reason
Involuntary Termination for
Cause
Change in Control with
Qualified Termination
Death
Beall
Retirement(g)
Resignation(g)
Involuntary Termination
without Cause or with Good
Reason
Involuntary Termination for
Cause
Change in Control with
Qualified Termination
Death
Hennigan Retirement(g)
Resignation(g)
Involuntary Termination
without Cause or with Good
Reason
Involuntary Termination for
Cause
Change in Control with
Qualified Termination
Death
Floerke
Retirement(g)
Resignation(g)
Involuntary Termination
without Cause or with Good
Reason
Involuntary Termination for
Cause
Change in Control with
Qualified Termination
Death
Swearingen Retirement(g)
Resignation(g)
Involuntary Termination
without Cause or with Good
Reason
Involuntary Termination for
Cause
Change in Control with
Qualified Termination
Death
Additional
Pension
Benefits(b)
($)
Accelerated
Options(c)
($)
Accelerated
Restricted
Stock(d)
($)
Accelerated
Performance
Units(e)
($)
Other
Benefits(f)
($)
Total
($)
Severance(a)
($)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2,292,347
—
2,550,000
—
— 4,842,347
—
—
—
—
—
—
—
—
—
—
—
2,292,347
—
2,550,000
—
—
— 4,842,347
— 164,112
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
164,112
—
—
—
3,200,806
—
2,394,185
164,112
— 164,112
644,379
644,379
908,000
908,000
46,085
7,357,567
— 1,716,491
—
—
—
—
5,100,000
—
—
—
—
—
3,375,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
24,036
24,036
75,099
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
5,109,670
5,109,670
1,750,000
1,750,000
54,950
12,014,620
— 6,859,670
—
1,105,223
1,105,223
—
—
—
—
—
—
—
— 1,105,223
— 1,105,223
—
—
1,608,233
1,608,233
884,000
884,000
51,332
5,942,601
— 2,516,269
—
—
—
—
—
—
—
—
—
—
—
—
75,099
—
—
—
3,375,000
—
6,834,165
—
75,099
75,099
556,349
556,349
950,000
950,000
45,890
11,836,503
— 1,581,448
(a) 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.
If the Qualified Termination occurs within three years prior to the date the officer reaches age 65, the NEO’s
215
(b)
benefit will be limited to a pro rata portion of the benefit. The NEO’s benefit is calculated using a fraction
equal to the number of full and partial months existing between the Qualifying Termination and the 65th
birthday divided by 36 months. As Mr. Heminger attained age 65 in September 2018, 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 “2018 Pension Benefits Table” above. Amounts in this
column represent additional pension benefits attributable solely to the final average pay formula in the
Executive Change in Control Severance Benefits Plan. 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 1.00% for NEOs who are
retirement eligible (taking into account the additional three years of age and service credit) and 1.00% 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. Health and welfare plans reflect the incremental cost of coverage under the
policy using the assumptions used for financial reporting purposes under generally accepted accounting
principles in the U.S. Only Mr. Swearingen and Ms. Beall are eligible for this enhanced benefit.
(c) Vesting of stock options is accelerated upon retirement or a change in control with a Qualified Termination.
Amounts shown reflect the value that would be realized if accelerated stock options were exercised on
December 31, 2018, taking into account the spread (if any) between the options’ exercise prices and the
closing price of MPC common stock on December 31, 2018 ($59.01).
(e)
(d) Vesting of restricted stock is accelerated upon a change in control with a Qualified Termination. Amounts
shown reflect the value that would be realized if MPC restricted stock and MPLX phantom unit awards
vested on December 31, 2018, taking into account the closing price of MPC common stock ($59.01) and
MPLX LP common units ($30.30) on December 31, 2018. 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.
In the event of a change in control and a Qualified Termination, unvested 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.
Amounts shown reflect the MPC and MPLX performance unit target vesting amounts that would be payable
in the event of a change in control with each performance unit having a target value of $1.00.
Includes 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 certain of our NEOs in the following amounts: Ms. Beall,
$1.05 million; Mr. Hennigan, $1.6 million; Mr. Floerke, $0.9 million; Mr. Swearingen, $1 million.
(g) Messrs. Heminger and Swearingen and Ms. Beall are currently eligible to retire under MPC’s retirement
(f)
plan; thus, amounts shown for them reflect retirement rather than resignation. Messrs. Hennigan and Floerke
were not eligible to retire as of December 31, 2018; thus, amounts shown for them reflect the compensation
they would receive upon their voluntary resignation.
Change in Control Plans
Our NEOs participate in two change-in-control severance plans: the Marathon Petroleum Corporation Amended
and Restated Executive Change in Control Severance Benefits Plan (“MPC CIC Plan”) and the MPLX LP
Executive Change in Control Severance Benefits Plan (“MPLX CIC Plan”). While our NEOs participate in both
plans, they are not entitled to receive benefits under both plans as a result of the same change-in-control event;
rather, in the event of a change in control under both plans, our NEOs would receive the greater of the benefits
provided by the plans. The plans are designed to pay benefits only upon a change in control and a Qualified
Termination. A Qualified Termination generally occurs when an NEO separates from service from our affiliates
or us in connection with, or within two years after, a change in control unless such separation is:
•
•
due to death or disability;
for cause;
216
•
•
voluntary, unless the NEO has good reason (defined as a reduction in the NEO’s roles, responsibilities, pay
or benefits, or the NEO being required to relocate more than 50 miles from his or her current location); or
on or after the date the NEO attains age 65.
MPC CIC Plan
Upon a change in control of MPC and a Qualified Termination, each NEO is eligible to receive:
•
•
•
•
•
•
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;
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 that would be 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);
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; and
accelerated vesting of all outstanding MPC LTI awards.
MPLX CIC Plan
Upon a change in control of MPLX and a Qualified Termination, each NEO is eligible to receive:
•
•
•
•
•
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 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 that would be 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; and
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.
NEOs who receive an offer for comparable employment from an acquirer or successor entity in the change in
control will not be eligible to receive benefits under the MPLX CIC Plan.
217
The MPLX CIC Plan also provides that NEOs who incur a Qualified Termination in connection with a change in
control of MPLX or who separate from service with MPLX as a result of the change-in-control transaction (i.e.,
where the NEO remains employed with MPC but no longer provides services to MPLX) will become fully vested
in all outstanding MPLX LTI awards. 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, if an NEO incurs a Qualified
Termination, the NEO will become fully vested in all outstanding MPC LTI awards, provided that performance-
based awards remain subject to the attainment of the applicable performance goals at the end of the performance
cycle.
Retirement
MPC’s employees, including our NEOs, 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, 2018, Messrs. Heminger and
Swearingen and Ms. Beall 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 “Pension Benefits” and “Nonqualified Deferred Compensation.”
In addition, upon retirement, unvested MPC stock options held by our NEOs become exercisable according to the
grant terms. Unvested MPC restricted stock awards and MPLX phantom units are forfeited upon retirement
(except in the case of a mandatory retirement at age 65, at which time they vest in full). For performance units, if
an NEO has worked more than nine months of the performance cycle, awards may be vested on a prorated basis
at the discretion of the MPLX Committee (the MPC Compensation Committee, in the case of MPC performance
units). If an NEO retires under MPC’s mandatory retirement policy, outstanding performance units will fully
vest; however, payout will occur at the end of the full 36-month performance cycle based on the certified results
of the performance cycle.
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 a severance between
eight and 62 weeks of salary based either on service or level of base salary. Such payments are at the discretion
of MPC’s Compensation Committee.
Upon voluntary termination of employment by an NEO, or involuntary termination for cause, LTI awards,
including vested but unexercised MPC 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 the termination date.
Death or Disability
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. In the
event of disability, LTI awards continue to vest as if the NEO remained employed for up to 24 months during the
period of disability.
218
CEO PAY RATIO
We do not determine the total compensation of our chief executive officer 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 chief executive officer.
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 2018:
Role
Lead Director
Audit Committee Chair
Conflicts Committee Chair
Other Committee Chair
All Other Directors
Deferred
Phantom
Unit Equity
Award
($)
87,500
87,500
87,500
87,500
87,500
Cash
Retainer
($)
87,500
87,500
87,500
87,500
87,500
Lead Director
Retainer
($)
Committee
Chair
Retainer
($)
Total
($)
15,000
—
—
—
—
15,000
15,000
7,500
— 190,000
190,000
190,000
182,500
— 175,000
Cash retainer, lead director and committee chair fees are paid in cash in equal quarterly installments at the
beginning of each calendar quarter. 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.
Phantom unit awards are granted in equal quarterly installments at the beginning of each calendar quarter. They
are not subject to any risk of forfeiture once granted and are automatically deferred until departure from the
Board, at which time they are settled in common units.
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 $10,000 in a given year.
We indemnify our directors for any actions associated with being a director to the fullest extent permitted under
Delaware law, and reimburse them for all expenses incurred while serving as a director.
219
2019 Program Changes
In October 2018, following a presentation and discussion with Pay Governance, LLC, our CEO and Chairman
recommended, and the Board determined, to make certain changes to the non-employee director compensation
program to more closely align with market data. The following table shows the changes in compensation,
effective January 1, 2019.
Compensation Component
Cash Retainer
Deferred Phantom Unit Equity Award
Lead Director Retainer
Audit Committee Chair Retainer
Conflicts Committee Chair Retainer
MLP Representative MPC Board Observer Retainer
2018 Director Compensation Table
2018
($)
87,500
87,500
15,000
15,000
15,000
—
2019
($)
90,000
110,000
15,000
15,000
15,000
62,500
The following table shows compensation earned by or paid to our non-employee directors during 2018.
Name
Michael L. Beatty
David A. Daberko(c)
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
Frank M. Semple(d)
J. Michael Stice(e)
John P. Surma
Fees
Earned or
Paid in Cash
($)
Unit Awards (a)
($)
All Other
Compensation (b)
($)
87,500
27,885
102,500
102,500
102,500
103,125
59,856
87,500
87,500
27,885
87,500
87,500
87,500
87,500
59,856
87,500
10,000
—
—
1,000
10,000
—
—
—
Total
($)
185,000
55,770
190,000
191,000
200,000
190,625
119,712
175,000
(a) Amounts reflect the aggregate grant date fair value of phantom units, calculated in accordance FASB ASC
Topic 718. Non-employee directors generally received quarterly grants of phantom units with a grant date
fair value of $21,875. Mr. Daberko’s quarterly grant was prorated for the second quarter due to his
retirement, resulting in a grant date fair value for that award of $6,010. Mr. Stice joined our board during the
second quarter and received a prorated award of phantom units with a grant date fair value of $16,106. All
phantom units are deferred until departure from the Board, and distribution equivalents in the form of
additional phantom unit awards are credited to each director’s deferred account as and when distributions
are paid. The aggregate number of phantom units in respect of Board service outstanding for each
non-employee director as of December 31, 2018 is: Messrs. Helms, Sandman, and Surma, 14,048;
Mr. Peiffer, 11,222; Mr. Beatty, 8,352; Mr. Semple, 5,845; and Mr. Stice, 1,777.
(b) Reflects contributions made to educational institutions under MPC’s matching gifts program.
(c) Mr. Daberko retired from the Board effective April 25, 2018. Following his retirement, in July 2018,
Mr. Daberko received a distribution of MPLX common units related to his Board service from his deferred
equity account valued at $399,868, and cash in lieu of a fractional MPLX common unit in the amount of $5.
(d) Mr. Semple was appointed as our Representative Observer to attend certain MPC Board and committee
meetings, a role in which he acts as a liaison between the MPC Board and us, effective October 1, 2018;
accordingly, his fees reflect the prorated retainer he received for his service during that period.
(e) Mr. Stice was elected to the Board effective April 25, 2018.
220
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
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, 2018:
Name and Address
of Beneficial Owner
Marathon Petroleum Corporation(b)
539 S. Main Street
Findlay, Ohio 45840
Number of
Common Units
Representing
Limited Partner
Interests
504,701,934
Percent of
Common Units
Representing
Limited Partner
Interests (a)
63.6%
(a) Based on 794,158,848 common units representing limited partner interests (“MPLX LP common units”)
(b)
outstanding on February 15, 2019.
The 504,701,934 MPLX LP common units are directly held by MPLX Logistics Holdings LLC, MPC
Investment LLC and MPLX GP LLC. Marathon Petroleum Corporation (“MPC”) is the ultimate parent
company of MPLX Logistics Holdings LLC, MPC Investment LLC and MPLX GP LLC and may be
deemed to beneficially own the MPLX LP common units directly held by these entities. MPC Investment
LLC owns all of the membership interests in MPLX GP LLC and MPLX Logistics Holdings LLC, and MPC
owns all of the membership interests in MPC Investment LLC.
221
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, 2019, except as otherwise noted, 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, 2019, there were 794,105,445 MPLX common units outstanding
(including 504,701,934 common units held by MPC and its affiliates) and 676,152,130 shares of MPC common
stock outstanding.
Name of Beneficial Owner MPLX Common Units
Amount and Nature of Beneficial Ownership
Percent of Total
Outstanding (%)
MPC Common Stock MPLX MPC
Pamela K.M. Beall
Michael L. Beatty
Gregory S. Floerke
Gregory J. Goff
Timothy T. Griffith
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 (17 individuals)
35,955(a)
36,618(b)
77,217(a)
11,953(c)
30,438(a)
25,943(b)
239,270(d)(e)
135,396(a)
43,814(b)(e)
58,943(b)
583,940(b)(c)(e)
4,370(b)(e)
25,300(b)
20,284(a)
89,522(a)(c)
125,226(f)
—
20,052(f)
2,035,418(c)(f)(g)
280,749(f)
—
3,065,847(f)(h)
33,502(f)
63,394(h)
—
4,707(i)
4,837(i)
43,410(h)(i)
221,792(f)
581,422(f)
1,447,414(a)
6,568,250(f)
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
(a)
(b)
(c)
(d)
(e)
(f)
(g)
Less than 1% of common units or common shares outstanding, as applicable.
Includes phantom unit awards, which may be forfeited under certain conditions, as follows: Ms. Beall,
15,798; Mr. Floerke, 49,254; Mr. Griffith, 14,923; Mr. Hennigan, 126,326; Mr. Swearingen, 12,807;
Mr. Templin, 41,931; all other executive officers, 22,882.
Includes phantom unit awards, which settle in common units upon a director’s retirement from service on
the Board, as follows: Mr. Beatty, 9,248; Mr. Helms, 14,943; Mr. Peiffer, 12,117; Mr. Sandman, 14,943;
Mr. Semple, 7,646; Mr. Stice, 3,670; Mr. Surma, 17,800.
Includes shares of common stock or common units, as applicable, held by or with spouse, with spouse as
co-trustee, or by trust for the benefit of spouse.
Includes 75,655 phantom unit awards, which are fully vested and will settle in common units at the end of
the applicable performance period.
Includes common units indirectly beneficially held in trust as follows: Mr. Heminger, 131,915; Mr. Peiffer,
31,697; Mr. Semple, 527,517; Mr. Stice, 700.
Includes all stock options exercisable within 60 days of January 31, 2019 as follows: Ms. Beall, 83,440;
Mr. Floerke, 5,874; Mr. Goff, 283,329; Mr. Griffith, 233,800; Mr. Heminger, 2,498,655; Mr. Hennigan,
10,075; Mr. Swearingen, 172,834; Mr. Templin, 495,395; all other executive officers, 72,244.
Includes (i) 483,554 restricted stock units converted from previously outstanding Andeavor awards, a
portion of which may be forfeited under certain conditions, (ii) 226,383 shares held by G Goff Foundation
Inc., for which Mr. Goff acts as trustee with shared voting and investment power, and (iii) 38,875 shares
held in trust for which Mr. Goff acts as trustee with shared voting and investment power.
222
(h)
(i)
Includes shares of common stock indirectly beneficially held in trust as follows: Mr. Heminger, 206,202;
Mr. Peiffer, 63,394; Mr. Surma, 10,000.
Includes restricted stock unit awards, which vest upon the director’s retirement from service on the MPC
Board or observer status, as follows: Mr. Semple, 4,707; Mr. Stice, 4,837; Mr. Surma, 33,410.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 2018, 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(1)
1,372,439
—
1,372,439
Weighted
average
exercise
price of
outstanding
options,
warrants
and
rights(2)
N/A
—
Number of
securities
remaining
available for
future
issuance
under equity
compensation
plans (excluding
securities
reflected in the
first column)(3)
15,743,356
—
15,743,356
Plan category
Equity compensation plans approved by security holders
Equity compensation plans not approved by security holders
Total
(1)
Includes the following:
(a)
(b)
1,154,336 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, 2018.
218,103 units as the maximum potential number of common units that could be issued in settlement of
performance units outstanding as of December 31, 2018, pursuant to the MPLX 2012 Plan and the
MPLX 2018 Plan based on the closing price of our common units on December 31, 2018, of $30.30 per
unit. The number of units reported for this award vehicle may overstate dilution. See Item 8. Financial
Statements and Supplementary Data—Note 22 for more information on performance unit awards
granted under the MPLX 2012 Plan and the MPLX 2018 Plan.
(2)
There is no exercise price associated with phantom unit awards.
(3) Reflects the common units available for issuance pursuant to the MPLX 2018 Plan. The number of units
reported in this column assumes 2,393 as the maximum potential number of common units that could be
issued in settlement of performance units outstanding as of December 31, 2018, pursuant to the MPLX 2018
Plan based on the closing price of our common units on December 31, 2018, of $30.30 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 22 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
Our Board has adopted a formal written related person transactions policy to establish procedures for the
notification, review, approval, ratification and disclosure of related person transactions. This policy is available
on our website at www.mplx.com under the heading “Investors” and the subheading “Corporate Governance.”
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
223
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 following transactions, arrangements or
relationships, however, have the Board’s standing pre-approval:
•
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 that is identified prior to its consummation will be consummated only if the Board
approves it in advance. 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.
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;
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.
The related person transactions policy described above was adopted after the closing of the Initial Offering and,
as a result, the transactions and arrangements with MPC described above that were entered into prior to the
closing of the Initial Offering were not reviewed under such policy, but were approved by the Board.
Our Relationship with MPC
As of February 15, 2019, MPC owned through its affiliates 504,701,934 of our common units, representing
approximately 64% 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, Mr. Heminger is Chairman
of the Board and Chief Executive Officer of MPC, and Messrs. Griffith, Templin and Goff serve as officers 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 2018.
Acquisition and Restructuring Transactions
On February 1, 2018, pursuant to a Membership Interests Contribution Agreement entered into on November 13,
2017 by MPLX GP, MPLX, MPC Investment, and certain of their affiliates, MPC Investment contributed the
membership interests in MPLX Fuels Distribution LLC and MPLX Refining Logistics LLC through a series of
intercompany contributions to us for $4.1 billion in cash, 111,611,111 of our common units and 2,277,778 of our
general partner units.
224
On February 1, 2018, pursuant to a Partnership Interests Restructuring Agreement we entered into on
December 15, 2017 with MPLX GP, MPLX GP cancelled its incentive distribution rights in us and converted its
2% general partner interest in us into a non-economic general partner interest, in exchange for 275,000,000 of
our common units. MPC agreed to waive approximately one-third of the first quarter 2018 distributions on the
common units issued in connection with this transaction.
Distributions and Reimbursements to MPC
Pursuant to our Partnership Agreement, we make cash distributions to our unitholders, including MPC. During
2018, we distributed approximately $1,097 million with respect to MPC’s limited partner interest and $0 million
with respect to MPC’s 2% general partner interest. As of February 1, 2018, MPC’s 2% general partner interest
was converted into a non-economic general 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 2018 was $3 million.
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, an omnibus agreement, 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.
Auditor Fees
Following are the aggregate fees for professional services provided to us by PricewaterhouseCoopers LLP for the
years ended December 31, 2018, and December 31, 2017:
(In thousands)
Audit
Audit-Related
Tax
All Other
Total
2018
2017
$
$
$
3,617
163
989
6
4,775
$
3,806
469
1,081
2
5,358
Audit fees for the years ended December 31, 2018, and December 31, 2017, were 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.
225
Audit-Related fees for the year ended December 31, 2018 and December 31, 2017, 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, 2018, and December 31, 2017, 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, 2018, and December 31, 2017, 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.
Pursuant to the policy, the Audit Committee has delegated pre-approval authority of up to $250,000 to the Chair
of the Audit Committee for unbudgeted items, and the Chair reports the items pre-approved pursuant to this
delegation to the full Audit Committee at the next scheduled meeting.
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.
226
Exhibits:
Exhibit
Number
1.1
2.1
2.2
2.3 †
2.4
2.5
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
8-K
2.1
11/17/2015 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
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
227
Exhibit
Number
2.6
2.7
2.8
2.9
3.1
3.2
3.3
4.1
4.2
4.3
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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
Certificate of Limited Partnership of
MPLX LP
Amendment to the Certificate of
Limited Partnership of MPLX LP
Fourth Amended and Restated
Agreement of Limited Partnership of
MPLX LP, dated as of February 1,
2018
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)
Second 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)
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
S-1
3.1
7/2/2012 333-182500
S-1/A
3.2
10/9/2012 333-182500
8-K
3.1
2/2/2018
001-35714
8-K
4.1
2/12/2015
001-35714
8-K
4.2
2/12/2015
001-35714
8-K
4.2
12/22/2015
001-35714
228
Exhibit
Number
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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
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
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
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
229
Exhibit
Number
4.13
4.14
4.15
4.16
10.1*
10.2
10.3
10.4
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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
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)
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
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
8-K
4.4
2/8/2018
001-35714
8-K
4.5
2/8/2018
001-35714
8-K
4.1
11/15/2018
001-35714
8-K
4.2
11/15/2018
001-35714
S-1/A 10.3
10/9/2012 333-182500
8-K 10.1
11/6/2012
001-35714
8-K 10.2
11/6/2012
001-35714
S-1/A 10.6
10/9/2012 333-182500
230
Exhibit
Number
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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
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
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)
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)
231
Exhibit
Number
10.14
10.15
10.16
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
(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
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
10.4 11/6/2012 001-35714
8-K
10.5 11/6/2012 001-35714
8-K
10.6 11/6/2012 001-35714
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
232
Exhibit
Number
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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
10.25
10.26
10.27
10.28
10.29
10.30*
10.31*
10.32*
10.33
Restated Non-Management Director
Compensation Policy and Equity
Award Terms
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
Loan Agreement, by and between
MPLX LP and MPC Investment
LLC, dated December 4, 2015
Letter Agreement, by and between
Marathon Petroleum Corporation and
Paula L. Rosson, dated October 6,
2015
Retention Agreement, by and
between Marathon Petroleum
Company LP and Greg S. Floerke,
dated September 14, 2015
Retention Agreement, by and
between Marathon Petroleum
Company LP and C. Corwin
Bromley, dated September 14, 2015
Employee Services Agreement, dated
December 28, 2015, by and between
MPLX LP and MW Logistics
Services LLC
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 12/10/2015 001-35714
8-K
10.4 12/10/2015 001-35714
10-K 10.41
2/26/2016 001-35714
10-K 10.42
2/26/2016 001-35714
8-K
10.1
1/4/2016 001-35714
233
Exhibit
Number
10.34*
10.35+
10.36
10.37
10.38
10.39
10.40*
10.41*
10.42*
10.43*
10.44
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Executive Employment Agreement
effective September 5, 2007 between
MarkWest Hydrocarbon, Inc. and
Frank Semple
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
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
8-K
10.1 9/11/2007 001-31239
10-K 10.48 2/26/2016 001-35714
8-K
10.1
4/6/2016 001-35714
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
234
Exhibit
Number
10.45
10.46
10.47
10.48
10.49
10.50
10.51
10.52
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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.
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
8-K
10.1
9/6/2016 001-35714
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
235
Exhibit
Number
10.53
10.54
10.55
10.56
10.57
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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
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
10.58*
Form of MPLX LP Phantom Unit
Award Agreement—Officer, Cliff
Vesting
10-Q 10.1
8/3/2017 001-35714
236
Exhibit
Number
10.59
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
8-K 10.1
7/27/2017 001-35714
Credit Agreement, dated as of
July 21, 2017, among MPLX LP, as
borrower, Wells Fargo Bank,
National Association, as
administrative agent, each of Wells
Fargo Securities, LLC, JPMorgan
Chase Bank, N.A., Barclays Bank
PLC, Citigroup Global Markets Inc.,
Merrill Lynch, Pierce, Fenner &
Smith Incorporated, Mizuho Bank,
Ltd., The Bank of Tokyo-Mitsubishi
UFJ, Ltd. and RBC Capital Markets,
as joint lead arrangers and joint
bookrunners, JPMorgan Chase Bank,
N.A., as syndication agent, each of
Bank of America, N.A., Barclays
Bank PLC, Citigroup Global Markets
Inc., Mizuho Bank, Ltd., The Bank of
Tokyo-Mitsubishi UFJ, Ltd., and
Royal Bank of Canada, as
documentation agents, and the other
lenders and issuing banks that are
parties thereto.
10.60*
Amended Restricted Stock Award
Agreement
10.61* MPLX LP Executive Change in
Control Severance Benefits Plan
10.62
10.63
10.64
Transportation Services Agreement,
dated November 1, 2017, between
Marathon Pipe Line LLC and
Marathon Petroleum Company LP
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
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
8-K 10.2
11/7/2017 001-35714
8-K 10.1
12/19/2017 001-35714
237
Exhibit
Number
10.65
10.66+
10.67+
10.68
10.69+
10.70
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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.
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
10.1
1/4/2018 001-35714
8-K
10.1
2/2/2018 001-35714
8-K
10.2
2/2/2018 001-35714
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
10.71* MPLX LP 2018 Incentive
8-K
10.1
3/5/2018 001-35714
Compensation Plan
238
Exhibit
Number
10.72*
10.73*
10.74*
10.75*
10.76*
10.77*
Exhibit Description
Form
Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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
10-K
14.1 2/24/2017
10.78* MPLX LP 2018 Incentive
Compensation Plan MPC
Non-Employee Director Phantom Unit
Award Policy
10.79* MPLX GP LLC Amended and
Restated Non-Management Director
Compensation Policy and Director
Equity Award Terms
Code of Ethics for Senior Financial
Officers
List of Subsidiaries
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
14.1
21.1
23.1
24.1
31.1
31.2
32.1
32.2
101.INS XBRL Instance Document
101.SCH XBRL Taxonomy Extension Schema
239
X
X
X
X
X
X
X
X
X
X
X
Exhibit
Number
Exhibit Description
Form
Exhibit
Filing
Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
101.PRE XBRL Taxonomy Extension Presentation
Linkbase
101.CAL XBRL Taxonomy Extension Calculation
Linkbase
101.DEF XBRL Taxonomy Extension Definition
Linkbase
101.LAB XBRL Taxonomy Extension Label Linkbase
X
X
X
X
†
*
+
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.
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.
240
Item 16. Form 10-K Summary
Not applicable.
241
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, 2019
MPLX LP
By: MPLX GP LLC
Its general partner
By: /s/ C. Kristopher Hagedorn
C. Kristopher Hagedorn
Vice President and Controller of MPLX GP LLC
(the general partner of MPLX LP)
242
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on February 28, 2019 on behalf of the registrant and in the capacities indicated.
Signature
/s/ Gary R. Heminger
Gary R. Heminger
/s/ Pamela K.M. Beall
Pamela K.M. Beall
/s/ C. Kristopher Hagedorn
C. Kristopher Hagedorn
*
Michael J. Hennigan
*
Michael L. Beatty
*
Gregory James Goff
*
Timothy T. Griffith
*
Christopher A. Helms
*
Garry L. Peiffer
*
Dan D. Sandman
*
Frank M. Semple
*
J. Michael Stice
*
John P. Surma
*
Donald C. Templin
Title
Chairman of the Board of Directors 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)
Director and President 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)
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/ Gary R. Heminger
Gary R. Heminger
Attorney-in-Fact
February 28, 2019
243
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TABLE OF CONTENTS
1 LETTER TO OUR
UNITHOLDERS
2
4
5
6
8
9
STRATEGIC VISION
LOGISTICS AND STORAGE
GATHERING AND
PROCESSING
FINANCIAL AND OPERATIONAL
HIGHLIGHTS
BOARD OF DIRECTORS
COMPANY OFFICERS
10
RECONCILIATION DATA
Front cover: MPLX dock facility in Garyville, Louisiana
Inside cover: Sherwood complex in West Virginia
MPLX | 2018 ANNUAL REPORT
COMPANY INFORMATION
Headquarters
200 East Hardin St.
Findlay, OH 45840
(419) 421-2414
MPLX LP Website: www.MPLX.com
Investor Relations Office
539 South Main St.
Findlay, OH 45840
MPLXInvestorRelations@marathonpetroleum.com
Kristina Kazarian,
Vice President, Investor Relations
(419) 421-2071
Independent Accountants
PricewaterhouseCoopers LLP
406 Washington St., Suite 200
Toledo, OH 43604
Stock Exchange Listing
New York Stock Exchange
Common Unit Symbol
MPLX
Principal Unit Transfer Agent
ComputershareShareholder correspondence
should be mailed to:
P.O. Box 505000
Louisville, KY 40233-5000
Overnight correspondence should
be mailed to:
462 South 4th Street, 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 2018 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
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2018 ANNUAL REPORT
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MPLX LP
200 East Hardin St.
Findlay, OH 45840
®
Non-GAAP Financial Measures
Adjusted EBITDA, distributable cash flow (DCF), distribution coverage
ratio and leverage ratio are non-GAAP financial measures provided
in this presentation. Adjusted EBITDA and DCF reconciliations to the
nearest GAAP financial measure are included on Pages 10-11 and in
the MPLX Annual Report on Form 10-K for the year ended Dec. 31,
2018, 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. Leverage ratio is consolidated debt to last 12 months pro
forma adjusted EBITDA. These non-GAAP financial measures 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.
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. In accordance with “safe harbor”
provisions of the Private Securities Litigation Reform Act of 1995,
we have included in our attached Form 10-K for the year ended
Dec. 31, 2018, 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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