®
2017
ANNUAL REPORT
58281.indd 1
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Cover: An MPLX marine
vessel, acquired in 2016
as part of a dropdown
transaction with MPC,
loads at MPLX dock
facilities on the Mississippi
River at Wood River, Illinois
MPLX operations as of Dec. 31, 2017
Table of Contents
Chairman and CEO Letter
Logistics and Storage
Gathering and Processing
Board of Directors
Company Offi cers
Financial and Operational Highlights
1
3
4
6
7
8
$1,628
2017
$1,140
2016
Distributable cash flow attributable to MPLX (in millions).
See Reconciliation Data on Page 9.
Glossary of Terms
bbl: barrels
bcf/d: billion cubic feet per day
bpd: barrels per day
cf/d: cubic feet per day
EBITDA: earnings before interest, taxes, depreciation
and amortization
GP: general partner
IPO: initial public offering of units
LP: limited partner
MarkWest: MarkWest Energy Partners, L.P., is a wholly
owned subsidiary of MPLX LP acquired in December 2015
mbpd: thousand barrels per day
MLP: master limited partnership
mmcf/d: million cubic feet per day
MPC: Marathon Petroleum Corporation
MPL: Marathon Pipe Line LLC
NGL: Natural gas liquids
MPLX Terminals: Owned and Part-owned
Barge Dock
Cavern
MPLX Pipelines: Owned & Operated
MPLX Interest Pipelines: Operated by Others
MPLX Operated Pipelines: Owned by Others
MarkWest Complex
Marine Repair Facility
MPC Refi neries
58281.indd 2
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MPLX I 2017 ANNUAL REPORT I 1
FROM THE CHAIRMAN AND CEO
Fellow unitholders,
MPLX delivered strong performance in 2017, including record fi nancial and operational results.
We gathered, processed and fractionated record gas and NGL volumes, and more than tripled
our net income to $794 million for the year. Our adjusted earnings before interest, taxes,
depreciation and amortization (EBITDA) increased $585 million, to more than $2 billion, and
our full-year distributable cash fl ow exceeded $1.6 billion.
We delivered distribution growth of
12.1 percent and affi rmed a 2018
distribution growth target of 10 percent.
Since our IPO in 2012, we have achieved
20 consecutive quarters of increased
cash distributions for our unitholders,
representing a compound annual growth
rate of 18.3 percent over the minimum
quarterly distribution established when
we formed MPLX.
During our fi ve years as a publicly traded
partnership, we have transformed our
asset base and earnings profi le. In late
2015, we expanded into the midstream
natural gas business with the addition
of MarkWest. And early last year, we
announced a strategic action plan to
enhance unitholder value, which we
completed on Feb. 1, 2018.
As part of these strategic actions, we
acquired assets and services from
our sponsor, Marathon Petroleum
Corporation, that are projected to generate
approximately $1.4 billion in annual
EBITDA. MPC also exchanged its general
partner economic interest in MPLX, including
incentive distribution rights, for newly
issued MPLX common units.
2017 Success by the Numbers
In millions, except per unit and ratio data
2017
2016
Net income attributable to MPLX (a)
$ 794
$ 233
Adjusted EBITDA attributable to MPLX (b)
Net cash provided by operating activities
Distributable cash fl ow (DCF) (b)
Distribution per common unit (c)
Distribution coverage ratio (d)
Growth capital expenditures (e)
2,004
1,907
1,628
2.2975
1.28x
1,518
1,419
1,491
1,140
2.05
1.23x
1,292
(a) The year ended Dec. 31, 2016, includes pretax, non-cash impairments of $89 million related to an
equity method investment and $130 million related to the goodwill established in connection with
the MarkWest acquisition.
(b) Non-GAAP measure calculated before the distribution to preferred units and excluding impair-
ment charges. See Reconciliation Data on Page 9.
(c) Distributions declared by the board of directors of our general partner.
(d) See description in Non-GAAP Financial Measures on back cover.
(e) Excludes non-affi liated joint-venture (JV) members’ share of Capital Expenditures. See Capital
Expenditures table on Page 10.
58281.indd 3
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MPLX I 2017 ANNUAL REPORT I 2
FROM THE CHAIRMAN AND CEO
These transactions have nearly doubled the partnership’s earnings base, improved our cost of capital,
and added high-quality, fee-based revenue streams that further diversify our earnings.
In 2017, we also welcomed Mike Hennigan to the MPLX executive team as president. With 35 years in the
energy industry, Mike brings a tremendous depth of experience to the partnership. We have benefi ted
greatly from his skill and vision, and we are fortunate to have his expertise as we continue to grow.
We are enthusiastic about the future of MPLX. We are now one of the largest diversifi ed master limited
partnerships in the energy sector. We have a robust portfolio of organic projects in some of the most
prolifi c and economic shale plays in the nation, and a high-quality suite of transportation and storage
assets. Along with our ongoing commitment to maintain a strong balance sheet and an investment-
grade credit profi le, these factors position us to deliver long-term, sustainable growth for our investors.
Sincerely,
Gary R. Heminger
Chairman and Chief Executive Offi cer
Below:
Dock facilities at MPC’s
Galveston Bay refi nery
expanding
export capacity
58281.indd 4
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LOGISTICS & STORAGE
MPLX I 2017 ANNUAL REPORT I 3
In 2017, MPLX’s Logistics and Storage segment, which generates stable cash fl ows with its fee-
based revenues, reported segment operating income of $782 million.
During the year, the Logistics and Storage segment continued executing its long-term strategy to
expand crude oil and refi ned products infrastructure, acquiring the Ozark Pipeline; purchasing an
indirect equity interest in the Bakken Pipeline system; fully commissioning the Utica Build-Out
projects, including the Harpster-to-Lima Pipeline; and beginning the expansion of the Ozark and
Wood River-to-Patoka pipeline systems, which connect Cushing, Oklahoma, to Patoka, Illinois.
Additionally, through the strategic actions executed with our sponsor, MPC, completed in
February 2018, the partnership acquired terminals, pipelines and storage assets in March; joint-
interest ownership in certain pipeline and storage assets in September; and, in a transaction that
closed on Feb. 1, 2018, fuels distribution services and refi ning logistics assets. Combined, these
additional assets and services are projected to generate approximately $1.4 billion in annual
EBITDA, transforming the segment and the partnership.
Bottom right:
Laying the Harpster-
to-Lima Pipeline
MPLX continues to expand the logistics and storage services it provides to MPC, including butane
caverns and tank farms. And with the acquisition of docks supporting MPC’s operations, it plans to
continue the export-capacity expansion project already underway at the Galveston Bay refi nery.
58281.indd 5
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MPLX I 2017 ANNUAL REPORT I 4
GATHERING & PROCESSING
MPLX’s Gathering and Processing segment delivered strong volume growth in 2017 and continues to
provide exceptional organic growth opportunities, with a robust portfolio of organic projects in the
Marcellus, Utica, Permian and STACK (Sooner Trend of the Anadarko Basin Canadian and Kingfi sher
counties), which are among the most prolifi c and economic shale plays in the country.
We achieved record volumes, including increases of 10 percent in gathering throughput, 12 percent in
natural gas processing and 18 percent in natural gas liquids fractionation volumes for the year. During
2017, we added 400 million cubic feet per day of processing capacity and 120,000 barrels per day of
fractionation capacity.
The partnership continues to pursue and execute signifi cant growth opportunities. In the Marcellus
basin, we initiated the startup of the Sherwood IX gas processing plant as we closed 2017, and two
new plants are planned for our Sherwood complex in 2018, consistent with our strategy of constructing
plants on a just-in-time basis. We also expect to complete plant additions at our Houston, Majorsville
and Harmon Creek complexes by the end of the year. The addition of these plants will increase the
58281.indd 6
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Above: Sherwood gas
processing complex
in West Virginia
MPLX I 2017 ANNUAL REPORT I 5
GATHERING & PROCESSING
partnership’s processing capacity in the Marcellus and Utica basins by 21 percent to over 7 billion
cubic feet per day, further strengthening our position as the largest processor in the Northeast.
MPLX is also growing its footprint in prolifi c resource plays in the Southwest. In the Delaware Basin
of West Texas, our Hidalgo gas processing plant operated near full utilization in 2017. To support
ongoing producer activity in this area, we built a second gas processing plant, named Argo, which
was placed in service in the fi rst quarter of 2018. In addition, the partnership is constructing a gas
processing plant in the STACK resource of Oklahoma’s Cana-Woodford Shale that is expected to
be complete by mid-2018. We are also investing in two additional plants in southeast Oklahoma
through our Centrahoma processing joint venture.
Below:
Hidalgo gas
processing plant
in Texas
Overall, in 2018 we plan to add eight processing plants, increasing the partnership’s processing
capacity by nearly 1.5 billion cubic feet per day. The partnership also expects to add 40,000 barrels
per day of ethane fractionation capacity, and 60,000 barrels per day of propane-plus
fractionation capacity.
increasing processing capacity
58281.indd 7
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MPLX I 2017 ANNUAL REPORT I 6
BOARD OF DIRECTORS
Standing, left to right
Pamela K.M. Beall
Executive vice
president and chief
fi nancial 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 presi-
dent, Corporate
Planning and Strategy,
MPLX GP LLC.
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.
David A. Daberko
Retired chairman,
National City Corp.
Lead Director, MPC.
Mr. Daberko joined
National City Bank
in 1968 and went on
to hold a number
of management
positions. He was
named chairman of
the board and chief
executive offi cer
of National City
Corporation in 1995
and served in those
capacities until his
retirement in 2007.
Donald C. Templin
President, 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 presi-
dent of MPC and president of
MPLX in 2016. He assumed
his current role in 2017.
Prior to joining MPC in 2011,
Mr. Templin was managing
partner of Pricewaterhouse-
Coopers LLP’s audit practice
in Georgia, Alabama and
Tennessee.
Christopher A. Helms
President and CEO, U.S.
Shale Management Co.
Mr. Helms previously
served in various leader-
ship 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.
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.
C. Richard Wilson
Owner, Plough Penny
Associates, LLC. Prior to
Plough Penny, Mr. Wilson
was an executive offi cer
of Buckeye Partners,
L.P., a petroleum pipeline
company that became a
master limited partnership
in 1986. He served in vari-
ous capacities at Buckeye
and its general partner,
including as president,
chief operating offi cer,
director and vice
chairman.
(Retired Dec. 31, 2017)
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.
Timothy T. Griffi th
Senior vice president
and chief fi nancial
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 presi-
dent, 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.
Gary R. Heminger
Chairman and CEO, MPLX GP
LLC and chairman and CEO,
MPC. Mr. Heminger joined
Marathon Oil Co. in 1975
and held various leadership
positions including head of
Marathon’s downstream
operations beginning in
2001. Mr. Heminger was
named president and CEO of
Marathon Petroleum Corp. in
2011 and chairman in 2016.
He assumed his current slate
of roles in 2017.
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 chair of the board
and chief legal and adminis-
trative offi cer of United States
Steel Corp., retiring in 2007.
58281.indd 8
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COMPANY OFFICERS
MPLX I 2017 ANNUAL REPORT I 7
Standing, left to right
Seated, left to right
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
C. Michael Palmer
Senior Vice President
Suzanne Gagle
Vice President and General Counsel
Peter Gilgen
Vice President and Treasurer
Gregory S. Floerke
Executive Vice President, Gathering and Proccessing
Raymond L. Brooks
Senior Vice President
C. Kristopher Hagedorn
Vice President and Controller
John S. Swearingen
Executive Vice President, Logistics and Storage
Timothy J. Aydt
Vice President, Operations
Molly R. Benson
Vice President, Corporate Secretary and Chief Compliance Offi cer
Thomas M. Kelley
Senior Vice President
58281.indd 9
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MPLX I 2017 ANNUAL REPORT I 8
FINANCIAL AND OPERATIONAL HIGHLIGHTS
(In millions, except per-unit, throughput and average tariff data)
2017
2016
Revenues and other income
Net income attributable to MPLX LP
Limited partners’ interest in net income attributable to MPLX LP
Adjusted EBITDA attributable to MPLX LP (1)
Distributable cash fl ow (DCF)(1)
Net income per limited partner unit:
Common units – basic
Common units – diluted
Weighted average limited partner units outstanding:
$ 3,867
$ 3,029
794
411
2,004
1,563
233
1
1,419
1,099
$ 1.07
1.06
$ 0
0
Common units – basic
Common units – diluted
Cash and cash equivalents
Total assets
Total debt (2)
Redeemable preferred units
Total equity
Capital expenditures: (3)
Maintenance
Growth
Pipeline throughput (mbpd):
Crude oil pipelines
Product pipelines
Total pipelines
Average tariff rates ($ per bbl):
Crude oil pipelines
Product pipelines
Total pipelines
Gathering and Processing throughputs:(4)
Natural gas processed (mmcf/d)
C2+ NGLs fractionated (mbpd)
Total gathering throughputs (mmcf/d):
385
388
$ 5
19,500
7,332
1,000
9,973
108
1,518
1,936
1,085
3,021
0.56
0.74
0.63
6,460
394
3,608
331
338
$ 234
17,509
4,423
1,000
11,110
88
1,292
1,643
990
2,633
0.57
0.68
0.61
5,761
335
3,275
(1) Non-GAAP measure. See Reconciliation Data on Page 9.
(2) Total debt for 2017 includes $386 million of outstanding intercompany borrowings classifi ed in current liabilities as of Dec. 31, 2017.
(3) See Reconciliation Data on Page 9.
(4) Includes amounts related to unconsolidated equity method investments on a 100 percent basis.
58281.indd 10
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MPLX I 2017 ANNUAL REPORT I 9
RECONCILIATION DATA
Reconciliation of adjusted EBITDA attributable to MPLX LP, and DCF attributable to GP and LP unitholders
from net income (loss) (unaudited)
Year Ended Dec. 31
(In millions)
Net income
Depreciation and amortization
Provision (benefi t) for income taxes
Amortization of deferred fi nancing costs
Non-cash equity-based compensation
Impairment expense
Net interest and other fi nancial costs
(Income) loss from equity method investments (1)
Distributions from unconsolidated subsidiaries
Distributions of cash received from equity method investments to MPC
Other adjustments to equity method investment distributions
Unrealized derivative losses (2)
Acquisitions 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 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
2017
$ 836
683
1
53
15
–
301
(78)
241
(31)
21
6
11
2,059
(8)
(47)
2,004
33
(301)
(103)
(13)
6
2
1,628
(65)
$ 1,563
2016
$ 434
591
(12)
46
10
130
215
74
148
–
2
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 the partnership’s equity method investments for the year ended Dec. 31, 2016.
(2) The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative
contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract
matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.
(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
Current income taxes
Net interest and other fi nancial costs
Asset retirement expenditures
Unrealized derivative losses (1)
Acquisition costs
Distributions of cash received from equity method investments to MPC
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 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
2017
$ 1,907
(147)
(28)
15
–
2
301
2
6
11
(31)
21
2,059
(8)
(47)
2,004
33
(301)
(103)
(13)
6
2
1,628
(65)
$ 1,563
2016
$ 1,491
(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)
$ 1,099
(1) The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative
contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract
matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.
(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.
Reconciliation Data continued on next page.
58281.indd 11
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MPLX I 2017 ANNUAL REPORT I 10
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
Less: Maintenance capital
Total growth capital expenditures
Year Ended Dec. 31
2017
2016
$ 103
1,381
1,484
71
2
1,411
384
1,795
169
1,626
108
$ 84
1,213
1,297
(22)
6
1,313
131
1,444
64
1,380
88
$ 1,518
$ 1,292
(1) Includes capital expenditures of the Predecessor for all periods presented.
(2) Capital expenditures includes amounts related to unconsolidated, partnership operated subsidiaries.
Below: MPLX’s
Houston complex
in Pennsylvania
58281.indd 12
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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, 2017
‘ 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 and posted on its corporate web site, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter)
during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such
files.) Yes 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, 2017 was approximately $9.4 billion.
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 793,819,108 common units outstanding at February 16, 2018.
‘
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
MPLX LP
Page
4
40
68
69
80
81
82
84
88
125
129
197
197
197
198
210
248
252
255
257
269
270
Unless the context otherwise requires, references in this report to “MPLX LP,” “the Partnership,” “we,” “our,”
“us,” or like terms refer to MPLX LP and its subsidiaries, including MPLX Operations LLC (“MPLX
Operations”), MPLX Terminal and Storage LLC (“MPLX Terminal and Storage”), MarkWest Energy Partners,
L.P. (“MarkWest”), MarkWest Hydrocarbon, L.L.C. (“MarkWest Hydrocarbon”), MarkWest Pioneer, L.L.C.
(“MarkWest Pioneer”), MPLX Pipe Line Holdings LLC (“Pipe Line Holdings”), Marathon Pipe Line LLC
(“MPL”), Ohio River Pipe Line LLC (“ORPL”), Hardin Street Marine LLC (“HSM”), Hardin Street
Transportation LLC (“HST”), Woodhaven Cavern LLC (“WHC”) and MPLX Terminals LLC (“MPLXT”). We
have partial ownership interests in a number of joint venture legal entities, including MarkWest Utica EMG,
L.L.C. (“MarkWest Utica EMG”) and its subsidiary Ohio Gathering Company, L.L.C. (“Ohio Gathering”), Ohio
Condensate Company, L.L.C. (“Ohio Condensate”), Wirth Gathering Partnership (“Wirth”), MarkWest EMG
Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”), Sherwood Midstream LLC (“Sherwood
Midstream”), Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”), MarEn Bakken
Company, LLC (“MarEn Bakken”), Johnston County Terminal, LLC (“Johnston Terminal”), Guilford County
Terminal Company, LLC (“Guilford Terminal”), LOOP LLC (“LOOP”), LOCAP LLC (“LOCAP”), Illinois
Extension Pipeline Company, L.L.C. (“Illinois Extension”) and Explorer Pipeline Company (“Explorer”).
References to “MPC” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the
Partnership. Unless otherwise specified, references to “Predecessor” refer collectively to HSM’s, HST’s, WHC’s
and MPLXT’s related assets, liabilities and results of operations effective January 1, 2014 for HSM, January 1,
2015 for HST and WHC and April 1, 2016 for MPLXT.
The abbreviations, acronyms and industry technology used in this report are defined as follows.
Glossary of Terms
ATM Program
ARO
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
LIBOR
MarkWest Merger
mbbls
mbpd
mcf
MMBtu
MMcf/d
Net operating margin (a non-GAAP
financial measure)
NGL
NYSE
OTC
PADD
Partnership Agreement
PHMSA
PPI
Predecessor
An at-the-market program for the issuance of common units
Asset retirement obligation
Barrels
One billion cubic feet of natural gas per day
One British thermal unit, an energy measurement
On September 1, 2016, a series of reorganization transactions were
initiated in order to simplify the Partnership’s 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
London Interbank Offered Rate
On December 4, 2015, a wholly-owned subsidiary of the Partnership
merged with MarkWest Energy Partners L.P.
Thousands of barrels
Thousand barrels per day
One thousand cubic feet of natural gas
One million British thermal units, an energy measurement
One million cubic feet of natural gas 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
Over-the-Counter
Petroleum Administration for Defense District
Third Amended and Restated Agreement of Limited Partnership of
MPLX LP, dated as of October 31, 2016, as amended
Pipeline and Hazardous Materials Safety Administration
Producer Price Index
Collectively:
• HSM’s related assets, liabilities, and results of operations prior
to the date of the acquisition, March 31, 2016, effective
January 1, 2015
• HST’s, WHC’s and MPLXT’s related assets, liabilities and
results of operations prior to the date of the acquisition, March 1,
2017, effective January 1, 2015 for HST and WHC and April 1,
2016 for MPLXT
Realized derivative gain/loss
SEC
SMR
Unrealized derivative gain/loss
USCG
VIE
WTI
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,” “design,” “estimate,”
“objective,” “expect,” “forecast,” “goal,” “guidance,” “imply,” “intend,” “opportunity,” “outlook,” “plan,”
“position,” “potential,” “predict,” “project,” “prospective,” “pursue,” “seek,” “strategy,” “target,” “could,”
“may,” “should,” “would,” “will” 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:
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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);
anticipated levels of regional, national and worldwide prices of crude oil, natural gas, NGLs and
refined products;
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;
expectations regarding joint venture arrangements and other acquisitions, including the dropdowns
completed by MPC, or divestitures of assets;
business strategies, growth opportunities and expected investments;
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;
the adequacy of our capital resources and liquidity, including, but not limited to, availability of
sufficient cash flow to pay distributions and execute our business plan;
our ability to successfully implement our growth strategy, whether through organic growth or
acquisitions;
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.
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
1
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 significant business, economic, competitive, regulatory and other risks, contingencies and
uncertainties, most of which are difficult 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. Differences between actual results and any future performance suggested in our
forward-looking statements could result from a variety of factors, including the following:
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changes in general economic, market or business conditions;
changes in the economic and financial condition of MPLX LP;
risks and uncertainties associated with intangible assets, including any future goodwill or intangible
assets impairment charges;
changes in producer customers’ drilling plans or in volumes of throughput of crude oil, natural gas,
NGLs, refined products or other hydrocarbon-based products;
changes in regional, national and worldwide prices of crude oil, natural gas, NGLs and refined
products;
domestic and foreign supplies of crude oil and other feedstocks, natural gas, NGLs and 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;
• midstream and refining industry overcapacity or undercapacity;
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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;
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 in our capital budget, maintenance capital expenditure requirements or changes in costs of
planned capital projects;
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 and the expansion and retirement of pipeline, processing,
fractionation and treating capacity 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 strategies, whether through organic growth or
acquisitions;
accidents or other unscheduled shutdowns affecting our pipelines, processing, fractionation and treating
facilities or equipment, or those of our suppliers or customers or facilities upstream or downstream of
our facilities;
unusual weather conditions and natural disasters;
2
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disruptions due to equipment interruption or failure;
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;
legislative or regulatory action, which may adversely affect our business or operations;
rulings, judgments or settlements in litigation or other legal, tax or regulatory matters, including
unexpected environmental remediation costs, in excess of any reserves or insurance coverage;
political pressure and influence of environmental groups upon policies and decisions related to the
production, gathering, processing, fractionation, refining, transportation and marketing of natural gas,
oil, NGLs or other carbon-based fuels;
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;
increases in and availability of equity capital, 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, growth-oriented master limited partnership (“MLP”) formed in 2012 by MPC to own,
operate, develop and acquire midstream energy infrastructure assets. We are engaged in the gathering, processing
and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of NGLs;
and the gathering, transportation and storage of crude oil and refined petroleum products.
As of December 31, 2017, our assets included 1,613 miles and 2,360 miles of owned or leased and operated
crude oil and product pipelines, respectively, and partial ownership in 2,194 miles and 1,917 miles of crude oil
and products pipelines, respectively, all of which are across 17 states; a barge dock facility with approximately
78 mbpd of crude oil throughput capacity; crude oil and product storage facilities (tank farms) with
approximately 18,642 mbbls of available storage capacity; nine butane and propane storage caverns with
approximately 2,755 mbbls of NGL storage capacity; 59 light products terminal facilities, one leased terminal
and partial ownership in two terminals, with a combined total shell capacity of approximately 23.8 million
barrels; an inland marine business, comprised of 18 tow boats and 232 barges; and gathering and processing
infrastructure, with approximately 5.9 bcf/d of gathering capacity, 8.0 bcf/d of natural gas processing capacity
and approximately 610 mbpd of fractionation capacity, acquired as a result of the December 4, 2015 merger with
MarkWest (the “MarkWest Merger”), one of the largest processors of natural gas in the United States and the
largest processor and fractionator in the Marcellus and Utica shale plays.
MPC is our sponsor and a large source of our revenues. We have multiple transportation and storage services
agreements with MPC. These agreements are long-term, fee-based agreements with minimum volume
commitments and, therefore, MPC will continue to be an important source of our revenues for the foreseeable
future. Further, as a result of the MarkWest Merger, 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, Huron/Berea
Shale, Haynesville Shale, STACK Shale, Granite Wash formation and the Permian Basin.
MPC’s significant interest in us and its stated intent to grow its midstream business has been evidenced by the
completion of three dropdown acquisitions of MLP-qualifying midstream assets throughout 2017 and early 2018
projected to generate $1.4 billion of annual EBITDA, as discussed below. Immediately following the completion
of the dropdowns, 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 (“GP IDR Exchange”), also described below. As of February 1, 2018,
MPC controlled our general partner, MPLX GP LLC (“MPLX GP”), in addition to owning approximately
64 percent of our outstanding common units.
We have significant organic growth opportunities to expand midstream services throughout major shale plays in
the United States. We may also pursue third-party midstream acquisitions independently or with MPC to
complement our existing geographic footprint or expand our activities into new areas. We are backed by an
investment grade credit profile, which provides strong financial flexibility in order to fund growth projects and
execute our strategic plans.
4
We conduct our operations in the following operating segments: Logistics and Storage (“L&S”) and Gathering
and Processing (“G&P”). For more information on these segments, see Our Operating Segments discussion
below. The following map details our individual assets as of December 31, 2017:
The following table summarizes the operating performance for each segment for the year ended December 31,
2017. For further discussion of our segments and a reconciliation to our Consolidated Statements of Income, see
Item 8. Financial Statements and Supplementary Data—Note 10.
(In millions)
Revenues and other income:
Segment revenues
Segment other income
Total segment revenues and other income
Costs and expenses:
Segment cost of revenues
Segment operating income before portion attributable to noncontrolling interests
and Predecessor
Segment portion attributable to noncontrolling interests and Predecessor
Segment operating income attributable to MPLX LP
L&S
2017
G&P
Total
$1,480
47
$2,609
1
$4,089
48
1,527
2,610
4,137
692
1,105
1,797
835
53
1,505
170
2,340
223
$ 782
$1,335
$2,117
5
RECENT DEVELOPMENTS
On February 1, 2018, the Partnership acquired MPLX Refining Logistics LLC (“Refining Logistics”) and MPLX
Fuels Distribution LLC (“Fuels Distribution”) from MPC in exchange for cash and limited and general
partnership units. Refining Logistics contains the integrated tank farm assets that support MPC’s refining
operations. These essential logistics assets include: approximately 56 million barrels storage capacity (crude,
finished products and intermediates), 619 tanks, 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 MPC’s sole and
exclusive agent. The consideration for the transaction, which is projected to generate approximately $1.0 billion
of annual EBITDA, consisted of a cash payment of $4.1 billion and a fixed number of 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 (“GP Interest”). Immediately following this transaction was the GP
IDR Exchange. This exchange provides a clear valuation for MPC’s GP Interest in the Partnership, eliminates the
general partner cash distribution requirements of the Partnership and is expected to be accretive to DCF
attributable to common unitholders in the third quarter and for the full year 2018. MPC continues to own a
non-economic general partner interest in the Partnership. See Item 8. Financial Statements and Supplementary
Data—Note 24.
On January 26, 2018, we announced the board of directors of our general partner had declared a distribution of
$0.6075 per common unit that was paid on February 14, 2018 to common unitholders of record on February 5,
2018.
During 2017, we also executed on our organic growth plan, which included placing into service three new
processing plants and three new fractionation plants in the Marcellus and Utica areas and increasing tank storage.
ACQUISITIONS, INVESTMENTS AND OTHER HIGHLIGHTS
Effective January 1, 2017, the Partnership 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. The joint venture is also investing in fractionation
capacity at MarkWest’s Hopedale Complex and has an option to invest in future fractionation expansions that
support Antero Resources’ liquids production. See Item 8. Financial Statements and Supplementary Data—Note
5 for additional information.
On February 15, 2017, the Partnership closed on a joint venture 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, L.P. The Partnership holds, through a subsidiary, a 25 percent
interest in the joint venture, which equates to a 9.1875 percent indirect interest in the Bakken Pipeline system.
See Item 8. Financial Statements and Supplementary Data—Note 4 for additional information.
On March 1, 2017, the Partnership acquired the Ozark pipeline from Enbridge Pipelines (Ozark) LLC for
approximately $219 million. See Item 8. Financial Statements and Supplementary Data—Note 4 for additional
information.
On March 1, 2017, the Partnership acquired HST, WHC and MPLXT from MPC for $1.5 billion in cash and the
issuance of $503 million in MPLX LP equity. HST owns and operates various crude oil and refined product
pipelines and associated storage tanks. WHC owns and operates butane and propane storage caverns and MPLXT
owns and operates terminals for the receipt, storage, blending, additization, handling and redelivery of refined
petroleum products. See Item 8. Financial Statements and Supplementary Data—Note 4 for additional
information.
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On July 1, 2017, each of the Partnership’s remaining 3,990,878 Class B units 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. As a result of
the Class B units conversion, MPLX GP contributed less than $1 million in exchange for 7,330 general partner
units to maintain its two percent general partner interest. As common units outstanding as of the August 7, 2017
record date, the converted Class B units participated in the second quarter distribution. See Item 8. Financial
Statements and Supplementary Data—Note 8 for additional information.
On September 1, 2017, the Partnership acquired joint-interest ownership in certain pipelines and storage facilities
from MPC for $420 million in cash and the issuance of $653 million in MPLX LP equity. The acquired
ownership interests include a 35 percent ownership interest in Illinois Extension, a 40.7 percent ownership
interest in LOOP, a 58.52 percent ownership interest in LOCAP, and a 24.51 percent ownership interest in
Explorer. See Item 8. Financial Statements and Supplementary Data—Note 4 for additional information.
During the year ended December 31, 2017, we issued an aggregate of 13,846,998 commons units under our ATM
Program, generating net proceeds of approximately $473 million.
BUSINESS STRATEGIES
Our primary business objective is to enhance total unitholder returns through the generation of stable cash flows
and growing distributions. We intend to accomplish this objective by executing the following strategies:
Maintain and Strengthen Long-Term Integrated Relationships with Our Producer Customers. We develop long-
term integrated relationships with our producer customers. Our relationships are characterized by an intense
focus on customer service and a deep understanding of our producer customers’ requirements coupled with the
ability to increase the level of our midstream services in response to their midstream requirements. Through
collaborative planning, we construct midstream infrastructure and provide unique solutions that are critical to the
ongoing success of our producer customers’ development plans. As a result of delivering high-quality midstream
services, MarkWest has been a top-rated midstream service provider since 2006 as determined by an independent
research provider.
Grow through Acquisitions. In early 2018, we completed the final dropdown acquisition as part of the previously
announced strategic plan to acquire assets from MPC projected to generate $1.4 billion of annual EBITDA. As a
result of these actions, as well as the Ozark pipeline acquisition and the acquisition of the joint venture interest in
the Bakken Pipeline system, both of which occurred in the first quarter of 2017, we are one of the energy sector’s
largest diversified master limited partnerships and well-positioned to be a consolidator in the midstream sector.
We intend to continue pursuing third-party midstream acquisitions independently or with MPC that complement
our existing geographic footprint or expand our activities into new areas.
Increase Operating Cash Flow and Pursue Organic Growth Opportunities. We intend to increase operating cash
flow by evaluating and capitalizing on organic investment opportunities that may arise in our areas of operations
and increasing the utilization of our existing facilities by providing additional services for new and existing
customers. We will evaluate organic growth projects both within our geographic footprint as well as in new areas
that we consider strategic. With the support of MPC as our sponsor, we have the ability to develop incremental
infrastructure to support growth across the hydrocarbon value chain.
Focus on Fee-Based Businesses. We are focused on generating stable cash flows through long-term contracts
providing fee-based midstream services to MPC and third parties. For the full year ending December 31, 2018,
we expect fee-based contracts to be approximately 95 percent of our net operating margin (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—Non-GAAP Financial Measures).
7
Sustain Long-Term Growth. Our goal is to maintain an attractive distribution growth profile over the long
term. Since the Initial Offering, we have increased our distribution for 20 consecutive quarters, which represents
a compound annual growth rate of 18.3 percent over the minimum quarterly distribution. Our goal is to also
optimize our cost of capital by maintaining an investment grade credit profile, providing visibility to growth and
maintaining a strong distribution coverage, which will allow us to fund a higher proportion of our growth from
internal cash flows. On February 1, 2018, we completed the GP IDR Exchange, which we believe creates one of
the fastest and most pronounced paths to accretion compared with alternative general partner transactions. For
the remainder of 2018, we expect to fund our organic growth needs from internal cash flows and debt, without
the need to access public equity markets. See Item 8. Financial Statements and Supplementary Data—Note 24 for
additional information. We believe our plans, along with the support of our sponsor, provide multiple avenues to
support our distribution growth profile over the long-term.
Maintain Safe and Reliable Operations. We believe that providing safe, reliable and efficient services is a key
component in generating stable cash flows, and we are committed to maintaining and improving the safety,
reliability and efficiency of our operations. We intend to continue promoting a high standard for safety and
environmental stewardship.
COMPETITIVE STRENGTHS
We believe we are well-positioned to execute our business strategies based on the following competitive
strengths:
Extensive Portfolio of Strategically Located Assets. Our L&S segment assets are primarily located in the
Midwest and Gulf Coast regions of the United States and our G&P segment assets are primarily located in the
Northeast and Southwest regions of the United States.
• Our L&S assets are strategically located and collectively support approximately 75 percent of total
United States crude distillation capacity and can serve markets representing approximately 81 percent
of total United States finished products demand for the year ended December 31, 2017, according to
the EIA. These assets are located at the heart of the refining centers in the Midwest and Gulf Coast
regions of the United States and are strategic to third-party business, as well as being integral to the
success of MPC’s operations, which include six refineries with an aggregate crude oil refining capacity
of approximately 1.9 million barrels per calendar day.
• Our G&P segment is focused on regions of natural gas supply growth. We are one of the largest
processors and fractionators in the United States.
• We are the largest processor and fractionator in the Marcellus and Utica shale plays. As of
December 31, 2017, our assets in the northeastern United States have combined processing
capacity of approximately 6.7 bcf/d and combined fractionation capacity of approximately 578
mbpd, as well as an integrated NGL pipeline network and extensive logistics and marketing
infrastructure. We believe our significant asset base and full-service midstream model provides us
with strategic competitive advantages in capturing and contracting for gathering, processing and
fractionating of new supplies of natural gas as production in the Northeast continues to increase.
• We also have a growing presence in the southwestern portion of the United States with an existing
strong competitive position; access to a significant reserve or customer base with a stable or
growing production profile; ample opportunities for long-term continued organic growth; ready
access to markets; and close proximity to other expansion opportunities. We have 1.4 bcf/d of
processing capacity in the southwestern portion of the United States.
Additionally, we continually invest in the maintenance and integrity of our assets and have developed various
programs to help us efficiently monitor and maintain them. For example, within the L&S segment, we utilize
MPC’s patented integrity management program that employs state-of-the-art mechanical integrity inspection and
repair programs to enhance the safety of certain of our pipelines.
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Leading Midstream Positions Drive Investment Opportunities. Our organic growth capital plan for 2018 is
approximately $2.2 billion, which does not include the first quarter 2018 dropdown previously discussed or its
associated organic capital expenditures. The G&P segment capital plan includes investments that are expected to
support producer customers and complete certain processing and fractionation plants. During 2018, we expect to
complete 1.3 bcf/d of additional natural gas processing capacity and 100 mbpd of additional fractionation
capacity, primarily in the Marcellus Shale and southwestern portion of the United States. The L&S segment
capital plan includes the development of various crude oil and refined petroleum products infrastructure projects,
a butane cavern and tank farm expansion and an expansion project to increase line capacity on the Ozark
pipeline. We also have various organic growth prospects associated with the anticipated growth of MPC’s
operations and third-party activity in our areas of operation that we believe will provide attractive returns and
cash flows. We also plan to pursue acquisitions of other midstream assets on a standalone basis or cooperatively
with MPC.
Strategic Relationship with MPC. We have a strategic relationship with MPC and MPC views us as integral to its
operations and is aligned with our success, as evidenced by its accelerated execution of the dropdown
acquisitions. We believe MPC to be the largest crude oil refiner in the Midwest and the second-largest in the
United States based on crude oil refining capacity. MPC is well-capitalized, with investment grade credit ratings.
They own our general partner, an approximate 28.4 percent limited partner interest, and all of our incentive
distribution rights as of December 31, 2017. As a result of this relationship, MPC serves as a stable revenue
stream for MPLX LP and as we continue to provide services integral to the success of MPC, we believe that this
relationship will continue to provide us with growth opportunities, as well as a base of stable cash flows.
Stable and Predictable Cash Flows. We generate a substantial majority of our revenue through long-term,
fee-based agreements and have minimal direct commodity exposure. We believe our long-term contracts, which
we define as contracts with remaining terms of four years or more, lend greater stability to our cash flow profile.
Further, the dropdown acquisitions have substantially contributed stable fee-based earnings streams and have
diversified the financial profile of the Partnership. The table below provides long-term contract details by
segment as of December 31, 2017:
L&S segment
G&P segment
Remaining contract term
% of volumes
5-9 years
4 to 21 years
77%
87%
We manage our business by taking into account the partial offset of short natural gas positions primarily in the
Southwest region of our G&P segment. For the year ended December 31, 2017, we calculated the following
approximate percentages of our net operating margin from the following types of contracts:
L&S(2)
G&P(2)(3)
Total
Fee-Based
Other(1)
100%
86%
92%
—%
14%
8%
(1)
Includes percent-of-proceeds, keep-whole and other types of arrangements tied to NGL, condensate and
natural gas prices.
(2) Detail on contract types provided below.
(3)
Includes unconsolidated affiliates (See Item 8. Financial Statements and Supplementary Data—Note 5).
Financial Flexibility. As of December 31, 2017, we had $5 million of cash and approximately $1.9 billion
available on our revolving credit facility and our loan agreement with MPC Investment LLC (“MPC
Investment”), a wholly owned subsidiary of MPC. We are committed to maintaining our investment grade credit
profile, and we anticipate that we will not issue public equity to fund organic growth in 2018. Further, the
elimination of MPC’s IDRs and conversion of its two percent general partner interest into a non-economic
9
general partner interest in exchange for MPLX LP common units on February 1, 2018 eliminated the general
partner cash distribution requirements of the Partnership and is expected to be accretive to DCF attributable to
common unitholders in the third quarter and for the full year 2018. We believe that these actions allow us to have
financial flexibility to execute our growth strategy through excess cash reserves, borrowing capacity under our
revolving credit facilities as well as access to the debt and equity capital markets if so desired in the future. See
Item 8. Financial Statements and Supplementary Data—Note 8 and Note 17 for additional information regarding
our recent transactions related to debt and equity offerings.
Experienced Management Team. Our management team has substantial experience in the management and
operation of midstream assets. Our management team also has expertise in acquiring and integrating assets as
well as executing growth strategies in the midstream sector.
The above discussion contains forward-looking statements with respect to the business and operations of MPLX
LP, including the anticipated effects of the dropdown acquisitions and GP IDR Exchange with MPC, our
business strategies, competitive strengths and the Partnership’s capital budget, all of which are based on current
expectations, estimates and projections and are not guarantees of future performance. Actual results may differ
materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and
other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause
actual results to differ materially include negative capital market conditions, including an increase of the current
yield on common units, adversely affecting the Partnership’s ability to meet its distribution growth guidance; our
ability to achieve the strategic and other objectives discussed herein and other proposed transactions; adverse
changes in laws including with respect to tax and regulatory matters; the adequacy of the Partnership’s capital
resources and liquidity, including, but not limited to, availability of sufficient cash flow to pay distributions and
access to debt on commercially reasonable terms, and the ability to successfully execute its business plans and
growth strategy; the timing and extent of changes in commodity prices and demand for crude oil, refined
products, feedstocks or other hydrocarbon-based products; continued/further volatility in and/or degradation of
market and industry conditions; changes to the expected construction costs and timing of projects; completion of
midstream infrastructure by competitors; disruptions due to equipment interruption or failure, including electrical
shortages and power grid failures; the suspension, reduction or termination of MPC’s obligations under the
Partnership’s commercial agreements; modifications to earnings and distribution growth objectives; our ability to
manage disruptions in credit markets or changes to our credit rating; compliance with federal and state
environmental, economic, health and safety, energy and other policies and regulations and/or enforcement
actions initiated thereunder; adverse results in litigation; changes to the Partnership’s capital budget; prices of
and demand for natural gas, NGLs, crude oil and refined products, delays in obtaining necessary third-party
approvals and governmental permits, changes in labor, material and equipment costs and availability, planned
and unplanned outages, the delay of, cancellation of or failure to implement planned capital projects, project
overruns, disruptions or interruptions of our operations due to the shortage of skilled labor and unforeseen
hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and
other operating and economic considerations. These factors, among others, could cause actual results to differ
materially from those set forth in the forward- looking statements. For additional information on forward-looking
statements and risks that can affect our business, see “Disclosures Regarding Forward-Looking Statements” and
Item 1A. Risk Factors in this Annual Report on Form 10-K.
10
ORGANIZATIONAL STRUCTURE
The following diagram depicts our organizational structure and MPC’s ownership interests in us as of
February 16, 2018.
Marathon Petroleum Corporation
(NYSE: MPC)
and Affiliates (including our General Partner)
504,701,934 Common Units
(63.6% of common units outstanding)
Public Unitholders
289,117,174 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 are entitled to receive cumulative quarterly distributions
equal to $0.528125 per unit commencing for the quarter ended June 30, 2016, with a prorated amount
from the date of issuance. Following the second anniversary of the issuance of the Preferred units, the
holders of the Preferred units will be entitled to receive as a distribution the greater of $0.528125 per
unit or the amount of per unit distributions paid to common units. The purchasers may convert their
Preferred units into common units, at any time after the third anniversary of the issuance date or prior
to liquidation, dissolution or winding up of the Partnership, in full or in part, subject to minimum
conversion amounts and conditions. After the fourth anniversary of the issuance date, the Partnership
may convert the Preferred units into common units at any time, in whole or in part, subject to certain
minimum conversion amounts and conditions, if the closing price of MPLX LP common units is
greater than $48.75 for the 20 day trading period immediately preceding the conversion notice date.
11
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 (as
proportionately adjusted for any unit splits, unit distributions or similar transactions). The holders of
the Preferred units are entitled to vote on an as-converted basis with the common unitholders and have
certain other class voting rights with respect to any amendment to the 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, 2017, 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. While many forms of transportation are used to move this product to storage hubs and
refineries, we believe pipelines and marine vessels are among the safest, most efficient and cost-
effective ways to move this resource to refineries and to market. Pipelines bring advantaged North
American crude oil from the upper Great Plains, Louisiana, Texas and Canada to numerous refiners.
Pipelines and marine vessels are also used to effectively move refined products from refineries to
customers and end markets. Terminal facilities 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 and butane and propane caverns. 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.
12
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.
•
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 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/fractionation 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.
13
Basic NGL products and their typical uses are discussed below. The following basic NGL products are sold in
our G&P segment.
• Ethane is used primarily as feedstock in the production of ethylene, one of the basic building blocks for
a wide range of plastics and other chemical products.
• Propane is used for heating, engine and industrial fuels, agricultural burning and drying and as a
petrochemical feedstock for the production of ethylene and propylene.
• Normal butane is mainly used for gasoline blending, as a fuel gas, either alone or in a mixture with
propane, and as a feedstock for the manufacture of ethylene and butadiene, a key ingredient of
synthetic rubber.
•
Isobutane is primarily used by refiners to enhance the octane content of motor gasoline.
• Natural gasoline is principally used as a motor gasoline blend stock or petrochemical feedstock.
The other primary products also produced and sold in our G&P segment are discussed below.
• Ethylene is primarily used in the production of a wide range of plastics and other chemical products.
• Propylene is primarily used in manufacturing plastics, synthetic fibers and foams. It is also used in the
manufacture of polypropylene, which has a variety of end-uses including packaging film, carpet and
upholstery fibers and plastic parts for appliances, automobiles, housewares and medical products.
OUR OPERATING SEGMENTS
We conduct our operations in the following operating segments: L&S and G&P. As of December 31, 2017, our
assets and operations in each of these segments are described below.
L&S:
The L&S segment includes transportation and storage 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, and an inland marine business. Our pipeline network includes
approximately 8,084 miles of pipeline across 17 states. Our storage caverns consist of a butane cavern in Neal,
West Virginia with approximately 1,000 mbbls of liquefied petroleum gas storage capacity, and eight active
butane and propane storage caverns in Woodhaven, Michigan with approximately 1,755 mbbls of NGL storage
capacity. Our terminal facilities for the 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 23,789 mbbls. Our marine business owns and operates
boats, 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.
Additionally, we have ownership in various joint-interests, including LOOP LLC, the only U.S. deepwater oil
port, located offshore of Louisiana, which offloads crude oil from marine vessels destined for onshore storage
and pipeline transport. We have completed the Cornerstone pipeline project, expanded and reversed pipelines,
and increased tank storage to create a critical solution for the industry to move condensate and NGLs out of the
Marcellus and Utica regions into refining centers in the Midwest and connect to the pipelines to Canada. MPLX
LP acquired the Ozark pipeline in 2017, which is undergoing an expansion project to increase the line’s capacity
to approximately 360 mbpd, expected to be completed mid-2018. 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 dock 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. 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
14
December 31, 2017, 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 crude oil volumes in the open market to make up negative or positive imbalances.
As of December 31, 2017, our marine transportation operations included 18 owned towboats as well as 208
owned and 24 leased barges that transport refined products and crude oil on the Ohio, Mississippi and Illinois
rivers and their tributaries and inter-coastal waterways.
G&P:
Natural Gas Gathering
We operate several natural gas gathering systems that have a combined 5,903 MMcf/d throughput capacity in
five states. The scope of gathering services that we provide depends on 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.
Natural Gas Processing
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 transmission pipeline transportation or commercial use.
We currently operate five complexes in the Marcellus Shale, including: processing, gathering, and C2+
fractionation at the Houston Complex located in Washington County, Pennsylvania (the “Houston Complex”);
processing and de-ethanization at the Majorsville Complex located in Marshall County, West Virginia (the
“Majorsville Complex”); processing and de-ethanization at the Mobley Complex located in Wetzel County, West
Virginia (the “Mobley Complex”); processing and de-ethanization at the Sherwood Complex located in
Doddridge County, West Virginia (the “Sherwood Complex”); and processing, gathering, and C2+ fractionation
at the Bluestone Complex located in Butler County, Pennsylvania (previously referred to as Keystone). Further,
we operate one condensate stabilization facility with two mbpd of capacity near the Houston Complex.
MarkWest Utica EMG, our joint venture with an affiliate of the Energy & Minerals Group, operates two
complexes in the Utica Shale, including: processing and de-ethanization at the Cadiz Complex in Harrison
County, Ohio (the “Cadiz Complex”) and processing at the Seneca Complex in Noble County, Ohio (the “Seneca
Complex”). MarkWest Liberty Midstream & Resources, LLC operates a C3+ fractionation complex at the
Hopedale Complex located in Harrison County, Ohio (the “Hopedale Complex”). The Hopedale Complex is
jointly owned by MarkWest Utica EMG and MarkWest Liberty Midstream. Further, Sherwood Midstream LLC
(our joint venture between MarkWest Liberty Midstream LLC and Antero Midstream LLC) has rights to
fractionation revenue and the obligation to pay expenses related to 20 mbpd of capacity in the Hopedale 3
fractionator at the Hopedale Complex. Ohio Condensate, our joint venture with Summit, operates one condensate
stabilization facility with 23 mbpd of capacity.
We operate four processing complexes in the Appalachia region, including: the Kenova Complex located in
Wayne County, West Virginia (the “Kenova Complex”); the Boldman Complex located in Pike County,
Kentucky (the “Boldman Complex”); the Cobb Complex located in Kanawha County, West Virginia (the “Cobb
Complex”); and the Langley Complex located in Langley, Kentucky (the “Langley Complex”). Further, we
operate a C3+ fractionation complex at the Siloam Complex in South Shore, Kentucky (the “Siloam Complex”).
We also operate five complexes in the Southwest region, including: processing and gathering at the Carthage
Complex located in Panola County, Texas (the “Carthage Complex”); processing and gathering at the Western
Oklahoma Complex located in Custer and Beckham Counties, Oklahoma (the “Western Oklahoma Complex”);
15
processing at the Hidalgo Complex located in Culberson County, Texas (the “Hidalgo Complex”); gathering at
the Eagle Ford Complex located in Dimmit County, Texas (the “Eagle Ford Complex”); and treating, processing
and C2+ fractionation at the Javelina Complex located in Corpus Christi, Texas (the “Javelina Complex”). We
also own a 40 percent non-operating interest in the Centrahoma processing joint venture with Targa Resources.
The joint venture includes processing plants in Southeast Oklahoma with existing capacity of 280 MMcf/d with
plans to add two additional plants in 2018 with a combined capacity of 270 MMcf/d. The new plants are
expected to be completed in the fourth quarter of 2018 and are not included in the following table.
The following table summarizes our current and planned processing assets:
Plant
Bluestone Complex
Harmon Creek Complex
Houston Complex(1)
Majorsville Complex(1)
Mobley Complex
Sherwood Complex
Cadiz Complex(2)
Seneca Complex(2)
Kenova Complex
Boldman Complex
Cobb Complex
Langley Complex
Carthage Complex
Western Oklahoma Complex
Hidalgo Complex
Argo Complex
Javelina Complex
Existing capacity
(MMcf/d)
Expansion
capacity under
construction
(MMcf/d)
Expected in-
service of
expansion
capacity
410
—
520
1,070
920
1,800
525
800
160
70
65
325
600
425
200
—
142
— N/A
200 Q4 2018
200 Q1 2018
200 Q3 2018
— N/A
400 Q3 2018
and Q4
2018
— N/A
— N/A
— N/A
— N/A
— N/A
— N/A
— N/A
75 Mid-2018
— N/A
200 Q1 2018
— N/A
Geographic Region
Marcellus Operations
Marcellus Operations
Marcellus Operations
Marcellus Operations
Marcellus Operations
Marcellus Operations
Utica Operations
Utica Operations
Southern Appalachian Operations
Southern Appalachian Operations
Southern Appalachian Operations
Southern Appalachian Operations
Southwest Operations
Southwest Operations
Southwest Operations
Southwest Operations
Southwest Operations
Total
8,032
1,275
(1) We have the operational flexibility to process gas for producer customers at either complex.
(2) We have the operational flexibility to process gas for producer customers at either complex.
The following table summarizes our key producer customers and attributes for each geographic region:
Key Producer Customers
Volume Protection
Area Dedications
Marcellus Operations
Utica Operations
Southern Appalachian
Operations
Southwest Operations
Range Resources,
Antero
Resources(1),
EQT(1), CNX,
HG Energy(1),
Southwestern(1),
Rex and others
76% of 2017
capacity contains
minimum volume
commitments
4.1 million acres
Antero
Resources(1),
Gulfport, Ascent,
Rice, and others
Core
Appalachia(1),
EQT(1) and
Transcanada(1)
Newfield, BP,
Trinity,
FourPoint
Energy, CCI,
Valero, and
others
27% of 2017
capacity contains
minimum volume
commitments
3.9 million acres
24% of 2017
capacity contains
minimum volume
commitments
None
18% of 2017
capacity contains
minimum volume
commitments
2.0 million acres
(1) We do not provide gathering services for these producer customers.
16
NGL Gathering
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.
C3+ NGL Fractionation Complexes
Our NGL fractionation facilities separate the mixture of extracted NGLs into individual purity product
components for end-use sale. All NGLs, other than purity ethane as discussed below, produced at our 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. We can also
gather NGLs produced at a third party’s processing facilities to the Houston, Hopedale and Bluestone Complexes
for fractionation.
Our fractionation facilities for propane and heavier NGLs are supported by long-term, fee-based agreements with
our key producer customers. The following tables summarize our current and planned fractionation assets at
these facilities:
Facility
Bluestone Complex
Hopedale Complex(1)
Houston Complex
Siloam Complex
Javelina Complex
Existing
propane and
heavier
NGLs + capacity
(mbpd)
Propane and
heavier NGLs
expansion
capacity under
construction
(mbpd)
Expected in-
service of
expansion
capacity
Market outlets
Geographic Region
47
180
60
24
11
— N/A
— N/A
Railcar and truck
loading
60 Q4 2018 Key interstate pipeline
access
Railcar and truck
loading
Marine vessels
Key interstate pipeline
access
Railcar and truck
loading
Marine vessels
Railcar and truck
loading
Marine vessels
Key interstate pipeline
access
— N/A
— N/A
Marcellus Operations
Marcellus and Utica
Operations
Marcellus Operations
Southern Appalachian
Operations
Southwest Operations
Total
322
60
(1)
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 LLC (a joint
venture between MarkWest Liberty and Antero Midstream LLC). MarkWest Liberty Midstream and
Sherwood Midstream LLC are entities that operate in the Marcellus region, and MarkWest Utica EMG is an
entity that operates in the Utica region. We account for MarkWest Utica EMG and Sherwood Midstream
LLC as equity method investments. See discussion in Item 8. Financial Statements and Supplementary
Data—Note 5.
17
Ethane Recovery, Transportation and Associated Market Outlets
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. The
following table summarizes our current and planned de-ethanization assets, which are, or are expected to be,
supported by a network of purity ethane pipelines:
Facility
Bluestone Complex
Harmon Creek Complex
Houston Complex
Majorsville Complex
Mobley Complex
Sherwood Complex
Cadiz Complex
Javelina Complex
Total
Existing
ethane
capacity
(mbpd)
Ethane
expansion
capacity under
construction
(mbpd)
Expected in-
service of
expansion
capacity
34
—
40
80
10
40
40
18
262
— N/A
20 Q4 2018
— N/A
— N/A
— N/A
20 Q3 2018
— N/A
— N/A
40
Geographic Region
Marcellus Operations
Marcellus Operations
Marcellus Operations
Marcellus Operations
Marcellus Operations
Marcellus Operations
Utica Operations
Southwest Operations
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 the 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 Houston Complex and from the 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.
Sunoco announced phase two of Mariner East (“Mariner East II”) with plans to construct a pipeline from
our Houston and Hopedale Complexes in western Pennsylvania and eastern Ohio, respectively, to transport
propane and butane to the Marcus Hook Facility where it will be loaded onto marine vessels and delivered
to domestic and international markets. The Mariner East II pipeline is expected to be operational in 2018.
A significant portion of our business comes from a limited number of key customers. For the year ended
December 31, 2017, revenues earned from two customers are significant to the segment, accounting for
16 percent and 12 percent of G&P segment revenue and 9 percent of consolidated operating revenue,
respectively.
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.
18
OUR TRANSPORTATION, TERMINAL, AND STORAGE SERVICES AGREEMENTS 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 service agreement, MPC has committed to provide us with minimum quarterly throughput and
storage volumes. 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. All of our
transportation services agreements for our crude oil and refined products pipelines include a 5 to 15 year term
with various automatic renewal terms ranging from multiple two to five year terms, unless terminated by either
party. Our butane and propane cavern storage services agreements include 10 to 17 year terms. Our terminal
services agreement includes a ten-year term and automatically renews for one additional five-year term, unless
terminated by either party. Our storage services agreements for our tank farms include a three-year term and
automatically renew for additional one-year terms, unless terminated by either party. Our marine transportation
service agreement includes an initial six-year term and automatically renews for up to two additional five-year
terms, unless terminated by either party.
The following table sets forth additional information regarding our transportation, terminal, 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)
Initiation Date
Various
Various
January 1, 2015
Various
Various
April 1, 2016
Term
(years)
5-10
10-15
6
10-17
3
10
MPC
minimum
commitment(1)
1,256
973
N/A(2)
2,755
18,642
131,530
(1) Quarterly commitments for our transportation services agreements refer to throughput in thousands of
barrels per day. Commitments for our cavern storage services agreements refer to thousands of barrels.
Commitments for our terminal services agreements refer to quarterly terminal throughput in thousands of
barrels. Volumes shown for crude oil transportation services agreements are adjusted for crude viscosities.
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 tanks and barges.
(3) Volume shown represents total tank farm capacity in thousands of barrels.
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. Any such remaining credits may be used against any volumes shipped by MPC on the applicable
pipelines, without regard to any minimum volume commitment that may have been in place during the term of
the agreement.
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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.
MPC’s obligations under these transportation and storage services agreements will not terminate if MPC no
longer controls our general partner.
OPERATING AND MANAGEMENT SERVICES AGREEMENTS WITH MPC AND THIRD PARTIES
Operating Agreements
Through MPL, we operate various pipelines owned by MPC and third parties under existing operating services
agreements that MPL has entered into with MPC and third parties. Under these operating services agreements,
MPL receives 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. MPL is generally reimbursed for all direct and indirect costs associated with operating the assets and
providing such operational services. These agreements generally range from one to five years in length and
automatically renew. Most of the agreements are indexed for inflation.
As noted above, MPL receives an annual fee for operating certain pipelines owned by MPC. MPC has agreed to
indemnify MPL against any and all damages arising out of the operation of MPC’s pipelines unless such
occurrence is due to the gross negligence or willful misconduct of MPL. MPL has agreed to indemnify MPC
against any and all damages arising out of MPL’s gross negligence or willful misconduct in the operation of the
pipelines. The initial term of this agreement was for one year and automatically renews from year-to-year unless
terminated by either party.
Our existing operating services agreements include an operating agreement with Red Butte Pipe Line LLC,
which is owned by a third party. Under this agreement, MPL receives an operating fee for operating certain
pipelines in Wyoming and Montana. The term of this agreement is through December 2018. We also have
operating services agreements with MPC under which MPL receives annual fees to provide services related to
certain of MPC’s refining assets.
MPL maintains and operates four joint interest pipelines including Capline, Centennial, Lou-Lex and Muskegon.
MPL receives an operating fee for each of these pipelines, which is subject to adjustment for inflation. In
addition, we are reimbursed for specific costs associated with operating each pipeline. The length and renewals
terms for each agreement vary.
Management Services Agreement
The Partnership, through its wholly-owned 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.
OTHER AGREEMENTS WITH MPC
We have the following additional agreements with MPC:
• Omnibus Agreement. 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 general and administrative
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.
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• Employee Services Agreements. We have various separate 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 employed by affiliates of our general partner.
OUR RELATIONSHIP WITH MPC
One of our competitive strengths is our strategic relationship with MPC, which we believe to be the largest crude
oil refiner in the Midwest and the second-largest in the United States, based on crude oil refining capacity. MPC
owns and operates six refineries and associated midstream transportation and logistics assets in PADD II and
PADD III, which consist of states in the Midwest and Gulf Coast regions of the United States, along with an
extensive wholesale and retail refined product marketing operation that serves markets primarily in the Midwest,
Gulf Coast and Southeast regions of the United States. MPC markets refined products under the Marathon brand
through an extensive network of retail locations owned by independent entrepreneurs, and under the Speedway
brand through its wholly-owned subsidiary, Speedway LLC, which operates what we believe to be the nation’s
second largest chain of company-owned and operated retail gasoline and convenience stores. In addition, MPC
sells refined products in the wholesale markets. MPC had consolidated revenues of approximately $75 billion in
2017. Marathon Petroleum Corporation’s common stock trades on the NYSE under the symbol “MPC.”
MPC retains a significant interest in us through its ownership of our general partner, an approximate 28.4 percent
limited partner interest, and all of our incentive distribution rights as of December 31, 2017. 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 2017 and early 2018
dropdowns of MLP-qualifying assets and services projected to generate approximately $1.4 billion in total of
annual EBITDA. These transactions have and are expected to support increased limited partner distributions and
provide value creation for investors.
OUR G&P CONTRACTS WITH THIRD PARTIES
We generate the majority of our revenues in the G&P segment from natural gas gathering, transportation and
processing; NGL gathering, transportation, fractionation, exchange, marketing and storage; and crude oil
gathering and transportation. We enter into a variety of contract types. In many cases, we provide services under
contracts that contain a combination of more than one of the arrangements described below. We provide services
under the following types of arrangements:
• Fee-based arrangements—Under fee-based arrangements, we receive a fee or fees for one or more of the
following services: gathering, processing and transmission of natural gas; gathering, transportation,
fractionation and storage of NGLs; and gathering, transportation and storage of crude oil. The revenue we
earn from these arrangements is generally directly related to the volume of natural gas, NGLs or crude oil
that flows through our systems and facilities and is not normally directly dependent on commodity prices. In
certain cases, our arrangements provide for minimum annual payments or fixed demand charges. Fee-based
arrangements are reported as Service revenue on the Consolidated Statements of Income. In certain
instances when specifically stated in the contract terms, we purchase product after fee-based services have
been provided. Costs to purchase such products are reported as Purchased product costs and revenue from
the sale of such products is reported as Product sales and recognized on a gross basis as we are the principal
in the transaction.
• Percent-of-proceeds arrangements—Under percent-of-proceeds arrangements, we gather and process
natural gas on behalf of producers, sell the resulting residue gas, condensate and NGLs at market prices and
remit to producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash
payments to the producer, we deliver an agreed-upon percentage of the residue gas and NGLs to the
producer (take-in-kind arrangements) and sell the volumes we retain to third parties. Revenue from these
arrangements is reported on a gross basis where we act as the principal, as we have physical inventory risk
and do not earn a fixed dollar amount. The agreed-upon percentage paid to the producer is reported as
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Purchased product costs on the Consolidated Statements of Income. Revenue is recognized on a net basis
when we act as an agent and earn a fixed dollar amount of physical product and do not have risk of loss of
the gross amount of gas and/or NGLs. Percent-of-proceeds revenue is reported as Product sales on the
Consolidated Statements of Income.
• Keep-whole arrangements—Under keep-whole arrangements, we gather natural gas from the producer,
process the natural gas and sell 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, we must either purchase natural gas at market prices for return to producers or make cash
payment to the producers equal to the energy content of this natural gas. Certain keep-whole arrangements
also have provisions that require us 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. 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 we are the
principal in the arrangement. Natural gas purchased to return to the producer and shared NGL profits are
recorded as Purchased product costs in the Consolidated Statements of Income.
• Purchase arrangements—Under purchase arrangements, we purchase natural gas and/or NGLs at either
(1) a percentage discount to a specified index price; (2) a specified index price less a fixed amount; or (3) a
percentage discount to a specified index price less an additional fixed amount. We may purchase product at
the inlet or outlet of our facility. We then resell the natural gas or NGLs at the index price or at a different
percentage discount to the index price. Revenue generated from purchase arrangements are reported as
Product sales on the Consolidated Statements of Income and are recognized on a gross basis as we purchase
and take title to the product prior to sale and are the principal in the transaction.
In many cases, we provide 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 keep-whole
arrangements, percent-of-proceeds arrangements or percent-of-index arrangements, we record such fees as
Service revenue on the Consolidated Statements of Income. When commodities are obtained as a result of
providing our services, Product sales is recorded at the time the commodity is sold. The terms of our contracts
vary based on gas quality conditions, the competitive environment when the contracts are signed and customer
requirements.
Amounts billed to customers for shipping and handling, including fuel costs, are included in Product sales on the
Consolidated Statements of Income, except under contracts where we are acting as an agent. Shipping and
handling costs associated with product sales are included in Purchased product costs on the Consolidated
Statements of Income. Taxes collected from customers and remitted to the appropriate taxing authority are
excluded from revenue. Cost of revenues and depreciation represent those expenses related to operating our
various facilities and are necessary to provide both Product sales and Service revenue. Reimbursements for third-
party charges, such as electricity, are recorded net in Cost of revenues.
The terms of our contracts vary based on gas quality conditions, the competitive environment when the contracts
are signed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL
prices may change as a result of changes in producer preferences, our 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 or storage
services.
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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;
• medium and large sized independent exploration and production companies;
• major interstate and intrastate pipelines; and
•
other marine and land-based transporters of natural gas and NGLs.
Some of our competitors operate as MLPs 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.
Additionally, we believe we have critical connections to a strong sponsor and the 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 less than 20 years old, 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
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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 such as changes in transportation and travel
patterns and 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 50 million gallons of propane storage
capacity in the Southern Appalachia region provided by an arrangement with a third party which provides us with
flexibility to manage the seasonality impact. Overall, our exposure to the seasonal fluctuations in the commodity
markets is declining due to our growth in fee-based business.
REGULATORY MATTERS
Our operations are subject to extensive regulations. The failure to comply with applicable laws and regulations or
to obtain, maintain and comply with requisite permits and authorizations can result in substantial penalties and
other costs to the Partnership. 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. Due to the myriad of complex federal,
state, provincial and local regulations that may affect us, directly or indirectly, reliance on the following
discussion of certain laws and regulations should not be considered an exhaustive review of all regulatory
considerations affecting our operations.
Pipeline Control Operations. 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.
Common Carrier Liquids Pipeline Operations. Our liquids pipelines are common carriers subject to regulation by
various federal, state and local agencies. FERC regulates interstate transportation on liquids pipelines under the
Interstate Commerce Act (“ICA”), Energy Policy Act of 1992 (“EPAct 1992”) and the rules and regulations
promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate
service on these pipelines, including interstate pipelines that transport crude oil, natural gas liquids (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
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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. 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. FERC may order a change to the portion of a rate that is subject to grandfathering protection upon
complaint only after it is shown that a substantial change has occurred since enactment in either the economic
circumstances or the nature of the services that were a basis for the rate. 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. 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
when and 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 pipelines must 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.
While petroleum pipelines often use the indexing methodology to change their rates, petroleum pipelines may
elect to support proposed rates by using other methodologies such as cost-of-service ratemaking, market-based
rates and settlement rates. A pipeline can follow a cost-of-service approach when seeking to increase its rates
above the rate ceiling provided that the pipeline can establish that there is a substantial divergence between the
actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can
charge market-based rates if it establishes that it lacks significant market power in the affected markets. In
addition, a pipeline can establish rates under settlement if agreed upon by all current shippers. 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 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. Whether a pipeline’s owners have
such actual or potential income tax liability is subject to review by FERC on a case-by-case basis. Although this
policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due
to the case-by-case review requirement. FERC’s income tax policy continues to be the subject of various appeals
by shippers, before FERC and the courts, and recently the United States Court of Appeals for the District of
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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. FERC is currently reviewing pleadings that the
parties to that case filed in response to the remand. We cannot guarantee that FERC, through an order related to
that remand or through another order, 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 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, including, but not limited to:
•
•
•
•
•
•
•
the overall cost of service, including operating costs and overhead;
the allocation of overhead and other administrative and general expenses to the regulated entity;
the appropriate capital structure to be utilized in calculating rates;
the appropriate rate of return on equity and interest rates on debt;
the rate base, including the proper starting rate base;
the throughput underlying the rate; and
the proper allowance for federal and state income taxes.
If FERC or a state commission were to determine that our rates were or had become unjust and unreasonable, we
could be ordered to reduce rates prospectively and pay refunds and/or reparations to shippers.
FERC-Regulated Natural Gas Pipelines. Our natural gas pipeline operations are subject to federal, state and local
regulatory authorities. Specifically, we have FERC gas tariffs on file for MarkWest New Mexico, L.L.C. and
MarkWest Pioneer, L.L.C. with respect to our Hobbs Pipeline and the Arkoma Connector Pipeline. These
pipelines are subject to regulation by FERC, and it is possible that we may have additional gas pipelines that may
require such tariffs and may be subject to similar regulation in the future. FERC regulation of jurisdictional
natural gas pipelines extends to various matters including:
•
•
•
•
•
•
•
rates and rate structures;
return on equity;
recovery of costs;
the services that our regulated assets are permitted to perform;
the acquisition, construction, expansion, operation and disposition of assets;
affiliate interactions; and
to an extent, the level of competition in that regulated industry.
Under the Natural Gas Act (“NGA”), FERC has authority to regulate natural gas companies that provide natural
gas pipeline transportation services in interstate commerce. As noted in the list above, FERC’s authority to
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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 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.
As noted above (under “Common Carrier Liquids Pipeline Operations”), FERC is reviewing its policies with
respect to the inclusion of income tax allowances in cost-of-service rates. A Notice of Inquiry into these issues
was issued by FERC on December 15, 2016. The outcome of this inquiry could affect the rates that interstate
natural gas pipelines are permitted to charge.
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.
Market Transparency Rulemakings. In 2007, FERC issued Order 704, as amended and clarified in subsequent
orders on rehearing, whereby wholesale buyers and sellers of more than 2.2 MMBtu of physical natural gas in the
previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas
processors and natural gas marketers, are now required to report, on May 1 of each year, aggregate volumes of
natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize,
contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to
determine which transactions should be reported based on the guidance of Order 704.
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
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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 could become subject to such regulations and
reporting requirements in the future to the extent that any of our intrastate pipelines were to begin providing, or
were 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,
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.
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Currently, PHMSA is evaluating possible changes to the scope and applicability of 49 C.F.R. Part 192, which
governs construction standards and operation of certain natural gas gathering pipelines. The changes being
considered 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.
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 FERC
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
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 is evaluating possible changes to the scope and applicability of 49
C.F.R. Part 195m, including, among other things, expansion of reporting obligations, additional inspection
requirements, and expansion of the use of leak detection systems. Depending upon the nature of the final rule-
making, those could have an impact upon MPLX LP operations. 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 are in compliance 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 are in compliance 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
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regulations. The majority of our vessels are subject to inspection by the USCG and carry certificates of
inspection. The crews employed aboard the vessels are licensed or certified by the USCG. We are required by
various governmental agencies to obtain licenses, certificates and permits for our vessels.
Our marine transportation business competes principally in markets subject to the Jones Act, a federal cabotage
law that restricts domestic marine transportation in the United States to vessels built and registered in the United
States, and manned and owned by United States citizens. We presently meet all of the requirements of the Jones
Act for our vessels. The loss of Jones Act status could have a significant negative effect on us. The requirements
that our vessels be United States built and manned by United States citizens, the crewing requirements and
material requirements of the USCG, and the application of United States labor and tax laws increases the cost of
United States flag vessels when compared with comparable foreign flag vessels. Our marine transportation
business could be adversely affected if the Jones Act were to be modified so as to permit foreign competition that
is not subject to the same United States government imposed burdens. Since the events of September 11, 2001,
the United States government has taken steps to increase security of United States ports, coastal waters and
inland waterways. We believe that it is unlikely that the current cabotage provisions of the Jones Act would be
modified or eliminated in the foreseeable future.
The Secretary of Homeland Security is vested with the authority and discretion to waive the Jones Act to such
extent and upon such terms as the Secretary may prescribe whenever the Secretary deems that such action is
necessary in the interest of national defense. For example, the Secretary has waived the Jones Act generally or
with respect to the transportation of certain petroleum products for limited periods of time and in limited areas
following the occurrence of certain natural disasters such as hurricanes. Waivers of the Jones Act, whether in
response to natural disasters or otherwise, could result in increased competition from foreign tank vessel
operators, which could negatively impact our marine transportation business.
Pipeline Interconnections. One or more of our plants include pipeline interconnections to, or incidental gathering
pipelines that connect the plants to, interstate pipelines. These pipeline interconnections are an integral part of
our facilities and are not currently being used, nor can they be used in the future, by any third party due to their
origin points at our proprietary facilities. Therefore, we believe these pipeline interconnections are part of our
plant facilities and are not subject to the jurisdiction of FERC. In the event that FERC were to determine that
these pipeline interconnections were subject to its jurisdiction, we believe the pipelines would qualify for a
waiver from most FERC reporting and filing requirements. In the event that FERC were to determine that the
pipeline interconnections did not qualify for such waivers, we would likely be required to file a tariff with FERC
for the pipeline interconnections, provide a cost justification for their transportation rates and provide service to
all potential shippers without undue discrimination. In such event, we may experience increased operating costs
and reduced revenues.
Security. Certain of our facilities have been preliminarily classified as subject to the Department of Homeland
Security Chemical Facility Anti-Terrorism Standards. In addition, we have several facilities that are subject to
the United States Coast Guard’s Maritime Transportation Security Act, and a number of other facilities that are
subject to the Transportation Security Administration’s Pipeline Security Guidelines and are designated as
“Critical Facilities.” The Transportation Security Administration Security Guidelines are subject to change
without formal regulatory proposal and review. We have an internal inspection program designed to monitor and
ensure compliance with all of these requirements. We believe that we are in material compliance with all
applicable laws and regulations regarding the security of our facilities.
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
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aspects of our present and future operations, including for example, requiring the acquisition of permits or other
approvals to conduct regulated activities that may impose burdensome conditions or potentially cause delays,
restricting the manner in which we handle or dispose of our wastes, limiting or prohibiting construction or other
activities in environmentally sensitive areas such as wetlands or areas inhabited by threatened or endangered
species, requiring us to incur capital costs to construct, maintain and/or upgrade processes, equipment and/or
facilities, restricting the locations in which we may construct our compressor stations and other facilities and/or
requiring the relocation of existing stations and facilities, and requiring remedial actions to mitigate any pollution
that might be caused by our operations or attributable to former operations. Spills, releases or other incidents may
occur in connection with our active operations or as a result of events outside of our reasonable control, which
incidents may result in non-compliance with such laws and regulations. Any failure to comply with these legal
requirements may expose us to the assessment of sanctions, including administrative, civil and criminal penalties,
the imposition of remedial or corrective actions and the issuance of orders enjoining or limiting some or all of
our operations.
We believe that our operations and facilities are in substantial compliance with applicable environmental laws
and regulations and the cost of continued compliance with such laws and regulations will not have a material
adverse effect on our results of operations or financial condition. We cannot assure, however, that existing
environmental laws and regulations will not be reinterpreted or revised or that new environmental laws and
regulations will not be adopted or become applicable to us. Generally speaking, the trend in environmental law is
to place more restrictions and limitations on activities that may be perceived to adversely affect the environment,
which may cause significant delays in obtaining permitting approvals for our facilities, result in the denial of our
permitting applications, or cause us to become involved in time consuming and costly litigation. Thus, there can
be no assurance as to the amount or timing of future 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. 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.
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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
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
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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
such liabilities. We do not believe that the portion of any such liabilities that the Partnership may bear with
respect to any such properties previously acquired by the Partnership 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.
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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.
Hydraulic Fracturing
We do not conduct hydraulic fracturing operations, but we do provide gathering, processing and fractionation
services with respect to natural gas, oil and NGLs produced by our producer customers as a result of such
operations. Hydraulic fracturing is an important and common practice that is used to stimulate production of
natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the
injection of water, sand and additives under pressure into targeted subsurface formations to fracture the
surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas
commissions, but several federal agencies have asserted regulatory authority over certain aspects of the process.
For example, the EPA has issued final Clean Air Act regulations governing performance standards, including
standards for the capture of air emissions released during hydraulic fracturing, and issued in May 2014 its
Advance Notice of Proposed Rulemaking to solicit input on the possible Toxic Substances Control Act reporting
of the chemical substances and mixtures used in hydraulic fracturing. Also, in March 2015, the Bureau of Land
Management (“BLM”) published its final rule setting new standards for hydraulic fracturing on onshore federal
and Indian lands. The final rules have been challenged and, in June 2016, the United States District Court for
Wyoming set aside these BLM rules, holding that the BLM lacked the statutory authority to regulate the
hydraulic fracturing process. In addition, Congress has from time to time considered legislation to provide for
additional regulation of hydraulic fracturing, and some states have adopted, and other states are considering
adopting, laws and/or regulations that could impose more stringent permitting, disclosure and well construction
requirements on natural gas and oil drilling activities or prohibit hydraulic fracturing altogether, similar to the
State of New York. 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. In the event
that new or more stringent federal, state or local legal restrictions relating to natural gas drilling activities or to
the hydraulic fracturing process are adopted in areas where our producer customers operate, those customers
could incur potentially significant added costs to comply with such hydraulic fracturing-related requirements and
experience delays or curtailment in the pursuit of production or development activities, which could reduce
demand for our gathering, transportation and processing services and/or our NGL fractionation services.
In addition, certain governmental reviews are underway that focus on potential environmental aspects of
hydraulic fracturing practices. Most notably, in December 2016, the EPA released its final assessment of the
impacts of hydraulic fracturing on drinking water. These studies could spur initiatives to further regulate
hydraulic fracturing that could delay or curtail production of natural gas, and thus reduce demand for our
midstream services.
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.
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
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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, or ppb, for both the
eight-hour primary and secondary standards protective of public health and public welfare. These standards,
which are currently again under review, could require states to implement new more stringent regulations, which
could apply to our operations and those of our customers. The EPA is currently considering revisions to
regulations or interpretations of regulations regarding permitting and performance standards for methane
emissions from new and modified oil and gas production and natural gas processing and transmission facilities,
any of which could require additional capital expenditures, increase our operating costs or otherwise restrict our
operations. Additionally, in 2015, 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
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 issued final
rules in May 2016 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
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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. 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 the Partnership 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.
Pipeline 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
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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.
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 Code of Federal Regulations (“CFR”) Part 192), as well as hazardous liquids by
pipeline (49 CFR 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 CFR, Part 195); pressure testing of
new pipelines (Subpart E of 49 CFR 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 CFR Part 195); protecting steel pipelines from the adverse effects of internal and external
corrosion (Subpart H of 49 CFR Part 195); and integrity management requirements for pipelines in HCAs (49
CFR 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.
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.
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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, including the Texas Railroad
Commission, have recently 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. These recent actions by PHMSA are
currently subject to judicial and administrative challenges by one or more midstream operators; however, to the
extent that such challenges are unsuccessful, midstream operators of NGL fractionation facilities and associated
storage facilities may be required to make operational changes or modifications at their facilities to meet
standards beyond current requirements. These changes or modifications may result in additional capital costs,
possible operational delays and increased costs of operation.
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, our general partner.
Our general partner has the sole responsibility for providing the employees and other personnel necessary to
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conduct our operations. All of the employees that conduct our business are employed by affiliates of our general
partner. Our general partner and its affiliates have approximately 4,300 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
http://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. 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, and 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 $7.7 billion as of December 31, 2017, including amounts
outstanding under our loan agreement with MPC Investment, and we may incur significant additional debt
obligations in the future. For example, in February 2018, we issued an additional $5.5 billion aggregate principal
amount of senior notes. 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 partnership 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.
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, strength of U.S. currency versus other international currencies, consumer confidence and
debt levels, retail trends, inflation and foreign currency exchange rates, may generally affect our business.
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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.
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, 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 depends in part on the level of
successful drilling activity near our facilities.
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.
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Our business plan and growth strategy requires, among other matters, 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
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 equity market 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. 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. A significant decline in oil prices, such as
the decline that occurred in 2015 and 2016, can impact our common unit price. Although oil prices have since
recovered to some extent, there is no assurance that this recovery will continue. The high and the low closing
market price of our common units in 2017 ranged from a high of $38.86 to a low of $31.10. Given the significant
change in MLP valuations and the resultant higher distribution yield environment the sector has experienced
since 2015, our cost of capital has increased, which could impair our ability to grow our business and make
distributions to unitholders at intended levels.
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;
42
•
•
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 may mean that we will not receive the amount of cash we expect to be
distributed to us. 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. In
addition, we may be unable to control the amount of cash we receive from the operation of these entities, which
could adversely affect our ability to pay the minimum quarterly distribution to our unitholders.
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.
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. Significant declines in oil, natural gas or NGL
prices could also cause producers to curtail or limit drilling operations, which may result in the volumes
delivered to us being less than anticipated. 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. In such event, if we are unable to secure additional sources, then the volumes that we gather or process
in the future could be less than anticipated. A decline in such volumes could have a material adverse effect on
our results of operations and financial condition.
Our expansion of existing assets and the construction of new assets, if completed, may not result in revenue
increases and 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, which requires the expenditure
of significant amounts of capital which may exceed our expectations. Construction involves many factors beyond
our control including 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, lengthy and occasionally unreasonable or impractical
43
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, subject us to additional expenses or
penalties and adversely affect our operations and cash flows available for distribution to unitholders. 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 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.
Furthermore, we may have only limited oil, natural gas, NGL or refined product supplies committed to these
facilities prior to their 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.
Other ways we may grow our business is through the construction of new pipelines or the expansion of existing
ones. The construction of a new pipeline or the expansion of an existing pipeline, by adding horsepower or pump
stations or by adding a second pipeline along an existing pipeline, involves numerous regulatory, environmental,
political, and legal uncertainties, most of which are beyond our control. The approval process for storage and
transportation projects has become increasingly challenging, due in part to state and local concerns related to
pipelines and negative public perception regarding the oil and gas industry. These projects may not be completed
on schedule (or at all) or at the budgeted cost. In addition, 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 will occur
44
over an extended period of time and we will not receive any material increases in revenues until after completion
of the project.
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;
•
•
•
•
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;
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
45
financial instruments, we might be forced to settle all or a portion of our derivative transactions without the
benefit of the cash flow from our sale or purchase of the underlying physical commodity, which could result in a
substantial diminution of our liquidity. Alternatively, we may seek to amend the terms of our derivative financial
instruments, including the extension of the settlement date of such instruments. Additionally, because we may
use derivative financial instruments relating to the future price of crude oil to mitigate our exposure to NGL price
risk, the volatility of our future cash flows and net income may increase if there is a change in the pricing
relationship between crude oil and NGLs. As a result of these factors, our risk management activities may not be
as effective as we intend in reducing the downside volatility of our cash flows and, in certain circumstances, may
actually increase the volatility of our cash flows. In addition, our risk management activities are subject to the
risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of
the derivative instruments are imperfect and our risk management policies and procedures are not properly
followed. For further information about our risk management policies and procedures, please read Item 8.
Financial Statements and Supplementary Data—Note 16.
To the extent that we do not manage the commodity price risk relating to a position that is subject to commodity
price risk and commodity prices move adversely, we could suffer losses. Such losses could be substantial and
could adversely affect our operations and cash flows available for distribution. In addition, managing the
commodity risk may actually reduce our opportunity to benefit from increases in the market or spot prices.
As a result of the Dodd-Frank Act, over-the-counter 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 over-the-counter 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 various of our producer customers, and as a result, we may
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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.
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
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cases are permitted to compete with us and may have a competitive advantage due to their familiarity with our
business arising from our joint venture arrangements, as well as third parties on whom we rely to deliver natural
gas, NGLs, crude oil and refined products to our facilities, who may have a competitive advantage due to their
ability to modify the flow of natural gas, NGLs, crude oil and refined products on their systems away from our
facilities. Additionally, our customers that gather gas through facilities that are not otherwise dedicated to us may
develop their own processing and fractionation facilities in lieu of using our services.
As a consequence of the increase in competition in the industry, and the volatility of natural gas prices, end-users
and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from
more than one natural gas company and have the ability to change providers at any time. Some of these end-users
also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the
market. Because there are numerous companies of greatly varying size and financial capacity that compete with
us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis
of price. The inability of our management to renew or replace our current contracts as they expire and to respond
appropriately to changing market conditions could affect our profitability.
The fees charged to third parties under our gathering, processing, transmission, transportation,
fractionation, stabilization and storage agreements may not escalate sufficiently to cover increases in costs,
or the agreements may not be renewed or may be suspended in some circumstances.
Our costs may increase at a rate greater than the fees we charge to third parties. Furthermore, third parties may
not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us
may be permanently or temporarily reduced due to certain events, some of which are beyond our control,
including force majeure events wherein the supply of natural gas, NGLs, crude oil or refined products are
curtailed or cut-off due to events outside our control, and in some cases, certain of those agreements may be
terminated in their entirety if the duration of such events exceeds a specified period of time. If the escalation of
fees is insufficient to cover increased costs, or if third parties do not renew or extend their contracts with us, or if
third parties suspend or terminate their contracts with us, our financial results would suffer.
We are exposed to the credit risks of our key customers and derivative counterparties, and any material
non-payment or non-performance by our key customers or derivative counterparties could reduce our
ability to make distributions to our unitholders.
We are subject to risks of loss resulting from non-payment or non-performance by our customers, which risks
may increase during periods of economic uncertainty. Furthermore, some of our customers may be highly
leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default
on their obligations to us. This risk is further heightened during sustained periods of declines of natural 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.
Any strategic acquisitions are subject to substantial risks that could adversely affect our financial
condition and results of operations and reduce our ability to make distributions to unitholders.
In addition to organic growth, a component of our business strategy can include the expansion of our operations
through strategic acquisitions. Any acquisitions involve potential risks, including, amongst others:
•
the validity of our assumptions about revenues, capital expenditures and operating costs of the acquired
business or assets, as well as assumptions about achieving synergies with our existing business;
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the validity of our assessment of environmental and other liabilities, including legacy liabilities;
the costs associated with additional debt or equity capital, which may result in a significant increase in our
interest expense and financial leverage resulting from any additional debt incurred to finance such
acquisitions, or the issuance of additional common units or preferred units on which we will make
distributions, either of which could offset the expected accretion to our unitholders from such acquisition
and could be exacerbated by volatility in the equity or debt capital markets;
a failure to realize anticipated benefits, such as increased available cash per unit, enhanced competitive
position or new customer relationships;
a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to
finance the acquisition;
the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset
devaluation or restructuring charges; and
the risk that our existing financial controls, information systems, management resources and human
resources will need to grow to support future growth and we may not be able to react timely.
In addition, 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.
If we are unable to timely and successfully integrate our future acquisitions, our future financial
performance may suffer, and we may fail to realize all of the anticipated benefits of the transactions.
Our future growth may depend in part on our ability to integrate our future acquisitions. We cannot guarantee
that we will successfully integrate the assets acquired in the 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 present potential risks including:
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operating a significantly larger combined organization and integrating additional operations into ours;
difficulties in the assimilation of the assets and operations of the acquired businesses, especially if the assets
acquired are in a new business segment or geographical area;
the loss of customers or key employees from the acquired businesses;
the diversion of management’s attention from other existing business concerns;
the failure to realize expected synergies and cost savings;
coordinating geographically disparate organizations, systems and facilities;
integrating personnel from diverse business backgrounds and organizational cultures; and
consolidating corporate and administrative functions.
Further, 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. Following an acquisition, we may discover previously unknown liabilities, including
environmental liabilities, which could cause us to incur increased costs to address these liabilities or to attain or
maintain compliance with applicable law. 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.
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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.
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 pipelines, and various of our 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
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compliance with our tariff or applicable regulations, we may incur additional costs, expenses or penalties. For
certain natural gas pipelines and certain 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 and NGL pipelines, and various of our 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.
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
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refined product markets, or capitalize on other attractive expansion opportunities. Additionally, it may become
more expensive for us to obtain new or 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 have variable interest rates. Although
interest rates have been low during the past several years, the United States Federal Reserve raised interest rates
in 2015, 2016 and 2017. As a result, 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 storage, fractionation and
processing 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 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. 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.
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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, 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. The EPA has proposed a delay of this rule so that the EPA can determine
whether to revise or rescind the regulations. Additionally, this rule is currently being challenged in court by
various affected states. In addition, Pennsylvania has issued a proposed general permit applicable to compressor
stations that specifically recognizes an emissions limit for methane. 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.
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.
We have mature systems in place to manage potential acute physical risks, such as floods and hurricane-force
winds, 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.
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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 are subject to operating and litigation risks that may not be covered by insurance.
Our industry is subject to numerous operating hazards and risks incidental to gathering, processing, transporting,
fractionating and storing natural gas and NGLs and to transporting and storing crude oil and refined products.
These include:
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damage to pipelines, plants, storage facilities, barges, related equipment and surrounding properties caused
by floods, hurricanes and other natural disasters and acts of terrorism;
inadvertent damage from vehicles and construction and farm equipment;
leakage of crude oil, natural gas, NGLs, refined products and other hydrocarbons into the environment,
including groundwater;
fires and explosions; and
other hazards and conditions, including those associated with various hazardous pollutant emissions, high-
sulfur content, or sour gas, and proximity to businesses, homes, or other populated areas, that could also
result in personal injury and loss of life, pollution and suspension of operations.
As a result, we may be a defendant in various legal proceedings and litigation arising from our operations. We
may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates or at all,
and, even if we are able to obtain such insurance, we may not be able to recover amounts from the insurance
carrier for events that we believe are covered. In addition, insurance carriers now require broad exclusions for
losses due to war risk and terrorist acts. If we were to incur a significant liability for which we were not fully
insured, it could have a material adverse effect on our operations and cash available for distribution.
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;
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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.
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, 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
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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.
Information technology systems used in our operations could become the target of industrial espionage or
cyber-attack, the occurrence of which could materially and adversely affect 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 and network infrastructure and
maintain and rely upon certain critical information systems 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
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business processes, including our supply chain, 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. The U.S. government has issued public warnings that indicate
that energy assets might be specific targets of cyber security threats. Our systems and networks, as well as those
of our customers, vendors and counterparties, may become the target of cyber-attacks or information security
breaches, which in turn could result in the unauthorized release and misuse of confidential or proprietary
information as well as disrupt our operations, damage our facilities or those of third parties or cause spills or
releases, any or all of which could have a material adverse effect on our revenues, increase our operating and
capital costs, and reduce the amount of cash otherwise available for distribution. Additionally, as cyber incidents
continue to evolve we may be required to incur additional costs to modify or enhance our systems or in order to
try to prevent or remediate any such attacks. 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 cyber-security 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 infrastructure protection technologies and disaster recovery
plans and continuously provide awareness training around phishing, malware and other cyber-attacks to help
ensure we are protected against cyber risks and security breaches. 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. In addition our applicable
insurance may not compensate us adequately for losses that may occur. State and federal cyber-security
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, and the nation’s pipeline and terminal
infrastructure in particular, may be future targets of terrorist organizations. The threat of terrorist attacks has
subjected our operations to increased risks. Any future terrorist attack on our facilities, those of our customers
and, in some cases, those of other pipelines, could have a material adverse effect on our business. Similarly, any
future terrorist attacks that severely disrupt the markets we serve could materially and adversely affect our results
of operations, financial position and cash flows.
Risks Relating to the Business and Operations of MPC
MPC accounted for a large portion of our revenues in 2017 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, 2017, 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
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approximately 36 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;
the risk of contract cancellation, non-renewal or failure to perform by MPC’s customers, and MPC’s
inability to replace such contracts and/or customers;
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
services 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, 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.
MPC may suspend, reduce or terminate its obligations under our transportation and storage services
agreements 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.
Our transportation 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
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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 and storage services agreements we have with MPC, or if MPC elects to use credits upon
the expiration or termination of a transportation services 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 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 10 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, 2017, MPC had consolidated long-term
indebtedness of approximately $13 billion, of which $7 billion was a direct obligation of MPC. The covenants
contained in the agreements governing MPC’s outstanding and future indebtedness may limit its ability to
borrow additional funds for development and make certain investments and may directly or indirectly impact our
operations in a similar manner.
Furthermore, if MPC were to default under certain of its debt obligations, there is a risk that MPC’s creditors
would attempt to assert claims against our assets during the litigation of their claims against MPC. The defense
of any such claims could be costly and could materially impact our financial condition, even absent any adverse
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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.
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
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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.
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
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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 17 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.
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.
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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 16, 2018. 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
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;
63
• 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.
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.
64
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
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
65
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 16, 2018, 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
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.
66
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 partners 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 16, 2018, 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.
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 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
67
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
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
68
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, 2017.
Pipeline Name
Patoka to Lima and Canton crude pipelines
Patoka, IL to Lima, OH
Lima OH, to Canton, OH
Subtotal
Catlettsburg and Robinson crude pipelines
Patoka, IL to Robinson, IL
Patoka, IL to Catlettsburg, KY
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
Diameter
(inches)
Length
(miles)
Capacity
(mbpd)(1)
Associated MPC Refineries
20”/22”
12”/16”
20”
24”/20”
16”
16”
22”
22”
12”
30”
302
153
455
78
406
484
44
17
61
433
57
58
115
20
45
267 Detroit, MI; Canton, OH
84 Canton, OH
351
245 Robinson, IL
270 Catlettsburg, KY
515
117 Detroit, MI
80 Detroit, MI
197
230 All Midwest refineries
215 All Midwest refineries
99 All Midwest refineries
314
620 Garyville, LA
N/A
1,613
2,227
(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.
This pipeline is leased from a third party.
(3)
69
The following table sets forth certain information regarding crude oil pipelines in which we have a joint interest,
as of December 31, 2017.
Pipeline Name
Bakken Pipeline
Dakota Access Pipeline
Energy Transfer Crude Oil Company (ETCO) pipeline
Subtotal
Illinois Extension
LOOP
LOCAP
Total
Diameter
(inches)
Length
(miles)
Ownership
Interest
30”
30”
24”
48”
48”
9.2%
35%
40.7%
58.5%
1,172
749
1,921
168
48
57
2,194
Our crude oil pipeline and related assets are strategically positioned to support diverse and flexible crude oil
supply options for MPC’s Midwest 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.
70
Product Pipelines
The following table sets forth certain information regarding our product pipelines as of December 31, 2017.
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(2)
20”
36”
Subtotal
Texas products pipelines
Texas City, TX to Pasadena, TX
Pasadena, TX to connecting pipelines(2)
16”
36”/30”
Subtotal
Ohio products pipelines
Bellevue 4” Products
Canton, OH to East Sparta, OH(2,3)
Columbus Locals
Cornerstone Pipeline
Cadiz, OH to East Sparta, OH
East Sparta, OH to Canton, OH
East Sparta, OH to Heath, OH
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
West leg—Wood River, IL to
Champaign, IL
East leg—Robinson, IL to
Champaign, IL
4”
6”
12”
16”
8”
8”
8”
6”
8”/12”
14”
12”
8”
4”/6”
10”
16”
10”
10”
12”
12”
Champaign, IL to Hammond, IN(6) 16”/12”
Subtotal
Michigan product pipelines
Detroit LPG—Woodhaven #1
Detroit LPG—Woodhaven #2
Subtotal
Kentucky products pipeline
Louisville, KY to Louisville International
Airport
Louisville, KY to Lexington, KY(7)
Subtotal
Inactive pipelines(8)
Total
4”
4”
8”/6”
8”
71
70
2
72
40
3
43
3
17
1
50
8
81
62
108
149
150
N/A
251
54
934
250
129
79
317
130
86
140
1,131
12
14
26
389
N/A
389
215
N/A
215
5
73
N/A
198
40
47
32
24
63
68
N/A
24
32
606
51
82
77
48
71
99
85
513
6
6
12
14
87
101
140
2,447
29
37
66
N/A
1,801
Garyville, LA
Garyville, LA
Galveston Bay, TX
Galveston Bay, TX
N/A
Canton, OH
N/A
Canton, OH
Canton, OH
Canton, OH
Canton, OH
Catlettsburg, KY; Canton, OH
Catlettsburg, KY; Canton, OH
Catlettsburg, KY
N/A
N/A
N/A
Robinson, IL
Robinson, IL
Robinson, IL
Robinson, IL
Robinson, IL
Robinson, IL
Robinson, IL
N/A
N/A
Robinson, IL
N/A
(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 third-party
pipelines.
This pipeline is leased from a third party.
(5)
(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)
Includes 77 miles of pipeline leased from a third party.
The following table sets forth certain information regarding a products pipeline in which we have a joint interest,
as of December 31, 2017.
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 six of MPC’s refineries to MPC’s
marketing operations, as well as those of third parties. These pipelines also supply feedstocks to MPC’s Midwest
refineries. These product pipelines are integrated with MPC’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, 2017.
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
1,275
3,229
2,587
97
2,440
1,509
3,227
390
370
1,148
1,587
22,722
16
65
31
34
60
56
7
73
34
101
12
8
30
25
552
4
22
9
14
17
25
2
26
13
28
2
3
12
2
179
(1) MPLX Terminals owns and operates 59 terminals, operates one leased terminal and has partial ownership
interest in two terminals, with a combined tank shell capacity of 1,067 mbbls.
72
Marine Assets
The following table sets forth certain information regarding our marine assets as of December 31, 2017. 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 at
December 31,
2017
Capacity
(thousand barrels)
Associated MPC Refineries
Catlettsburg, KY; Garyville, LA
942
4,985
5,927
62
170
232
2
16
18
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 Midwest and U.S. 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.
Other L&S Assets
The following table sets forth certain information regarding our other midstream assets as of December 31, 2017,
each of which currently has an associated transportation services agreement or storage services agreement with
MPC.
Asset Name
Capacity(1)
Associated MPC Refineries
LOOP(2)
Wood River Barge Dock
Tank Farms(3)
Caverns
N/A
78 mbpd
18,642 mbbls
2,755 mbbls
N/A
Garyville, LA
N/A
N/A
(1) Capacity for Tank Farms and Caverns 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.
(2) We have a 40.7 percent interest in LOOP, which includes a deepwater oil port and crude oil storage.
(3) We own and operate 15 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, natural gas pipeline and crude oil and refined product pipelines as
of and for the year ended December 31, 2017. All throughputs and utilizations included are weighted-averages
for days in operation.
73
Gas Processing Complexes
Plant
Marcellus Shale:
Bluestone Complex
Houston Complex(2)
Majorsville Complex
Mobley Complex
Sherwood Complex(6)
Total Marcellus Shale
Utica Shale:
Cadiz Complex(7)
Seneca Complex(7)
Total Utica Shale
Southern Appalachia:
Kenova Complex(3)
Boldman Complex(3)
Cobb Complex
Kermit Complex(3)(4)
Langley Complex
Total Southern Appalachia(4)
Southwest:
Carthage Complex
Western Oklahoma Complex
Hidalgo Complex
Javelina Complex
Total Southwest(5)
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
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
Corpus Christi, TX
410
520
1,070
920
1,800
4,720
525
800
1,325
160
70
65
32
325
620
600
425
200
142
310
495
905
695
1,480
3,885
509
475
984
108
32
24
N/A
101
265
399
373
199
112
1,367
8,032
1,083
6,217
76%
95%
85%
76%
102%
89%
97%
59%
74%
68%
46%
37%
N/A
31%
43%
67%
88%
100%
79%
79%
81%
(1) Natural gas throughput is a weighted average for days in operation. The utilization of design capacity has
been calculated using the weighted average design throughput capacity.
(2) Approximately 35 MMcf/d of processing capacity at the Houston Complex was decommissioned during the
first quarter of 2017 and will be replaced with 200 MMcf/d of processing capacity in 2018.
(3) A portion of the gas processed at the Boldman plant, and all of the gas processed at the Kermit plant, is
(4)
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)
(5) Centrahoma processing capacity of 280 MMcf/d and actual throughput of 243 MMcf/d, that exceeded our
40 percent share of the capacity of 112 MMcf/d, are not included in this table as we own a non-operating
interest.
The Sherwood Complex is partially owned by Sherwood Midstream. We account for Sherwood Midstream
as an equity method investment. Included in design throughput capacity is Sherwood IX which was
commissioned in late December 2017. See discussion in Item 8. Financial Statements and Supplementary
Data—Note 5.
74
(7)
The Cadiz and Seneca Complexes 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.
Fractionation & Condensate Stabilization Facilities
Facility
Marcellus Shale:
Bluestone Complex(2)(3)
Houston Complex(2)
Total Marcellus Shale
Hopedale Complex(2)(4)
Utica Shale:
Ohio Condensate Complex(5)
Total Utica Shale
Southern Appalachia:
Siloam Complex(6)
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
180
23
23
24
24
11
11
19
61
80
134
13
13
14
14
8
8
40%
102%
75%
77%
57%
57%
58%
58%
73%
73%
345
249
73%
(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.
(3)
(4)
(2) Our Houston, Hopedale and Bluestone Complexes have above-ground NGL storage with a usable capacity
of 32 million gallons, 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 50 million gallons 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 that expires in 2018. Lastly, we have up to 8 million gallons of propane storage
with third parties that can be utilized by our assets in the Marcellus Shale and Utica Shale.
Includes 33 mbpd of de-propanization only capacity.
The Hopedale Complex is jointly owned by Ohio Fractionation and MarkWest Utica EMG. Ohio
Fractionation is a joint venture between 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 includes its portion utilized of the jointly
owned Hopedale Fractionation Complex. The Utica Operations includes Utica’s portion utilized of the
jointly owned Hopedale Fractionation Complex. Additionally, Sherwood Midstream has the right to
fractionation revenue and the obligation to pay expenses related to 20 mbpd of capacity in the Hopedale 3
fractionator.
The Ohio Condensate Complex has up to 7 million gallons 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)
(6) Our Siloam Complex has both above-ground, pressurized NGL storage facilities, with usable capacity of
two million gallons, and underground storage facilities, with usable capacity of 10 million gallons. Product
75
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 an 860,000 gallon barge.
De-ethanization Facilities
Facility
Marcellus Shale:
Bluestone 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
Marshall County, WV
Wetzel County, WV
Doddridge County, WV
Harrison County, OH
Corpus Christi, TX
34
40
80
10
40
204
40
40
18
18
262
15
40
45
11
30
141
5
5
12
12
158
63%
100%
99%
110%
75%
88%
13%
13%
67%
67%
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.
76
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,
Custer, Beckham and
Washita Counties, OK
Hughes, Pittsburg and
Coal Counties, OK
Dimmit County, TX
Various
227
1,178
1,405
1,123
1,250
2,373
165
839
1,004
766
426
1,192
73%
74%
74%
70%
47%
60%
680
444
65%
585
755
45
60
2,125
5,903
404
525
30
9
1,412
3,608
69%
70%
67%
15%
66%
66%
(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. 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 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.
Excludes lateral pipelines where revenue is not based on throughput.
(2)
(3)
(4)
77
NGL Pipelines
Pipeline
Location
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
Third-party processing plant to Bluestone
ethane and heavier liquids pipeline
Bluestone to Mariner West ethane pipeline(1)
Houston to Ohio River ethane pipeline(2)
Majorsville to Houston ethane pipeline(1)
Sherwood to Mobley ethane pipeline
Mobley to Majorsville ethane pipeline
Utica Shale:(5)
Seneca to Cadiz propane and heavier liquids
pipeline
Cadiz to Hopedale propane and heavier liquids
pipeline
Seneca to Cadiz propane/ethane and heavier
liquids pipeline(4)
Cadiz to Atex ethane pipeline
Cadiz to Utopia ethane pipeline
Appalachia:
Langley to Siloam propane and heavier liquids
pipeline(3)
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
Butler County, PA
Butler County, PA to
Beaver 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
Noble County, OH to
Harrison County, OH
Harrison County, OH
Noble County, OH to
Harrison County, OH
Harrison County, OH
Harrison County, OH
Langley, KY to South
Shore, KY
Southwest:
East Texas propane and heavier liquids pipeline Panola County, TX
Design
Throughput
Capacity
(mbpd)
NGL
Throughput
(mbpd)
Utilization of
Design
Capacity
75
105
45
140
32
35
57
137
47
57
75
90
69/82
125
125
17
39
60
85
32
69
8
15
9
49
30
41
16
31
1
5
1
12
22
80%
81%
71%
49%
25%
43%
16%
36%
64%
72%
21%
34%
1%
4%
1%
71%
56%
(1)
(2)
This pipeline is FERC-regulated.
This is a section of the Mariner West pipeline which is FERC-regulated and is leased to, and operated by,
Sunoco.
(4)
(3) 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.
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.
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
(5)
78
Crude Oil Pipeline
We also have a crude oil pipeline constructed in 1973 that runs from Manistee County, Michigan to Crawford
County, Michigan. The design capacity throughput for this pipeline is 60 mbpd. For the year ended December 31,
2017, throughput on this pipeline was 10 mbpd, which was approximately 17 percent utilization.
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. 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. 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. 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.
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;
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 21, 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 in
connection with our Initial Offering. 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 (as defined below) 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.
79
Item 3. 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. Some of
these matters are discussed below.
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.
The Partnership, 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. The MPLX Parties seek in excess of $10 million, plus an unspecified amount of punitive damages.
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 the Partnership cannot be predicted with certainty, and the Partnership is not able to
provide a reasonable estimate of the potential loss (or range of loss), if any, for these claims, the Partnership
believes the resolution of these claims will not 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 MPL. These complaints, which have been amended since filing, assert claims of common law nuisance
and contribution under the Illinois Contribution Act and other laws for environmental cleanup costs that may be
imposed on Premcor and Apex by the State of Illinois. On September 6, 2016, the trial court approved a
settlement between Apex and the State of Illinois whereby Apex agreed to settle all claims against it for a
$10 million payment. Premcor has objected to this ruling and is seeking an appeal. There are several third-party
defendants in the litigation and MPL has asserted cross-claims in contribution against the various third-party
defendants. This litigation is currently pending in the Third Judicial Circuit Court, Madison County, Illinois. The
State’s case against Premcor is currently scheduled to commence trial on June 25, 2018 and Premcor’s claims
against third-party defendants, including MPL, is currently scheduled to commence August 13, 2018. While the
ultimate outcome of these litigated matters remains uncertain, neither the likelihood of an unfavorable outcome
nor the ultimate liability, if any, with respect to this matter can be determined at this time and the Partnership is
unable to estimate a reasonably possible loss (or range of loss) for this litigation. Under the omnibus agreement,
MPC will indemnify the Partnership for the full cost of any losses should MPL be deemed responsible for any
damages in this lawsuit.
80
Environmental Proceedings
The Illinois Environmental Protection Agency (“IEPA”) initiated an enforcement action against MPL, in
connection with an April 17, 2016 pipeline release to the Wabash River near Crawleyville, Indiana. MPL
responded to a Clean Water Act request for information from the EPA in furtherance of its investigation of
possible violations arising from the April 17, 2016 pipeline release. MPL has entered into joint settlement
negotiations with the IEPA and the EPA and reached a settlement in principle for payment of a total civil penalty
of $335,000.
In July 2015, representatives from the EPA and the United States Department of Justice conducted a search at a
MarkWest Liberty Midstream pipeline launcher/receiver site utilized for pipeline maintenance operations in
Washington County, Pennsylvania pursuant to a search warrant. The criminal investigation ended without any
charges against MarkWest Liberty Midstream. With respect to the civil enforcement allegations associated with
permitting or other related regulatory obligations for its launcher/receiver and compressor station facilities in the
region, MarkWest Liberty Midstream and its affiliates have agreed in principle 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.
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 Disclosures
Not applicable
81
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 16, 2018, there were 323 registered holders of 289,117,174 outstanding common units held by the
public, including 287,997,480 common units held in street name. In addition, as of February 16, 2018, 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 the non-economic general partnership
interest in us.
The following table reflects intraday high and low sales prices of and cash distributions declared on our common
units by quarter over the last two fiscal years.
Quarter ended
High
Low
Trading prices per common unit
Quarterly
cash
distribution
per unit(1)
Distribution date
Record date
December 31, 2017
September 30, 2017
June 30, 2017
March 31, 2017
December 31, 2016
September 30, 2016
June 30, 2016
March 31, 2016
$38.47
36.80
37.85
39.43
35.32
35.12
34.92
39.46
$32.00
32.17
30.88
34.13
30.09
30.36
26.75
16.34
February 5, 2018
February 14, 2018
$0.6075
0.5875 November 14, 2017 November 6, 2017
0.5625 August 14, 2017
0.5400 May 15, 2017
0.5200
0.5150 November 14, 2016 November 4, 2016
0.5100 August 12, 2016
0.5050 May 13, 2016
August 7, 2017
May 8, 2017
February 6, 2017
August 2, 2016
May 3, 2016
February 14, 2017
(1) Represents cash distributions attributable to the quarter and declared and paid in accordance with our
Partnership Agreement and as amended.
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
82
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 are entitled to receive cumulative quarterly distributions equal to $0.528125
per unit for any quarter ending on or before May 13, 2018, and thereafter will be entitled to receive quarterly
distributions on each Preferred unit equal to the greater of $0.528125 per unit or the amount that each Preferred
unit would have otherwise received if it had been converted into common units at the then-applicable Preferred
unit conversion rate. The Partnership may not pay any distributions for any quarter on any junior securities,
including any of the common units, unless the distribution payable to the Preferred units with respect to such
quarter, together with any previously accrued and unpaid distributions to the Preferred units, have been paid in
full.
Recent Sales of Unregistered Units
In connection with the issuance of 84,658 common units upon vesting of phantom units under the MPLX LP
2012 Incentive Compensation Plan, our general partner purchased an aggregate of 1,727 general partner units for
$62,125.69 in cash during the three months ended December 31, 2017, to maintain its two percent general partner
interest in us. The general partner units were issued in reliance on an exemption from registration under
Section 4(a)(2) of the Securities Act of 1933, as amended.
83
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. On May 1, 2013, we acquired a five percent interest in Pipe Line Holdings, resulting in a
56 percent indirect ownership interest at December 31, 2013. We then acquired a 13 percent interest in Pipe Line
Holdings on March 1, 2014, and a 30.5 percent interest on December 1, 2014, resulting in a 99.5 percent indirect
ownership interest at December 31, 2014. The remaining 0.5 percent interest was purchased on December 4,
2015. On this same date, a wholly-owned subsidiary of MPLX LP merged with MarkWest. This information
includes periods prior to the acquisition of HSM, which occurred on March 31, 2016, and prior to the acquisition
of HST, WHC and MPLXT, which occurred on March 1, 2017.
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)
2017
2016
2015
2014
2013
Consolidated Statements of Income Data
Total revenues and other income
Income from operations
Net income
Net income attributable to MPLX LP
Limited partners’ interest in net income attributable to
MPLX LP
Per Unit Data
Net income attributable to MPLX LP per limited
partner unit (basic and diluted):
Common—basic
Common—diluted
Subordinated—basic and diluted
Cash distributions declared per limited partner
common unit
Consolidated Balance Sheets Data (at period end)
Property, plant and equipment, net
Total assets
Long-term debt, including capital leases(3)
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(1)
Other Financial Data
$ 3,867
1,191
836
794
$ 3,029
683
434
233
$ 1,101
381
333
156
$
411
1
99
$
793
245
239
121
115
713
213
211
78
76
$
1.07
1.06
—
$ — $
—
—
1.23
1.22
0.11
$
$
1.55
1.55
1.50
1.05
1.05
1.01
$2.2975
$2.0500
$1.8200
$1.4100
$1.1675
$12,187
19,500
6,945
1,000
$11,408
17,509
4,422
1,000
$10,214
16,404
5,255
—
$ 1,324
1,544
644
—
$ 1,248
1,504
10
—
$ 1,907
(2,307)
171
1,411
$ 1,491
(1,413)
113
1,313
$
$
427
(1,686)
1,275
334
498
399
$
$
$
$
335
(137)
(225)
141
166
137
297
(158)
(302)
151
111
114
Adjusted EBITDA attributable to MPLX LP(2)(4)
DCF attributable to MPLX LP(2)(4)
$ 2,004
1,628
$ 1,419
1,140
(1) Represents cash capital expenditures as reflected on Consolidated Statements of Cash Flows for the periods
(2)
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 a discussion of the non-GAAP financial
84
measures of Adjusted EBITDA and DCF and a reconciliation of Adjusted EBITDA and DCF to our most
directly comparable 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.
(3) 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
$943 million of borrowings under MarkWest’s credit facility.
For all years presented, Predecessor is excluded from Adjusted EBITDA attributable to MPLX LP and DCF
attributable to MPLX LP.
(4)
85
Operating Data
L&S
Crude oil transported for (mbpd)(1):
MPC
Third parties
Total
% MPC
Products transported for (mbpd)(2):
MPC(3)
Third parties
Total
% MPC
Average tariff rates ($ per Bbl)(4):
Crude oil pipelines
Product pipelines
Total pipelines
Terminal throughput (mbpd)(5)
Marine Assets (number in operation)(6)
Barges
Towboats
G&P(7)
Gathering Throughput (MMcf/d)
Marcellus Operations
Utica Operations(8)
Southwest Operations(9)
Total gathering throughput
Natural Gas Processed (MMcf/d)
Marcellus Operations
Utica Operations(8)
Southwest Operations(14)
Southern Appalachian Operations
Total natural gas processed
C2 + NGLs Fractionated (mbpd)
Marcellus Operations(10)
Utica Operations(8)(10)
Southwest Operations
Southern Appalachian Operations(11)
Total C2 + NGLs fractionated(12)
Pricing Information
Natural Gas NYMEX HH ($/MMBtu)
C2 + NGL Pricing/Gal(13)
2017
2016
2015
2014
2013
1,622
314
1,936
1,461
182
1,643
1,443
197
1,640
838
203
853
222
1,041
1,075
84%
89%
88%
80%
79%
928
157
1,085
86%
844
146
990
85%
966
27
993
97%
852
26
878
97%
862
49
911
95%
0.64
0.61
0.63
N/A
211
18
0.60
0.56
0.58
N/A
200
17
0.56
0.74
0.63
0.57
0.68
0.61
1,477
1,505
232
18
222
18
1,004
1,192
1,412
3,608
3,885
984
1,326
265
6,460
320
40
20
14
394
3.02
0.66
910
932
1,433
3,275
3,210
1,072
1,226
253
5,761
260
42
18
15
335
2.55
0.47
0.55
0.65
0.59
N/A
219
18
889
745
1,441
3,075
2,964
1,136
1,125
243
5,468
220
51
24
12
307
2.04
0.40
(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.
86
(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.
(8)
Includes unconsolidated equity method investments that are shown consolidated for segment purposes only.
Includes approximately 173 MMcf/d, 309 MMcf/d and 310 MMcf/d related to our unconsolidated equity
method investments, Wirth and MarkWest Pioneer, for the years ended December 31, 2017, 2016 and 2015,
respectively. The Partnership acquired a 100 percent interest in MarkWest Pioneer on July 1, 2017.
(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
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 165 mbpd, 128 mbpd and 104 mbpd of total fractionated products for
the years ended December 31, 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.
Includes Centrahoma, an unconsolidated equity method investment that is non-operated and is shown
100 percent in the above table for segment purposes only.
(14)
87
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in
conjunction with the information included under Item 1. Business, Item 1A. Risk Factors, Item 6. Selected
Financial Data and Item 8. Financial Statements and Supplementary Data.
Management’s Discussion and Analysis of Financial Condition and Results of Operations includes various
forward-looking statements concerning trends or events potentially affecting our business. You can identify our
forward-looking statements by words such as “anticipate,” “believe,” “estimate,” “objective,” “expect,”
“forecast,” “goal,” “intend,” “plan,” “predict,” “project,” “potential,” “seek,” “target,” “could,” “may,” “should,”
“would,” “will” 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, which could cause future outcomes to differ materially from those set forth in forward-looking
statements.
PARTNERSHIP OVERVIEW
We are a diversified, growth-oriented MLP formed by MPC to own, operate, develop and acquire midstream
energy infrastructure assets. We are engaged in the gathering, processing and transportation of natural gas; the
gathering, transportation, fractionation, storage and marketing of NGLs; and the gathering, transportation, and
storage of crude oil and refined petroleum products.
SIGNIFICANT FINANCIAL AND OTHER HIGHLIGHTS
During 2017, we continued to focus on our long-term objectives of delivering a sustainable distribution growth
rate that provides attractive total returns to our unitholders, driving a lower cost of capital, developing our
organic growth projects, maintaining our investment grade credit profile and becoming a consolidator in the
midstream space. Significant financial and other highlights for the year ended December 31, 2017, are listed
below. Refer to Results of Operations and Liquidity and Capital Resources for further details.
• L&S segment operating income attributable to MPLX LP increased approximately $329 million, or
73 percent, in 2017 compared to 2016. This increase was primarily due to $270 million of operating
income generated by HST, WHC and MPLXT following the March 1, 2017 acquisition, $35 million
from the inclusion of HSM for the first quarter of 2017, along with approximately $27 million from the
acquisition of the Ozark pipeline.
• G&P segment operating income attributable to MPLX LP increased approximately $203 million, or
18 percent, in 2017 compared to 2016. This increase was predominately due to $170 million from
increased gathered, processed and fractionated volumes, which drove higher utilization rates, as a result
of expansions in the Southwest, as well as growth at the Sherwood, Majorsville and Bluestone
(previously referred to as Keystone) plants. Further, there was an increase in product margins of
$63 million as compared to 2016, offset by increased facility expenses. Compared to full-year 2016,
gathering volumes were up 10 percent, processing volumes were up 12 percent and fractionated
volumes were up 18 percent.
Additional highlights for the year ended December 31, 2017, including a look ahead to anticipated growth, are
listed below.
Dropdown Acquisitions from MPC
In early 2017, MPC announced plans to offer MLP-qualifying midstream assets and services to the Partnership,
projected to generate $1.4 billion of annual EBITDA. Two of the three planned dropdown transactions, projected
88
to generate $388 million of annual EBITDA, occurred during the first and third quarters of 2017. The third
planned dropdown transaction, projected to generate $1.0 billion of annual EBITDA, occurred in the first quarter
of 2018. The stable, fee-based earnings from these acquisitions, as described below, add both scale and
diversification to our portfolio of high-quality midstream assets.
• 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 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. Refining Logistics contains the integrated tank farm assets that
support MPC’s refining operations. These essential logistics assets include: approximately 56 million
barrels storage capacity (crude, finished products and intermediates), 619 tanks, 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 MPC’s sole and exclusive agent. See Financing Activities below, and Item 8.
Financial Statements and Supplementary Data—Note 24 for additional information.
• On September 1, 2017, we acquired joint-interest ownerships in certain pipelines and storage facilities
from MPC for $420 million in cash and a fixed number of common units and general partner units of
18.5 million and 0.4 million, respectively. The general partner units maintained MPC’s two percent
economic general partner interest. The acquired ownership interests included a 35 percent ownership
interest in Illinois Extension, a 41 percent ownership interest in LOOP, a 59 percent ownership interest
in LOCAP, and a 25 percent ownership interest in Explorer (collectively, the “Joint-Interest
Acquisition”). As of the acquisition date, the assets held by these entities include a 1,830-mile refined
products pipeline, storage facilities, pump stations, and a deepwater oil port, located offshore of
Louisiana. The infrastructure serves primarily the Midwest and Gulf Coast regions of the United States.
• On March 1, 2017, we acquired certain pipeline, storage and terminal assets from MPC for $1.5 billion
in cash and a fixed number of common units and general partner units of 13.0 million and 0.3 million,
respectively. The general partner units maintained MPC’s two percent economic general partner
interest. As of the acquisition date, the assets consisted of 174 miles of crude oil pipelines and 430
miles of refined products pipelines, nine butane and propane storage caverns located in Michigan with
approximately 1.8 million barrels of NGL storage capacity, 59 terminals for the receipt, storage,
blending, additization, handling and redelivery of refined petroleum products, along with one leased
terminal and partial ownership interest in two terminals. Collectively, the 62 terminals had a combined
total shell capacity of approximately 23.6 million barrels. The terminal facilities are located primarily
in the Midwest, Gulf Coast and Southeast regions of the United States.
Other Significant Acquisitions and Investments
• On March 1, 2017, we purchased the 433-mile, 22-inch Ozark crude oil pipeline for $219 million. The
pipeline is capable of transporting approximately 230 mbpd and expands the footprint of our logistics
and storage segment by connecting Cushing, Oklahoma-sourced volumes to our extensive Midwest
pipeline network. An expansion project to increase the line’s capacity to approximately 360 mbpd is
targeted for completion in mid-2018.
• On February 15, 2017, we acquired a 9.1875 percent indirect equity interest in the Dakota Access
Pipeline and Energy Transfer Crude Oil Company Pipeline projects, collectively referred to as the
Bakken Pipeline system, for an initial investment of $500 million. 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.
• Effective January 1, 2017, we formed a strategic joint venture with Antero Midstream to process
natural gas at the Sherwood Complex and fractionate natural gas liquids at the Hopedale Complex. We
believe this unique transaction strengthens our long-term relationship with the largest producer in the
89
Appalachian Basin and provides the Partnership with substantial future growth opportunities. As part
of this agreement, Antero Midstream released to the joint venture the dedication of approximately
195,000 gross operated acres located in Tyler, Wetzel and Ritchie counties of West Virginia. We
contributed cash of $20 million, along with $353 million of assets, comprised of real property,
equipment and facilities, including three 200 MMcf/d gas processing plants then under construction at
the Sherwood Complex. Antero Midstream contributed cash of $154 million. The joint venture
commenced operations of the first new facility during the first quarter of 2017, the second new facility
during the third quarter of 2017 and the third new facility late in the fourth quarter of 2017.
Construction of the fourth and fifth new facilities has been announced and are expected to commence
operations in the last half of 2018. In addition to the five new processing facilities, the joint venture
contemplates the development of up to another six processing facilities to support Antero Resources,
which would be located at both the Sherwood Complex and a new location in West Virginia. At the
Hopedale Complex, the largest fractionation facility in the Marcellus and Utica shales, the joint venture
will also support the growth of Antero Resources’ NGL production by investing in 20 mbpd of existing
fractionation capacity, with options to invest in future fractionation expansions.
Financing Activities
• On February 8, 2018, the Partnership issued $5.5 billion 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
364-day term loan facility of $4.1 billion, the outstanding borrowings under the credit agreement and
the intercompany loan agreement with MPC Investment, as well as for general partnership 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 eliminates the general partner cash
distribution requirements of the Partnership and is expected to be accretive to DCF attributable to
common unitholders in the third quarter and for the full year 2018.
• On February 1, 2018, in connection with the dropdown acquisition, the Partnership 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.
• On July 21, 2017, we entered into a credit agreement to replace our previous $2.0 billion five-year
bank revolving credit facility with a $2.25 billion five-year bank revolving credit facility that expires in
July 2022. Additionally, on July 19, 2017, we repaid the entire outstanding principal amount of our
$250 million term loan with cash on hand. For further discussion, see Item 8. Financial Statements and
Supplementary Data—Note 17.
• On February 10, 2017, we completed a public offering of $2.25 billion aggregate principal amount of
senior notes. For further discussion, see Item 8. Financial Statements and Supplementary Data—Note
17.
• During the year ended December 31, 2017, we issued an aggregate of 13,846,998 commons units under
our ATM Program, generating net proceeds of approximately $473 million, all of which transactions
were executed during the first half of the year.
90
Refer to Item 1. Business—Recent Developments and Liquidity and Capital Resources for further details
concerning the above-listed announcements.
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 the Partnership’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) non-cash equity-based
compensation; (v) impairment expense; (vi) net interest and other financial costs; (vii) (income) loss from equity
method investments; (viii) distributions from unconsolidated subsidiaries; (ix) distributions of cash received from
equity method investments to MPC; (x) unrealized derivative losses (gains); (xi) other adjustments to equity
method investment distributions; and (xii) acquisition costs. 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.
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the
period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an
unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain
or loss is reversed and the realized gain or loss of the contract is recorded.
We believe that the presentation of Adjusted EBITDA and DCF provides useful information to investors in
assessing our financial condition and results of operations. The GAAP measures most directly comparable to
Adjusted EBITDA and DCF are net income and net cash provided by operating activities. Adjusted EBITDA and
DCF should not be considered alternatives to GAAP net income or net cash provided by operating activities.
Adjusted EBITDA and DCF have important limitations as analytical tools because they exclude some but not all
items that affect net income and net cash provided by operating activities or any other measure of financial
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 Results of Operations.
Management evaluates contract performance on the basis of net operating margin, a non-GAAP financial
measure, which is defined as segment revenue less purchased product costs less derivative gains (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.
In evaluating our financial performance, management utilizes the segment performance measures, segment
revenues and segment operating income, including total segment operating income. The use of these measures
allows investors to understand how management evaluates financial performance to make operating decisions
and allocate resources. See Item 8. Financial Statements and Supplementary Data—Note 10 for the
91
reconciliations of these segment measures, including total segment operating income, to their respective most
directly comparable GAAP measures.
COMPARABILITY OF OUR FINANCIAL RESULTS
Our acquisitions, sale of certain assets to newly formed joint ventures, and impairments have impacted
comparability of our financial results (see Item 8. Financial Statements and Supplementary Data—Notes 4, 5 and
18).
92
RESULTS OF OPERATIONS
The following table and discussion is a summary of our results of operations for the years ended 2017, 2016 and
2015, 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.
(In millions)
Revenues and other income:
Service revenue
Service revenue—related parties
Rental income
Rental income—related parties
Product sales
Product sales—related parties
Gain on sale of assets
Income (loss) from equity method investments(1)
Other income
Other income—related parties
2017
2016
$ Change
2015
$ Change
$1,156
1,082
277
279
889
8
—
78
6
92
$ 958
936
298
235
572
11
1
(74)
6
86
$ 198
146
(21)
44
317
(3)
(1)
152
—
6
$ 130
701
20
146
36
1
—
3
6
58
$ 828
235
278
89
536
10
1
(77)
—
28
Total revenues and other income
3,867
3,029
838
1,101
1,928
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
528
651
62
2
455
683
—
241
54
2,676
1,191
2
296
56
837
1
836
6
36
454
448
57
1
388
591
130
227
50
2,346
683
1
210
50
422
(12)
434
2
199
74
203
5
1
67
92
(130)
14
4
330
508
1
86
6
415
13
402
4
(163)
247
20
11
1
172
129
—
125
15
720
381
—
35
12
334
1
333
1
176
207
428
46
—
216
462
130
102
35
1,626
302
1
175
38
88
(13)
101
1
23
Net income attributable to MPLX LP
$ 794
$ 233
$ 561
$ 156
$
77
Adjusted EBITDA attributable to MPLX LP(2)
DCF(2)
DCF attributable to GP and LP unitholders(2)
$2,004
$1,628
$1,563
$1,419
$1,140
$1,099
$ 585
$ 488
$ 464
$ 498
$ 399
$ 399
$ 921
$ 741
$ 700
(1)
Includes an impairment expense of $89 million related to one of the Partnership’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.
93
(In millions)
2017
2016
2015
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF
attributable to GP and LP unitholders from Net income:
Net income
Depreciation and amortization
Provision (benefit) for income taxes
Amortization of deferred financing costs
Non-cash equity-based compensation
Impairment expense
Net interest and other financial costs
(Income) loss from equity method investments(1)
Distributions from unconsolidated subsidiaries
Distributions of cash received from Joint-Interest Acquisition entities to MPC
Other adjustments to equity method investment distributions
Unrealized derivative losses (gains)(2)
Acquisition costs
Adjusted EBITDA
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to Predecessor(3)
MarkWest’s pre-merger EBITDA(4)
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 pre-MarkWest undistributed
MarkWest undistributed DCF (4)
DCF
Preferred unit distributions
$ 836
683
1
53
15
—
301
(78)
241
(31)
21
6
11
2,059
(8)
(47)
—
2,004
33
(301)
(103)
(13)
6
2
1,628
—
1,628
(65)
$ 434
591
(12)
46
10
130
215
74
148
—
2
36
(1)
1,673
(3)
(251)
—
1,419
16
(215)
(84)
(3)
(1)
8
1,140
—
1,140
(41)
$ 333
129
1
5
4
—
42
(3)
15
—
—
(4)
30
552
(1)
(215)
162
498
6
(35)
(49)
—
(6)
17
431
(32)
399
—
DCF attributable to GP and LP unitholders
$1,563
$1,099
$ 399
94
(In millions)
2017
2016
2015
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF
attributable to GP and LP unitholders from Net cash provided by operating
activities:
Net cash provided by operating activities
Changes in working capital items
All other, net
Non-cash equity-based compensation
Net gain on disposal of assets
Net interest and other financial costs
Current income taxes
Asset retirement expenditures
Unrealized derivative losses (gains)(2)
Acquisition costs
Distributions of cash received from Joint-Interest Acquisition entities to MPC
Other adjustments to equity method investment distributions
Adjusted EBITDA
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to Predecessor(3)
MarkWest’s pre-merger EBITDA(4)
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 pre-MarkWest undistributed
MarkWest undistributed DCF(4)
DCF
Preferred unit distributions
$1,907
(147)
(28)
15
—
301
2
2
6
11
(31) —
21
$1,491
(76)
(16)
10
1 —
$ 427
59
(7)
4
215
42
5 —
6
36
(1)
1
(4)
30
—
2 —
2,059
(8)
(47)
—
2,004
33
(301)
(103)
(13)
6
2
1,628
—
1,628
(65)
1,673
(3)
(251)
—
552
(1)
(215)
162
498
6
(35)
(49)
1,419
16
(215)
(84)
(3) —
(1)
8
(6)
17
1,140
—
431
(32)
1,140
399
(41) —
DCF attributable to GP and LP unitholders
$1,563
$1,099
$ 399
(1)
(2)
(3)
(4)
Includes an impairment expense of $89 million related to one of the Partnership’s equity method
investments for the year ended December 31, 2016.
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During
the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded
as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded
unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.
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.
The financial and operational results of MarkWest are included in the Partnership’s results from
December 4, 2015, the date of the MarkWest Merger, in accordance with GAAP. The Partnership distributes
and, prior to the MarkWest Merger, MarkWest distributed, all or a portion of the DCF generated in any
given quarter to unitholders in the subsequent quarter. MarkWest had made a distribution for the third
quarter of 2015 prior to the MarkWest Merger. However, the DCF generated by MarkWest for the period
from October 1, 2015 through December 3, 2015 had not been distributed to MarkWest unitholders as of the
date of the MarkWest Merger. By operation of the MarkWest Merger, the Partnership acquired such
undistributed cash, along with all other assets of MarkWest, with the intent and obligation to distribute such
cash to the Partnership’s unitholders as part of the Partnership’s fourth quarter 2015 distribution. In order to
95
effectively include the amount of Adjusted EBITDA and DCF generated by MarkWest during the fourth
quarter of 2015 prior to the date of the MarkWest Merger, and effectively include such previously
undistributed cash, we have made adjustments labeled “MarkWest’s pre-merger EBITDA” and “MarkWest
undistributed DCF” in our reconciliations of Adjusted EBITDA and DCF to reported net income.
MarkWest’s pre-merger EBITDA represents Adjusted EBITDA generated by MarkWest for the period from
October 1, 2015 through December 3, 2015. MarkWest undistributed DCF represents the net adjustments
made to MarkWest’s pre-merger EBITDA in order to arrive at the DCF generated by MarkWest for the
period from October 1, 2015 through December 3, 2015.
The amount of Adjusted EBITDA and DCF generated by MarkWest for the period of October 1, 2015
through December 3, 2015 was considered by the board of directors of the Partnership’s general partner in
approving the Partnership’s cash distribution for the fourth quarter of 2015. In addition, we believe the
inclusion of the DCF generated by MarkWest for the period of October 1, 2015 through December 3, 2015
allows for a more meaningful calculation of the Partnership’s ratio of DCF generated to distributions
declared for the fourth quarter of 2015. We believe the inclusion of these adjustments presents an
appropriate basis for analyzing the complete operating results of the Partnership and MarkWest, on a
combined basis, for the year ended December 31, 2015.
The following table presents a reconciliation of net operating margin to income from operations, the most
directly comparable GAAP financial measure.
(In millions)
Reconciliation of net operating margin to income from operations:
Segment revenues
Purchased product costs
Total derivative loss (gain) related to purchased product costs
Other
Net operating margin
Revenue adjustment from unconsolidated affiliates(1)
Realized derivative loss related to purchased product costs(2)
Other
Unrealized derivative (loss) gains(2)
Income (loss) from equity method investments(3)
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
2017
2016
2015
$4,089
(651)
19
1
$3,426
(448)
27
(5) —
$1,063
(20)
(5)
3,458
(403)
(9)
—
(6)
78
6
92
(528)
(62)
(2)
(455)
(683)
—
(241)
(54)
3,000
(402)
1,038
(28)
(5) —
6
—
(36)
(74)
6
86
(454)
(57)
(1)
(388)
(591)
(130) —
(227)
(50)
4
3
6
58
(247)
(11)
(1)
(172)
(129)
(125)
(15)
Income from operations
$1,191
$ 683
$ 381
(1)
(2)
These amounts relate to Partnership-operated unconsolidated affiliates. The chief operating decision maker
and management include these to evaluate the segment performance as we continue to manage the
operations. Therefore, the impact of the revenue is included for segment reporting purposes, but removed
for GAAP purposes.
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During
the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded
96
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 the Partnership’s equity method
investments for the year ended December 31, 2016.
(3)
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 increase was primarily
related 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 increase was primarily
related 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 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.
Purchased product costs increased $203 million in 2017 compared to 2016. This variance was due to higher NGL
and gas prices and purchase volumes in the Southwest area, offset by a $12 million unrealized gain on an
embedded derivative.
Purchases-related parties increased $67 million in 2017 compared to 2016. The increase 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
97
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 Ozark, as well as additions to in-service property, plant and
equipment.
Impairment expense decreased $130 million in 2017 compared to 2016. This variance was 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 18 for more information.
General and administrative expenses increased $14 million in 2017 compared to 2016. The increase 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. The increase was
primarily due to the senior notes issued in February 2017.
2016 Compared to 2015
Service revenue increased $828 million in 2016 compared to 2015. This variance was primarily due to an
$824 million increase due to the MarkWest Merger, a $3 million increase related to volumes of crude oil and
products shipped and a $1 million increase due to higher average tariffs received on the volumes of crude oil and
products shipped.
Service revenue-related parties increased $235 million in 2016 compared to 2015. This increase was primarily
related to the acquisition of Predecessor, a $13 million increase in higher average tariffs received on the volumes
of crude oil and products shipped, a $6 million increase related to volumes in related-party crude oil and products
shipped, $3 million increase in storage fees and increased HSM equipment revenue, partially offset by a
reduction in fees previously paid by HSM on behalf of MPC that are now paid directly by MPC and a $2 million
decrease in revenue related to volume deficiency credits recognized.
Rental income increased $278 million in 2016 compared to 2015. This variance was due to the MarkWest
Merger.
Rental income-related parties increased $89 million in 2016 compared to 2015. This increase was primarily
related to the acquisition of Predecessor, a $10 million increase in HSM equipment revenue and a $3 million
increase in storage fees.
Product sales increased $536 million in 2016 compared to 2015. This variance was due to the MarkWest Merger.
Income (loss) from equity method investments decreased $77 million in 2016 compared to 2015. This variance
was primarily due to the MarkWest Merger combined with impairment charges of $89 million related to one of
our equity method investments.
Other income-related parties increased $28 million in 2016 compared to 2015. The increase was due mainly to
the MarkWest Merger and inclusion of management fee revenue for engineering and construction and
administrative services for operating our unconsolidated joint ventures, offset by a decrease in fees paid to HSM
by MPC.
Cost of revenues increased $207 million in 2016 compared to 2015. This variance was primarily due to the
MarkWest Merger and the acquisition of Predecessor, offset by a reduction in contract services and fees
previously paid by HSM on behalf of MPC that are now paid directly by MPC.
Purchased product costs increased $428 million in 2016 compared to 2015. This variance was due to the
MarkWest Merger.
98
Rental cost of sales increased $46 million in 2016 compared to 2015. This variance was primarily due to the
MarkWest Merger.
Purchases-related parties increased $216 million in 2016 compared to 2015. The increase was primarily due to
the acquisition of Predecessor and higher compensation expenses provided under the omnibus and employee
services agreements with MPC due to the MarkWest Merger, partially offset by increased capitalization of
employee costs associated with capital projects.
Depreciation and amortization expense increased $462 million in 2016 compared to 2015. This variance was
primarily due to the depreciation of the fair value of the assets acquired in the MarkWest Merger and the
acquisition of Predecessor.
Impairment expense increased $130 million in 2016 compared to 2015. This variance was due to a non-cash
impairment to goodwill in two reporting units in the G&P segment. See Item 8. Financial Statements and
Supplementary Data—Note 18 for more information.
General and administrative expenses increased $102 million in 2016 compared to 2015. The increase was
primarily due to the MarkWest Merger and the acquisition of Predecessor, offset by a reduction in expenses due
to changes in allocations provided for in the omnibus and employee services agreements with MPC as well as
$30 million of acquisition costs incurred in connection with the MarkWest Merger in 2015.
Other taxes increased $35 million in 2016 compared to 2015. The increase was primarily due to property taxes
related to the MarkWest Merger.
Interest expense and other financial costs increased $214 million in 2016 compared to 2015. The increase was
primarily due to the senior notes assumed as part of the MarkWest Merger.
SEGMENT REPORTING
We classify our business in the following reportable segments: L&S and G&P. Segment operating income
represents income from operations attributable to the reportable segments. We have investments in entities that
we operate that are accounted for using equity method investment accounting standards. However, we view
financial information as if those investments were consolidated. Corporate general and administrative expenses,
unrealized derivative (losses) gains, property, plant and equipment impairment, goodwill impairment and
depreciation and amortization are not allocated to the reportable segments. Management does not consider these
items allocable to or controllable by any individual segment and, therefore, excludes these items when evaluating
segment performance. Segment results are also adjusted to exclude the portion of income from operations
attributable to the noncontrolling interests related to partially-owned entities that are either consolidated or
accounted for as equity method investments. Segment operating income attributable to MPLX LP excludes the
operating income related to the HSM Predecessor prior to the March 31, 2016 acquisition and the HST, WHC
and MPLXT Predecessor prior to the March 1, 2017 acquisition.
99
The tables below present information about segment operating income for the reported segments for the years
ended December 31, 2017, 2016 and 2015.
L&S Segment
(In millions)
Revenues and other income:
Segment revenues
Segment other income
Total segment revenues and other income
Costs and expenses:
Segment cost of revenues
Segment operating income before portion attributable to noncontrolling interests
and Predecessor
Segment portion attributable to noncontrolling interests and Predecessor
Segment operating income attributable to MPLX LP
2017
2016
2015
$1,480
47
$1,241
53
$913
62
1,527
1,294
975
692
552
416
835
53
742
289
559
237
$ 782
$ 453
$322
2017 Compared to 2016
Segment revenue increased $233 million primarily due to the inclusion of $103 million of revenue generated by
MPLXT and its subsidiaries in the first quarter of 2017, a $46 million increase from higher crude and product
transportation volumes, a $64 million increase from the acquisition of the Ozark pipeline, and a $14 million
increase in HSM equipment revenue due to increased capacity as a result of acquisition or chartering of
additional barges.
Segment cost of revenues increased $140 million primarily due to the acquisitions of MPLXT and the Ozark
pipeline, increased expenses related to greater project spend, salaries and compensation due to headcount, and
other miscellaneous expenses.
Segment portion attributable to noncontrolling interests and Predecessor decreased $236 million due to the
inclusion of HSM for the first three months of 2016 and the acquisition of HST, WHC and MPLXT as of
March 1, 2017.
2016 Compared to 2015
Segment revenue increased $328 million primarily due to the acquisition of Predecessor as well as a $14 million
increase in higher average tariffs received on the volumes of crude oil and products shipped, $9 million related to
increased volumes of crude oil and products shipped, a $6 million increase in storage income and increased HSM
equipment revenue, partially offset by a reduction in fees previously paid by HSM on behalf of MPC that are
now paid directly by MPC and a $2 million decrease in revenue related to volume deficiency credits recognized.
Segment other income decreased $9 million primarily due to a reduction in fees paid to HSM by MPC.
Segment cost of revenues increased $136 million primarily due to the acquisition of Predecessor offset by a
decrease in fees previously paid by HSM on behalf of MPC that are now being paid directly by MPC and a
decrease in expenses related to the timing of maintenance projects.
Segment portion attributable to noncontrolling interests and Predecessor increased primarily due to the
acquisition of Predecessor.
100
During 2017 and 2016, MPC did not ship its minimum committed volumes on certain of our pipelines. As a
result, MPC was obligated to make $45 million and $56 million of deficiency payments in 2017 and 2016,
respectively. We record deficiency payments as Deferred revenue-related parties on our Consolidated Balance
Sheets. During 2017 and 2016, we recognized revenue of $38 million and $45 million, respectively, related to
volume deficiency credits. At December 31, 2017 and 2016, the cumulative balance of Deferred revenue-related
parties on our Consolidated Balance Sheets related to volume deficiencies was $53 million and $47 million,
respectively. The following table presents the future expiration dates of the associated deferred revenue credits
for 2017:
(In millions)
March 31, 2018
June 30, 2018
September 30, 2018
December 31, 2018
March 31, 2019
June 30, 2019
September 30, 2019
December 31, 2019
Total
$ 11
10
10
11
4
3
4
—
$ 53
We will recognize revenue for the deficiency payments in future periods at the earlier of when volumes are
transported in excess of the minimum quarterly volume commitments, when it becomes impossible to physically
transport volumes necessary to utilize the accumulated credits or upon expiration of the make-up period.
Deficiency payments are included in the determination of DCF in the period in which a deficiency occurs.
G&P Segment
(In millions)
Revenues and other income:
Segment revenues
Segment other income
Total segment revenues and other income
Costs and expenses:
Segment cost of revenues
Segment operating income before portion attributable to noncontrolling interests
Segment portion attributable to noncontrolling interests
Segment operating income attributable to MPLX LP
2017
2016
2015
$2,609
1
$2,185
$150
1 —
2,610
2,186
150
1,105
1,505
170
907
1,279
147
62
88
12
$1,335
$1,132
$ 76
2017 Compared to 2016
Segment revenues increased $424 million due to increased pricing on product sales of approximately
$207 million and increased volumes of $61 million, combined with increased fees of approximately $156 million
on higher volumes due to new processing plants in the Marcellus and Southwest areas and additional
fractionation capacity in the Marcellus and Utica areas.
Segment cost of revenues increased $198 million due primarily to increased product costs resulting from higher
prices of approximately $144 million and higher volumes of $47 million primarily in the Southwest area, as well
as increased facility expenses.
101
Segment portion attributable to noncontrolling interests increased $23 million primarily due to our joint venture,
Sherwood Midstream, that was formed effective January 1, 2017, as well as growth within our other joint
ventures that operate in the Utica area.
2016 Compared to 2015
The G&P segment increased overall due to the MarkWest Merger. There was no G&P segment prior to the
MarkWest Merger.
Segment Reconciliations
The following tables provide reconciliations of segment operating income to our consolidated income from
operations, segment revenue to our consolidated total revenues and other income, and segment portion
attributable to noncontrolling interests to our consolidated net income attributable to noncontrolling interests for
the years ended December 31, 2017, 2016 and 2015. Adjustments related to unconsolidated affiliates relate to our
Partnership-operated non-wholly-owned entities that we consolidate for segment purposes. Income (loss) from
equity method investments relates to our portion of income (loss) from our unconsolidated joint ventures of
which Partnership-operated joint ventures are consolidated for segment purposes. Other income-related parties
consists of operational service fee revenues from our operated unconsolidated affiliates. Unrealized derivative
activity is not allocated to segments.
(In millions)
Reconciliation to Income from operations:
L&S segment operating income attributable to MPLX LP
G&P segment operating income attributable to MPLX LP
Segment operating income attributable to MPLX LP
Segment portion attributable to unconsolidated affiliates
Segment portion attributable to Predecessor
Income (loss) from equity method investments(1)
Other income—related parties
Unrealized derivative (losses) gains(2)
Depreciation and amortization
Impairment expense
General and administrative expenses
Income from operations
(In millions)
Reconciliation to Total revenues and other income:
Total segment revenues and other income
Revenue adjustment from unconsolidated affiliates
Income (loss) from equity method investments(1)
Other income—related parties
Unrealized derivative gains (losses) related to product sales(2)
Total revenues and other income
102
2017
2016
2015
$ 782
1,335
$ 453
1,132
$ 322
76
2,117
(178)
53
78
51
(6)
(683)
—
(241)
398
(8)
236
3
2
4
(129)
1,585
(173)
289
(74)
40
(36)
(591)
(130) —
(227)
(125)
$1,191
$ 683
$ 381
2017
2016
2015
$4,137
(403)
78
51
4
$3,480
(402)
(74)
40
(15)
$1,125
(28)
3
2
(1)
$3,867
$3,029
$1,101
(in millions)
2017
2016
2015
Reconciliation to Net income attributable to noncontrolling interests and
Predecessor:
Segment portion attributable to noncontrolling interests and Predecessor
Portion of noncontrolling interests and Predecessor related to items below segment
income from operations
Portion of operating income attributable to noncontrolling interests of unconsolidated
affiliates
$ 223
$ 436
$249
(106)
(203)
(67)
(75)
(32)
(5)
Net income attributable to noncontrolling interests and Predecessor
$ 42
$ 201
$177
(1)
(2)
Includes an impairment expense of $89 million related to one of the Partnership’s equity method
investments for the year ended December 31, 2016.
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During
the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded
as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded
unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Our cash and cash equivalents balance was $5 million at December 31, 2017, compared to $234 million at
December 31, 2016. 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
2017
2016
2015
$ 1,907
(2,307)
171
$ 1,491
(1,413)
113
$
427
(1,686)
1,275
$ (229) $
191
$
16
Cash Flows Provided by Operating Activities. 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.
Net cash provided by operating activities increased $1.1 billion in 2016 compared to 2015 due primarily to due to
the MarkWest Merger.
Cash Flows Used in Investing Activities. Net cash used in investing activities increased $894 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.
103
Net cash used in investing activities decreased $273 million in 2016 compared to 2015, primarily due to a
$979 million use of cash for additions to property, plant and equipment and a $73 million use of cash for
investments in unconsolidated affiliates, offset by a $1.2 billion decrease in acquisitions due to the MarkWest
Merger and $101 million source of cash from investment loans between HSM and related parties prior to the
HSM acquisition.
Cash Flows from Financing Activities. Net cash provided by financing activities in 2017 was $171 million
compared to $113 million in 2016. The sources of cash in 2017 was primarily due to $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.
The sources of cash in 2015 primarily consisted of contributions of $1.2 billion from MPC for the MarkWest
Merger and proceeds of $169 million from issuances of general partner units. The uses of cash in 2015 primarily
consisted of distributions to unitholders.
Long-term debt borrowings and repayments were a net $2.5 billion source of cash in 2017 compared to an
$878 million use of cash in 2016 and a $38 million source of cash in 2015. During 2017, we used proceeds from
the issuance of the February 2017 senior notes and the bank revolving credit facility for general partnership
purposes, including the acquisitions of HST, WHC, MPLXT and the Joint-Interest Acquisition from MPC, the
acquisition of our equity interest in MarEn Bakken, the 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 bank revolving credit facility. During 2015, we used proceeds from the issuance of $500 million
aggregate of principal amount of senior notes to repay $385 million outstanding under the bank revolving credit
facility. See Item 8. Financial Statements and Supplemental Data—Note 17 for additional information on our
long-term debt.
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. The term loan facility was
drawn in full on November 20, 2014. 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 revolving credit facility with a $2.25 billion five-year bank revolving
credit facility that expires in July 2022 (“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. Additionally, on July 19, 2017, we prepaid the entire outstanding principal amount
of the $250 million term loan facility with cash on hand and terminated the agreement.
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
104
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 2017, we borrowed $670 million under the MPLX Credit Agreement, at an average interest
rate of 2.748 percent, and repaid $165 million of these borrowings. At December 31, 2017, we had $505 million
borrowings and $3 million in letters of credit outstanding under this facility, resulting in total unused loan
availability of approximately $1.7 billion, or 77.4 percent, of the borrowing capacity. There were no borrowings
under the previous bank revolving credit facility between January 1, 2017 and July 21, 2017.
Borrowings under the MPLX Credit Agreement bear interest at either the Adjusted LIBOR or the Alternate Base
Rate (as defined in the MPLX Credit Agreement), at our election, plus a specified margin. We are charged
various fees and expenses in connection with the agreement, including administrative agent fees, commitment
fees on the unused portion of the bank revolving credit facility and fees with respect to issued and outstanding
letters of credit. The applicable margins to the benchmark interest rates and certain of the fees fluctuate based on
the credit ratings in effect from time to time on our long-term debt.
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, 2017, we were in compliance with this financial covenant with a
ratio of Consolidated Total Debt to Consolidated EBITDA of 3.2 to 1.0, as well as all other covenants contained
in the MPLX Credit Agreement.
As of December 31, 2017, we had $6.9 billion in aggregate principal amount of senior notes outstanding. The
increase as of December 31, 2017 compared to year-end 2016 resulted from the February 2017 public offering of
senior notes. As of December 31, 2017, there were no minimum principal payments due during the next five
years. For further discussion, see Item 8. Financial Statements and Supplementary Data—Note 17.
On February 1, 2018, in connection with the dropdown acquisition, the Partnership drew $4.1 billion on a
364-day term loan facility with a syndicate of lenders. The proceeds of the term loan facility were used to fund
the cash portion of the dropdown consideration.
On February 8, 2018, the Partnership issued in a public offering of $5.5 billion senior notes, 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 364-day term loan facility of $4.1 billion, the outstanding borrowings under the MPLX Credit
Agreement and the intercompany loan agreement with MPC Investment, as well as for general partnership
purposes.
105
Our intention is to maintain an investment grade credit profile. As of January 31, 2018, 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- (stable outlook)
BBB (stable outlook)
The ratings shown above reflect the respective views of the rating agencies. Although it is our intention to
maintain a credit profile that supports an investment grade rating, there is no assurance that these ratings will
continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if,
in their respective judgments, circumstances so warrant.
The 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
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 $1.9 billion at December 31, 2017, 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, 2017
Total
Capacity
Outstanding
Borrowings
Available
Capacity
$2,250
500
$2,750
$(508)
(386)
$(894)
$1,742
114
$1,856
5
$1,861
(1) Outstanding borrowings include $3 million in letters of credit outstanding under this facility.
We expect our ongoing sources of liquidity to include cash generated from operations and borrowings under our
revolving credit facilities. 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.
106
Equity and Preferred Units Overview
The following table summarizes the changes in the number of units outstanding through December 31, 2017:
(In units)
Common
Class B
Subordinated
General
Partner
Total
—
—
36,951,515
—
1,638,625
386
81,931,238
19,318
Balance at December 31, 2014
Unit-based compensation awards
Issuance of units under the ATM
Program
Subordinated unit conversion
MarkWest Merger
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/MPLXT
Contribution of the Joint-interest
Acquisition
Class B conversion
43,341,098
18,932
25,166
36,951,515
216,350,465
296,687,176
120,989
—
—
7,981,756
7,981,756
—
26,347,887
22,534,002
4,350,057
7,153,177
—
—
(3,990,878)
—
357,193,288
268,167
3,990,878
—
13,846,998
12,960,376
18,511,134
4,350,057
—
—
—
(3,990,878)
Balance at December 31, 2017
407,130,020
—
—
(36,951,515)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
514
—
5,160,950
25,680
—
229,493,171
6,800,475
2,470
311,469,407
123,459
537,710
459,878
7,330
(436,758)
26,885,597
22,993,880
366,509
6,716,419
7,371,105
5,472
368,555,271
273,639
282,591
264,497
14,129,589
13,224,873
377,778
7,330
18,888,912
366,509
8,308,773
415,438,793
For more details on equity activity, see Item 8. Financial Statements and Supplementary Data—Notes 8 and 9.
On May 13, 2016, the Partnership 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 partnership
purposes.
The Preferred units rank senior to all common units with respect to distributions and rights upon liquidation. The
holders of the Preferred units are entitled to receive cumulative quarterly distributions equal to $0.528125 per
unit commencing for the quarter ended June 30, 2016, with a prorated amount from the date of issuance.
Following the second anniversary of the issuance of the Preferred units, the holders of the Preferred units will be
entitled to receive as a quarterly distribution the greater of $0.528125 per unit or the amount of per unit
distributions paid to common units. Since the Preferred unit distribution was declared subsequent to the end of
the second quarter of 2016, the distribution was not accrued to the Preferred unit holders’ capital account. For the
quarter ended June 30, 2016, the Preferred units received an earned aggregate cash distribution of $9 million,
based on the quarterly per unit distribution prorated for the 49-day period the Preferred units were outstanding
during the second quarter of 2016. Distributions paid to Preferred unit holders for the years ended December 31,
2017 and 2016, were $65 million and $25 million, respectively.
On July 1, 2016, 3,990,878 Class B units automatically converted into 1.09 MPLX LP common units and the
right to receive $6.20 per unit in cash. They also received the second quarter 2016 distribution. MPC funded the
$6.20 per unit cash payment, which reduced our liability payable to Class B unitholders by approximately
107
$25 million on July 1, 2016. As a result of 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 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. As a result of 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.
On August 4, 2016, the Partnership entered into a second amended and restated distribution agreement providing
for the at-the-market issuances of common units, in amounts, at prices and on terms determined by market
conditions and other factors at the time of the offerings. During the year ended December 31, 2017, the sale of
common units under the ATM Program generated net proceeds of approximately $473 million, all of which
transactions were executed during the first half of the year. The Partnership used the net proceeds from sales
under the ATM Program for general partnership purposes, including repayment or refinancing of debt and
funding for acquisitions, working capital requirements and capital expenditures.
On September 1, 2016, the Partnership and various affiliates initiated a series of reorganization transactions in
order to simplify the Partnership’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 and MarkWest. As a result of these transactions, the MPLX LP Class A
units were eliminated, are no longer outstanding and no longer participate in distributions of cash from the
Partnership. See additional discussion in Item 8. Financial Statements and Supplementary Data—Notes 8 and 12.
We intend to pay a minimum quarterly distribution of $0.2625 per unit, which equates to $109 million per
quarter, or $436 million per year, based on the number of common and general partner units. On January 26,
2018, we announced that the board of directors of our general partner had declared a distribution of $0.6075 per
common unit that was paid on February 14, 2018 to common unitholders of record on February 5, 2018. This
represents a 17 percent increase over the fourth quarter 2016 distribution. We have provided distribution growth
guidance of 10 percent for 2018. 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 GP 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.
108
The allocation of total quarterly cash distributions to general and limited partners is as follows for the years
ended December 31, 2017, 2016 and 2015. 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
Limited partner units—GP
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
2017
2016
2015
$
$
656
210
128
18
211
1,223
65
$ 1,288
$
533
159
—
18
187
897
41
938
$
$
151
104
—
6
54
315
—
315
$0.5400
0.5625
0.5875
0.6075
$0.5050
0.5100
0.5150
0.5200
$0.4100
0.4400
0.4700
0.5000
$2.2975
$2.0500
$1.8200
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 associated with new well connections, 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 the Partnership.
109
Our capital expenditures for the past three years are shown in the table below:
(In millions)
Capital expenditures(1):
Maintenance
Expansion
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
Less: Maintenance capital expenditures
Total growth capital expenditures
Acquisition, net of cash acquired
2017
2016
2015
$ 103
1,381
$
84
1,213
$
1,484
71
2
1,411
384
1,795
169
1,626
108
1,518
—
1,297
(22)
6
1,313
131
1,444
64
1,380
88
1,292
—
51
311
362
27
1
334
24
358
8
350
51
299
1,218
Total growth capital expenditures and acquisition
$1,518
$1,292
$1,517
(1)
(2)
Includes capital expenditures of the Predecessor for all periods presented.
Includes amounts related to unconsolidated, Partnership-operated subsidiaries.
Our growth capital plan for 2018 is $2.2 billion, not including the February 1, 2018 dropdown transaction with
MPC as discussed below and in Item 8. Financial Statements and Supplementary Data—Note 24, or its
respective subsequent capital spending. The G&P segment capital plan includes the addition of 1.5 billion bcf/d
processing capacity at eight gas processing plants, six in the Marcellus and Utica basins and two in the
Southwest, which expands the Partnership’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 100,000 barrels per day of
fractionation capacity in the Marcellus and Utica basins. In the L&S segment, work continues on the expansion
of the Ozark and Wood River-to Patoka pipeline systems, both of which are targeted for completion in mid-2018.
The L&S capital plan also includes the completion of a butane cavern in Robinson, Illinois, tank expansions in
Patoka, Illinois, and Texas City, Texas, and an expansion of the Partnership’s marine fleet. We also have large
organic growth prospects associated with the anticipated growth of MPC’s operations and third-party activity in
our areas of operation that we anticipate will provide attractive returns and cash flows. We continuously evaluate
our capital plan and make changes as conditions warrant.
110
Contractual Cash Obligations
The table below provides aggregated information on our consolidated obligations to make future payments under
existing contracts as of December 31, 2017:
(In millions)
Bank revolving credit facility(1)
Intercompany loan
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:
Other liabilities
AROs(7)
Total
2018
2019 & 2020 2021 & 2022 Thereafter
$
591
419
10,352
8
249
355
59
414
91
211
573
2
28
$ 19
11
324
1
54
354
28
382
20
17
52
—
—
$
38
408
649
7
79
1
15
16
36
34
123
2
—
$ 534
—
649
—
62
$ —
—
8,730
—
54
—
9
9
35
34
123
—
—
—
7
7
—
126
275
—
28
Total contractual cash obligations
$12,938
$880
$1,392
$1,446
$9,220
(1) Amounts represent outstanding borrowings at December 31, 2017, plus any commitment and administrative
fees and interest.
(2) Amounts relate primarily 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 16 for the fair value of the frac spread
sharing component). We use the estimated future frac spreads as of December 31, 2017 for calculating this
obligation. The counterparty to the contract has the option to renew the gas purchase agreement and the
related keep-whole processing agreement for two successive five-year terms after 2022, which is not
included in the natural gas purchase obligations line item.
(5) Represents amounts due under a product supply agreement (see Item 8. Financial Statements and
Supplementary Data—Note 23 for further discussion of the product supply agreement).
(6) Represents transportation and terminalling agreements that obligate us to minimum volume, throughput or
payment commitments over the terms of the agreements, which will range from 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.
Excludes estimated accretion expense of $28 million. The total amount to be paid is approximately
$56 million.
(7)
111
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 $69 million in
2017 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 $10 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.
The Partnership has various employee services agreements with MPC under which the Partnership reimburses
MPC for employee benefit expenses, along with the provision of operational and management services in support
of both our L&S and G&P segments’ operations, including those in support of HST, WHC, MPLXT and HSM.
We incurred $513 million of expenses under the employee services agreements for 2017.
Off-Balance Sheet Arrangements
As of December 31, 2017, we have not entered into any transactions, agreements or other arrangements that
would result in off-balance sheet liabilities.
Forward-looking Statements
Our opinions concerning liquidity and capital resources and our ability to avail ourselves in the future of the
financing options mentioned in the above forward-looking statements are based on currently available
information. If this information proves to be inaccurate, future availability of financing may be adversely
affected. Factors that affect the availability of financing include our performance (as measured by various
factors, including cash provided by operating activities), the state of worldwide debt and equity markets, investor
perceptions and expectations of past and future performance, the global financial climate, and, in particular, with
respect to borrowings, the levels of our outstanding debt and future credit ratings by rating agencies. The
discussion of liquidity and capital resources above also contains forward-looking statements regarding expected
capital spending. The forward-looking statements about our capital budget are based on current expectations,
estimates and projections and are not guarantees of future performance. Actual results may differ materially from
these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some
of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ
materially include negative capital market conditions, including an increase of the current yield on common
units, adversely affecting the Partnership’s ability to meet its distribution growth guidance; our ability to achieve
the strategic and other objectives discussed herein and other proposed transactions; adverse changes in laws
including with respect to tax and regulatory matters; the adequacy of the Partnership’s capital resources and
liquidity, including, but not limited to, availability of sufficient cash flow to pay distributions and access to debt
on commercially reasonable terms, and the ability to successfully execute its business plans and growth strategy;
the timing and extent of changes in commodity prices and demand for crude oil, refined products, feedstocks or
other hydrocarbon-based products; continued/further volatility in and/or degradation of market and industry
conditions; changes to the expected construction costs and timing of projects; completion of midstream
infrastructure by competitors; disruptions due to equipment interruption or failure, including electrical shortages
and power grid failures; the suspension, reduction or termination of MPC’s obligations under the Partnership’s
commercial agreements; modifications to earnings and distribution growth objectives; our ability to manage
112
disruptions in credit markets or changes to our credit rating; compliance with federal and state environmental,
economic, health and safety, energy and other policies and regulations and/or enforcement actions initiated
thereunder; adverse results in litigation; changes to the Partnership’s capital budget; prices of and demand for
natural gas, NGLs, crude oil and refined products, delays in obtaining necessary third-party approvals and
governmental permits, changes in labor, material and equipment costs and availability, planned and unplanned
outages, the delay of, cancellation of or failure to implement planned capital projects, project overruns,
disruptions or interruptions of our operations due to the shortage of skilled labor and unforeseen hazards such as
weather conditions, acts of war or terrorist acts and the governmental or military response, and other operating
and economic considerations. These factors, among others, could cause actual results to differ materially from
those set forth in the forward-looking statements. For additional information on forward-looking statements and
risks that can affect our business, see “Disclosures Regarding Forward-Looking Statements” and Item 1A. Risk
Factors in this Annual Report on Form 10-K.
Effects of Inflation
Inflation did not have a material impact on our results of operations for the years ended December 31, 2017, 2016
or 2015. 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, 2017, MPC owned our general partner, an approximate 28.4 percent limited partner interest
in us, and all of our incentive distribution rights.
Excluding revenues attributable to volumes shipped by MPC under joint tariffs with third parties that are treated
as third-party revenues for accounting purposes, MPC accounted for 36 percent, 41 percent and 82 percent of our
total revenues and other income for 2017, 2016 and 2015, 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 22 percent, 23 percent and 34 percent for 2017, 2016 and
2015, respectively. MPC performed certain services for us related to information technology, engineering, legal,
accounting, treasury, human resources and other administrative services.
We believe that transactions with related parties 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 Transportation and Storage Services Agreements with MPC,—Operating and
Management Services Agreements with MPC and Third Parties,—Other Agreements with MPC 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.
113
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)
2017
2016
2015
Capital
Percent of total capital expenditures
Compliance:
Operating and maintenance
Remediation(1)
Total
$ 5
0%
$ 12
1%
$ 5
1%
$26
4
$30
$ 95
10
$105
$37
10
$47
(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 $13 million in 2018. Actual expenditures
may vary as the number and scope of environmental projects are revised as a result of improved technology or
changes in regulatory requirements and could increase if additional projects are identified or additional
requirements are imposed. The amount of expenditures in 2018 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 (1) 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 (2) 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.
114
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.
115
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Estimates and Assumptions
Acquisitions
In accounting for business
combinations, acquired assets and
liabilities, noncontrolling interests, if
any, and any contingent
consideration are recorded based on
estimated fair values as of the date of
acquisition. 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. Valuation techniques
that maximize the use of observable
inputs are favored.
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, and noncontrolling
interests, if any, is recorded as
goodwill or a bargain purchase gain,
The fair value of assets, liabilities,
including contingent
consideration, and noncontrolling
interests 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 useful life
and obsolescence estimates; and
the market approach which uses
market data and adjusts for entity-
specific differences. Additionally,
for customer contract intangibles
we must estimate the expected life
of the relationship with our
customers on a reporting unit
basis. 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.
If estimates or assumptions used
to complete the purchase price
allocation and estimate the fair
value of acquired assets,
liabilities and noncontrolling
interests significantly differed
from assumptions made, the
allocation of purchase price
between goodwill, intangibles,
noncontrolling interests, equity
method investments and
property plant and equipment
could significantly differ. Such a
difference would impact future
earnings through depreciation
and amortization expense. In
addition, if forecasts supporting
the valuation of the intangibles
or goodwill are not achieved,
impairments could arise.
Further, if customer
relationships terminate prior to
the expected useful life, we will
be required to record a charge to
operations to write-off any
remaining unamortized balance
of the intangible asset assigned
to that customer.
See Item 8. Financial Statements
and Supplementary Data—Note
4 for additional information on
the Ozark pipeline acquisition
completed March 1, 2017, and
the MarkWest Merger that was
completed effective
December 4, 2015.
116
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Estimates and Assumptions
respectively. A significant amount of
judgment is involved in estimating
the individual fair values of property,
plant and equipment, intangible
assets, equity method investments,
contingent consideration, other assets
and liabilities and noncontrolling
interests. We use all available
information to make these fair value
determinations and, for certain
acquisitions, engage third-party
consultants for assistance. We adjust
the preliminary purchase price
allocation, as necessary, after the
acquisition closing date through the
end of the measurement period of up
to one year as we finalize valuations
for the assets acquired, liabilities
assumed, and noncontrolling
interests, if any.
Impairment of Long-Lived Assets
Management evaluates our long-lived
assets, including intangibles, for
impairment when certain events have
taken place that indicate that the
carrying value may not be
recoverable from the expected
undiscounted future cash flows.
Qualitative and quantitative
information is reviewed in order to
determine if a triggering event has
occurred or if an impairment
indicator exists. If we determine that
a triggering event has occurred we
would complete a full impairment
analysis. If we determine that the
carrying value of an asset group is
not recoverable, a loss is recorded for
the difference between the fair value
and the carrying value. We evaluate
our property, plant and equipment
and intangibles on at least a segment
level and at lower levels where cash
flows for specific assets can be
identified, which generally are
groups of similar assets operated in
the same geographic region, and the
As of December 31, 2017, there
were no indicators of
impairment for any of our long-
lived assets.
Management considers the volume
of commodities expected to be
delivered to an asset and future
commodity prices to estimate cash
flows for each asset group.
Management considers the
expected net operating margin to
be earned by customers for each
customer contract intangible.
Management uses discount rates
commensurate with the risks
involved for each asset
considered. The amount of
additional oil and gas developed
by future drilling activity and
expected net operating margin
earned by customer depends, in
part, on expected commodity
prices. Projections of reserves,
drilling activity, ability to renew
contracts of significant customers,
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
117
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Estimates and Assumptions
customer relationship for our
customer contract intangibles.
sustained reduction of commodity
prices in forecasted cash flows.
Impairment of Goodwill
Goodwill is the cost of an acquisition
less the fair value of the net
identifiable assets of the acquired
business. We evaluate goodwill for
impairment annually as of
November 30 and whenever events
or changes in circumstances indicate
it is more likely than not that the fair
value of a reporting unit is less than
its carrying amount. The first step of
the evaluation is a qualitative
analysis to determine if it is “more
likely than not” that the carrying
value of a reporting unit with
goodwill exceeds its fair value. The
additional quantitative steps in the
goodwill impairment test may be
performed if we determine that it is
more likely than not that the carrying
value is greater than the fair value.
Management performed a
quantitative analysis as of
November 30, 2017. We
determined the fair value of our
reporting units using the income
and market approaches for our
2017 impairment analysis. This
type of analysis requires us to
make assumptions and estimates
regarding industry and economic
factors such as relevant
commodity prices, contract
renewals, and production volumes.
It is our policy to conduct
impairment testing based on our
current business strategy in light
of present industry and economic
conditions, as well as future
expectations.
For the 2017 qualitative analysis,
we analyzed the changes in the
assumptions above in light of
current economic conditions to
determine if it was more likely
than not that impairment exists.
We looked at factors, including
changes in the forecasted
operating income and volumes for
the six reporting units with
goodwill, changes in the
commodity price environment,
changes in our per unit market
value, changes in our peers’
market value and changes in
industry EBITDA multiples.
Management is also required to
make certain assumptions when
identifying the reporting units and
determining the amount of
goodwill allocated to each
reporting unit. The method of
allocating goodwill resulting from
the acquisitions involved
118
The Partnership recorded no
impairment charge related to our
annual impairment review of
goodwill as of November 30,
2017. The fair value of the
reporting units for our goodwill
impairment analysis 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
measurement date. The
significant assumptions that
were used to develop the
estimates of the fair values
under the discounted cash flow
method include management’s
best estimates of the expected
future results and discount rates,
which range from 9 percent to
15 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 impairment tests
will prove to be an accurate
prediction of the future.
As of December 31, 2017, the
Partnership had six reporting
units with goodwill: Marcellus
($1.8 billion), East Texas ($228
million), West Texas ($41
million), HSM ($11 million),
MPL ($130 million), and
MPLXT ($21 million). Step 1 of
the fourth quarter impairment
Description
Judgments and Uncertainties
estimating the fair value of the
reporting units and allocating the
purchase price for each acquisition
to each reporting unit. Goodwill is
then calculated for each reporting
unit as the excess of the allocated
purchase price over the estimated
fair value of the net assets.
Effect if Actual Results Differ from
Estimates and Assumptions
analysis resulted in the fair
value of the reporting units
exceeding their carrying value
by approximately 54 percent,
22 percent, 63 percent,
406 percent, 119 percent and
396 percent, respectively. An
increase of 1.50 percent 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 December 31, 2017. Our
2017 analysis resulted in a
significant increase in the fair
value of the reporting units as
compared to the analysis
performed during 2016. This
increase was generally
supported by an increase in our
market capitalization of
approximately 28 percent.
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
producers’ production plans and
commodity prices, for the
reporting units were to decline,
the overall reporting units’ fair
value would decrease, resulting
in potential goodwill
impairment charges.
Additionally, an increase in the
cost of capital would result in a
decrease in the fair value of the
reporting units, causing their
value to decline and goodwill to
potentially be impaired.
Impairment of Equity Method
Investments
We evaluate our equity method
investments for impairment
whenever events or changes in
circumstances indicate, in
management’s judgment, that the
Our impairment assessment
requires us to apply judgment in
estimating future cash flows
received from or attributable to
our equity method investments.
A fixed asset impairment
analysis was performed during
the second quarter of 2016 for
Ohio Condensate Company
(OCC) resulting in an
119
Description
Judgments and Uncertainties
carrying value of such investment
may have experienced a decline in
value. When evidence of an other-
than-temporary loss in value has
occurred, we compare the estimated
fair value of the investment to the
carrying value of the investment to
determine whether impairment
should be recorded.
The primary estimates may
include the expected volumes, the
terms of related customer
agreements and future commodity
prices.
120
Effect if Actual Results Differ from
Estimates and Assumptions
impairment charge of
$96 million within OCC’s
financial statements.
Approximately $58 million of
the charge was attributable to
the Partnership based on its
60 percent ownership of OCC
and was recorded in (Loss)
income from equity method
investments on the
accompanying Consolidated
Statements of Income.
Furthermore, to determine the
potential equity method
impairment charge, an
impairment analysis in
accordance with ASC Topic 323
was performed during the
second quarter of 2016 resulting
in an additional impairment
charge of approximately
$31 million, recorded in (Loss)
income from equity method
investments on the
accompanying Consolidated
Statements of Income.
For purposes of the second
quarter 2016 impairment
analysis, the fair value of OCC
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 significant
assumptions used to estimate the
fair value under the discounted
cash flow method included
management’s best estimates of
the expected results using a
probability weighted average set
of cash flow forecasts and using
a discount rate of 11.2 percent.
Fair value determinations
require considerable judgment
and are sensitive to changes in
underlying assumptions and
factors. As such, the fair value
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Estimates and Assumptions
of the OCC equity method
investment and its underlying
fixed assets represents a Level 3
measurement.
No material events or
circumstances indicated an
other-than-temporary decline in
our equity method investments
during the year ended
December 31, 2017.
Accounting for Risk Management
Activities and Derivative Financial
Instruments
Our derivative financial instruments
are recorded at fair value in the
accompanying Consolidated Balance
Sheets. Changes in fair value and
settlements are reflected in our
earnings in the accompanying
Consolidated Statements of Income
as gains and losses related to
revenue, purchased product costs,
and cost of revenues.
When available, quoted market
prices or prices obtained through
external sources are used to
determine a financial instrument’s
fair value. The valuation of
Level 2 financial instruments is
based on quoted market prices for
similar assets and liabilities in
active markets and other inputs
that are observable. However, for
other financial instruments for
which quoted market prices are
not available, the fair value is
based on inputs that are largely
unobservable such as option
volatilities and NGL prices that
are interpolated and extrapolated
due to inactive markets. These
instruments are classified as
Level 3 under the fair value
hierarchy. All fair value
measurements are appropriately
adjusted for non-performance risk.
If the assumptions used in the
pricing models for our Level 2
and 3 financial instruments are
inaccurate or if we had used an
alternative valuation
methodology, the estimated fair
value may have been different
and we may be exposed to
unrealized losses or gains that
could be material. A 10 percent
difference in our estimated fair
value of Level 2 and 3
commodity derivatives
(excluding embedded
derivatives) at December 31,
2017 would have affected
income before income taxes by
less than $1 million for the year
ended December 31, 2017.
Refer to Accounting for
Significant Embedded
Derivative Instruments for the
sensitivity analysis over our
embedded derivative.
Accounting for Significant Embedded
Derivative Instruments
Identifying embedded derivatives is
complex and requires significant
judgment. We have a gas purchase
agreement with a producer customer
in which we are required to purchase
natural gas based on a complex
We carry the Natural Gas
Embedded Derivative at fair value
with changes in fair value
recognized in income each period.
The valuation requires significant
judgment when forming the
The Natural Gas Embedded
Derivative is an instrument that
is not exchange-traded. The
valuation of the instrument is
complex and requires significant
judgment. The inputs used in the
121
Description
Judgments and Uncertainties
formula designed to share some of
the frac spread with the producer
customer, through December 31,
2022. Additionally, we have a keep-
whole gas processing agreement with
the same producer customer. For
accounting purposes, these two
contracts have been aggregated into a
single contract, and are evaluated
together. The agreements have
primary terms that expire on
December 31, 2022 and contain two
successive term-extending options
under which the producer customer
can extend the purchase and
processing agreements an additional
five years each. Neither contract may
be extended without an election to
extend the other contract.
The feature of the gas purchase
contract to purchase gas based on a
complex formula designed to share
some of the frac spread with the
producer customer and the option to
extend both contracts have been
identified as a single embedded
derivative (“Natural Gas Embedded
Derivative”) that requires a complex
valuation based on significant
judgment. The option to extend the
contracts is part of the embedded
feature and thus is required to be
considered in the valuation of the
embedded derivative. We are
required to make a significant
judgment about the probability that
the option would be exercised when
determining the value of the
embedded derivative.
assumptions used. Third-party
forward curves for certain
commodity prices utilized in the
valuation do not extend through
the term of the arrangement. Thus,
pricing is required to be
extrapolated for those periods. We
utilize multiple cash flow
techniques to extrapolate NGL
pricing. Due to the illiquidity of
future markets, we do not believe
one method is more indicative of
fair value than the other methods.
The Natural Gas Embedded
Derivative is classified as Level 3
under the fair value hierarchy. The
fair value is also appropriately
adjusted for non-performance risk
each period.
We evaluated various factors in
order to determine the probability
that the term-extending options
would be exercised by the
producer customer, such as
estimates of future gas reserves in
the region, the competitive
environment in which the
producer customer operates, the
commodity price environment and
the producer customer’s business
strategy. As of December 31,
2017, we have estimated the
probability that the producer
customer will exercise its option
to extend the agreements for the
first renewal period is 60 percent,
and for the second renewal period
is 80 percent based on the inherent
uncertainty of the variables that
would impact its decision.
Effect if Actual Results Differ from
Estimates and Assumptions
valuation model require
specialized knowledge, as NGL
price curves do not exist for the
entire term of the arrangement.
The valuation is sensitive to
NGL and natural gas future
price curves. Holding the natural
gas curves constant, a 10 percent
increase (decrease) in NGL
price curves causes a $6 million
increase (decrease) in the
liability as of December 31,
2017. Holding the NGL curves
constant, a 10 percent increase
(decrease) in the natural gas
curves causes a $2 million
(decrease) increase in the
liability as of December 31,
2017. The determination of the
fair value of the option to extend
is based on our judgment about
the probability of the producer
customer exercising the
extension. If it were determined
that the probability of exercise
was 25 percent for the first
renewal period and 50 percent
for the second renewal period as
of December 31, 2017, the
liability would be reduced by
$7 million. If it were determined
that the probability of exercise
was 75 percent for the first
renewal period and 100 percent
for the second renewal period as
of December 31, the liability
would be increased by
$10 million.
See Item 8. Financial Statements
and Supplementary Data—Note
16 for more information related
to the Natural Gas Embedded
Derivative.
Variable Interest Entities
We evaluate all legal entities in
which we hold an ownership or other
Significant judgment is exercised
in determining that a legal entity is
MarkWest Utica EMG is our
most significant VIE; Ohio
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Description
Judgments and Uncertainties
pecuniary interest to determine if the
entity is a VIE.
a VIE and in evaluating our
interest in 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 (a) the power to
direct the activities of the VIE that
most significantly impact the VIE’s
economic performance and (b) 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 (i.e. where we are
not the primary beneficiary).
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.
123
Effect if Actual Results Differ from
Estimates and Assumptions
Condensate, Jefferson Dry Gas,
and Sherwood Midstream are
also VIEs. We are not
considered to be the primary
beneficiary for any of the
entities. As a result, they are
accounted for under the equity
method. Changes in the design
or nature of the activities of
these VIEs, 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.
Ohio Gathering is a subsidiary
of MarkWest Utica EMG and is
a VIE. Sherwood Midstream
Holdings is a subsidiary of
Sherwood Midstream and is a
VIE. If there were a change in
consolidation conclusions for
MarkWest Utica EMG or
Sherwood Midstream, Ohio
Gathering or Sherwood
Midstream Holdings would need
to be assessed for consolidation
or deconsolidation, respectively.
MarkWest Ohio Fractionation is
a VIE and MPLX LP is
considered the primary
beneficiary. As a result, it is
consolidated by MPLX LP.
We account for our ownership
interests in MarEn Bakken and
Centrahoma under the equity
method and have determined
that these entities are not VIEs.
Description
Judgments and Uncertainties
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
can be reasonably estimated.
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
124
Effect if Actual Results Differ from
Estimates and Assumptions
However, changes in the design
or nature of the activities of
either entity may require us to
reconsider our conclusions.
Such reconsideration would
require the identification of the
variable interests in the entity
and a determination on which
party is the entity’s primary
beneficiary. If an equity
investment were considered a
VIE and we were determined to
be the primary beneficiary, the
change could cause us to
consolidate the entity. The
consolidation of an entity that is
currently accounted for under
the equity method could have a
significant impact on our
financial statements.
See Item 8. Financial Statements
and Supplementary Data—Note
5 for more information on our
other investments.
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 23.
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Estimates and Assumptions
interpretation, additional
information on the extent and
nature of site contamination and
improvements in technology.
Recent Accounting Pronouncements
From time to time, new accounting pronouncements are issued by the FASB that we adopt as of the specified
effective date. If not discussed in Item 8. Financial Statements and Supplementary Data—Note 3, management
believes that the impact of recently issued standards, which are not yet effective, will not have a material impact
on our financial statements upon adoption.
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 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, 2017,
we did not have any financial derivative instruments to economically hedge the risks related to interest rate
fluctuations; however, we continually monitor the market and our exposure and may enter into these
arrangements in the future. We are at risk for changes in fair value of all our derivative instruments; however,
such risk should be mitigated by price or rate changes related to the underlying commodity or financial
transaction.
Commodity Price Risk
We 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.
Derivative contracts utilized are primarily swaps traded on the OTC market and fixed price forward contracts.
The 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 current derivative positions, we have mitigated a portion of our expected commodity price risk
through the fourth quarter of 2018. 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
125
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
The following tables provide information on the volume of our derivative activity for positions related to long
liquids price risk at December 31, 2017, including the weighted-average prices (“WAVG”):
Natural Gas Swaps
2018
Propane Swaps
2018
IsoButane Swaps
2018
Volumes (MMBtu/d)
WAVG Price(Per MMBtu)
Fair Value
(in thousands)
2,542
$2.78
$ (212)
Volumes (Gal/d)
WAVG Price(Per Gal)
Fair Value
(in thousands)
16,925
$0.64
$(1,238)
Volumes (Gal/d)
WAVG Price(Per Gal)
Fair Value
(in thousands)
1,655
$0.80
$ (102)
Normal Butane Swaps
Volumes (Gal/d)
WAVG Price(Per Gal)
Fair Value
(in thousands)
2018
4,595
$0.75
$ (297)
Natural Gasoline Swaps
Volumes (Gal/d)
WAVG Price(Per Gal)
Fair Value
(in thousands)
2018
3,089
$1.18
$ (210)
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 in the Consolidated Statements of
Income. As of December 31, 2017 and 2016, the estimated fair value of this contract was a liability of
$64 million and $54 million, respectively.
During the year ending December 31, 2017, we had a commodity contract that gave us an option to fix a
component of the utilities cost to an index price on electricity at a plant location in the Southwest that expired as
of December 31, 2017. Changes in the fair value as of the derivative component of this contract were recognized
as Cost of Revenues in the Consolidated Statements of Income.
Open Derivative Positions and Sensitivity Analysis
The following table sets forth information relating to our significant open commodity derivative contracts as of
December 31, 2017.
Natural Gas (MMBtu)
NGLs (gal)
126
Financial
Position
Notional
Quantity (net)
Weighted
Average Price
Long
Short
928,003
9,586,503
$2.78
$0.73
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 10 percent difference in our estimated fair value of Level 2 and 3
commodity derivatives (excluding embedded derivatives) at December 31, 2017 would have affected income
before income taxes by less than $1 million for the year ended December 31, 2017. We evaluate our portfolio of
commodity derivative instruments on an ongoing basis and add or revise strategies in anticipation of changes in
market conditions and in risk profiles.
Interest Rate Risk
Sensitivity analysis of the effect of a hypothetical 100-basis-point change in interest rates on long-term debt,
excluding 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, 2017(1) Change in Fair Value (2)
Change in Income before
income taxes for the
Year Ended
December 31, 2017 (3)
$7,213
$ 505
$569
N/A
N/A
3
$
(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, 2017.
(3) Assumes a 100-basis-point change in interest rates. The change to net income was based on the weighted
average balance of all outstanding variable-rate debt for the year ended December 31, 2017.
At December 31, 2017, our portfolio of long-term debt consisted of fixed-rate instruments and variable-rate
instruments under our revolving credit facility. 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, 2017, we did not have any financial derivative
instruments to hedge the risks related to interest rate fluctuations; however, we continually monitor the market
and our exposure and may enter into these agreements 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.
127
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.
128
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 Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Equity
Notes to Consolidated Financial Statements
Select Quarterly Financial Data (Unaudited)
Page
130
130
131
133
134
135
136
137
196
129
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, 2017.
The effectiveness of MPLX LP’s internal control over financial reporting as of December 31, 2017 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)
130
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 as of
December 31, 2017 and 2016, and the related consolidated statements of income, of equity and of cash flows for
each of the three years in the period ended December 31, 2017, 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, 2017, 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, 2017 and 2016, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2017 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, 2017, based on criteria
established in Internal Control—Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective
internal control over financial reporting, and for its assessment of the effectiveness of internal control over
financial reporting, included in the accompanying Management’s Report on Internal Control over Financial
Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on
the Company’s internal control over financial reporting based on our audits. We are a public accounting firm
registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to
be independent with respect to the Company in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are
free of material misstatement, whether due to error or fraud, and whether effective internal control over financial
reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material
misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures
that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts
and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of
the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary in the circumstances. We
believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail,
131
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, 2018
We have served as the Company’s auditor since 2012.
132
MPLX LP
Consolidated Statements of Income
(In millions, except per unit data)
Revenues and other income:
Service revenue
Service revenue—related parties
Rental income
Rental income—related parties
Product sales
Product sales—related parties
Gain on sale of assets
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 $32 million, $28 million,
$5 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
$
2017
2016
2015
$
$ 1,156
1,082
277
279
889
8
—
78
6
92
$
958
936
298
235
572
11
1
(74)
6
86
130
701
20
146
36
1
—
3
6
58
3,867
3,029
1,101
528
651
62
2
455
683
—
241
54
454
448
57
1
388
591
130
227
50
2,676
1,191
2
2,346
683
1
296
56
837
1
836
6
36
794
65
318
411
210
50
422
(12)
434
2
199
233
41
191
$
1
$
247
20
11
1
172
129
—
125
15
720
381
—
35
12
334
1
333
1
176
156
—
57
99
Per Unit Data (See Note 7)
Net income attributable to MPLX LP per limited partner unit:
Common—basic
Common—diluted
Subordinated—basic and diluted
Weighted average limited partner units outstanding:
Common—basic
Common—diluted
Subordinated—basic and diluted
Cash distributions declared per limited partner common unit
$ 1.07
1.06
—
$ — $
—
—
1.23
1.22
0.11
385
388
—
$2.2975
331
338
—
$2.0500
79
80
18
$1.8200
The accompanying notes are an integral part of these consolidated financial statements.
133
MPLX LP
Consolidated Balance Sheets
(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
Deferred revenue—related parties
Accrued property, plant and equipment
Accrued taxes
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
Commitments and contingencies (see Note 23)
Redeemable preferred units
Equity
Common unitholders—public (289 million and 271 million units issued and outstanding)
Class B unitholders (0 million and 4 million units issued and outstanding)
Common unitholder—MPC (95 million and 86 million units issued and outstanding)
Common unitholder—GP (23 million and 0 units issued and outstanding)
General partner—MPC (8 million and 7 million units issued and outstanding)
Accumulated other comprehensive loss
Equity of Predecessor
Total MPLX LP partners’ capital
Noncontrolling interests
Total equity
Total liabilities, preferred units and equity
December 31,
2017
2016
$
5
292
160
65
37
559
4,010
12,187
453
2,245
20
26
$19,500
$
234
299
247
55
33
868
2,471
11,408
492
2,245
11
14
$17,509
$
151
231
516
5
43
194
38
88
38
1,304
42
43
6,945
5
188
8,527
$
140
232
87
2
38
146
38
53
27
763
12
19
4,422
6
177
5,399
1,000
1,000
8,379
—
1,278
821
(637)
(14)
—
9,827
146
9,973
$19,500
8,086
133
1,069
—
1,013
—
791
11,092
18
11,110
$17,509
The accompanying notes are an integral part of these consolidated financial statements.
134
MPLX LP
Consolidated Statements of Cash Flows
(In millions)
(Decrease) increase in cash and cash equivalents
Operating activities:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred financing costs
Depreciation and amortization
Impairment expense
Deferred income taxes
Asset retirement expenditures
Gain on disposal of assets
(Income) loss 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
Net cash provided by operating activities
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
Issuance of units in MarkWest Merger
Contributions from MPC—MarkWest Merger
Distributions to preferred unitholders
Distributions of cash received from joint-interest acquisition entities to MPC
Distribution to MPC for acquisition
Distributions to unitholders and general partner
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Consideration payment to Class B unitholders
Contribution from MPC
Distributions related to purchase of additional interest in Pipe Line Holdings
Distributions to MPC from Predecessor
All other, net
Net cash provided by financing activities
Net (decrease) increase in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
2017
2016
2015
$
836
$
434
$
333
53
683
—
(1)
(2)
—
(78)
241
8
(3)
6
48
63
(8)
33
28
1,907
(1,411)
(249)
80
7
(761)
26
1
(2,307)
2,911
(416)
2,369
(1,983)
(29)
483
—
—
—
(65)
(20)
(1,931)
(1,120)
(7)
129
(25)
—
—
(113)
(12)
171
(229)
234
5
$
46
591
130
(17)
(6)
(1)
74
148
(52)
(8)
43
102
(19)
—
10
16
1,491
(1,313)
—
(17)
1
(87)
—
3
(1,413)
434
(1,312)
2,532
(2,540)
—
792
984
—
—
(25)
—
—
(845)
(3)
6
(25)
225
—
(104)
(6)
113
191
43
234
$
5
129
—
1
(1)
—
(3)
15
(29)
1
(6)
5
(34)
—
4
7
427
(334)
(1,218)
(118)
—
(14)
—
(2)
(1,686)
1,490
(1,441)
301
(293)
(11)
1
—
169
1,230
—
—
—
(158)
(1)
—
—
1
(12)
—
(1)
1,275
16
27
43
$
The accompanying notes are an integral part of these consolidated financial statements.
135
MPLX LP
Consolidated Statements of Equity
Partnership
Common
Unitholders
Public
$ 639
Class B
Unitholders
Public
$ —
Common
Unitholder
MPC
$ 261
Subordinated
Unitholder
MPC
$ 217
—
—
1
15
(40)
—
—
—
—
17
(1)
7,060
—
7,691
—
—
—
—
776
(5)
—
(513)
—
—
133
—
6
(2)
8,086
—
—
—
473
301
—
—
(622)
—
—
133
8
$8,379
—
—
—
—
—
—
—
—
—
—
—
266
—
266
—
—
—
—
—
—
—
—
—
—
(133)
—
—
—
133
—
—
—
—
—
—
—
—
—
—
—
—
36
(52)
—
220
—
—
—
—
—
—
465
—
84
—
—
—
6
669
(142)
—
—
—
—
—
(13)
1,069
—
—
—
—
98
845
(537)
(197)
—
—
—
—
48
(45)
—
(220)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(133)
—
$ —
—
—
—
$1,278
—
—
—
$ —
Common
Unitholder
GP
$— $ (660)
General
Partner
MPC
Accumulated
Other
Comprehensive
Loss
$—
Non-controlling
Interests
Equity of
Predecessor Total
$
6
$
321
$
784
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
12
824
—
(6)
1,280
—
57
(21)
—
—
—
—
—
—
169
—
819
—
141
(188)
563
16
191
(337)
(190)
—
—
—
—
—
(2)
1,013
—
(32)
—
10
318
(266)
(1,394)
(15)
(286)
—
—
—
—
$821
—
—
—
—
$ (637)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(14)
—
—
—
—
—
—
—
—
—
$ (14)
(6)
—
—
1
—
(1)
—
—
—
—
—
—
13
13
—
—
—
—
—
2
—
—
(3)
6
—
—
—
—
18
—
—
—
—
6
—
—
—
(7)
129
—
—
$146
—
—
—
176
—
—
—
1
194
—
—
—
—
692
(104)
—
—
—
—
199
(332)
—
—
—
—
336
—
—
791
(12)
1,280
1
333
(158)
(1)
—
1
194
17
(1)
7,495
13
9,946
(104)
225
(188)
563
792
393
—
(845)
(3)
6
—
336
6
(17)
11,110
(113)
(113)
—
689
—
36
(1,403)
—
—
—
(32)
675
483
771
—
(1,931)
(1,120)
(7)
—
—
—
129
—
8
$ — $ 9,973
(In millions)
Balance at December 31, 2014
Purchase of additional interest in
Pipe Line Holdings
Contributions from MPC—
MarkWest Merger
Issuance of units under ATM
Program
Net income
Distributions to unitholders and
general partner
Distributions to noncontrolling
interests
Subordinated unit conversion
Contribution from MPC
Non-cash contribution from MPC
Equity-based compensation
Deferred income tax impact from
changes in equity
Issuance of units in MarkWest
Merger
Noncontrolling interests assumed
in MarkWest Merger
Balance at December 31, 2015
Distributions to MPC from
Predecessor
Contribution from MPC
Contribution of MarkWest
Hydrocarbon from MPC
Distribution of MarkWest
Hydrocarbon to MPC
Issuance of units under ATM
Program
Net (loss) income
Allocation of MPC’s net
investment at acquisition
Distributions to unitholders and
general partner
Distributions to noncontrolling
interests
interests
Contributions from noncontrolling
Class B unit conversion
Non-cash contribution from MPC
Equity-based compensation
Deferred income tax impact from
changes in equity
Balance at December 31, 2016
Distributions to MPC from
Predecessor
Distributions of cash received from
Joint-Interest Acquisition
entities to MPC
Contribution from MPC
Issuance of units under ATM
Program
Net income
Allocation of MPC’s net
investment at acquisition
Distribution to MPC for
acquisitions
Distributions to unitholders and
general partner
Distributions to noncontrolling
Contributions from noncontrolling
interests
interests
Class B unit conversion
Equity-based compensation
Balance at December 31, 2017
The accompanying notes are an integral part of these consolidated financial statements.
136
Notes to Consolidated Financial Statements
1. Description of the Business and Basis of Presentation
Description of the Business—MPLX LP is a diversified, growth-oriented master limited partnership formed by
Marathon Petroleum Corporation. MPLX LP and its subsidiaries (collectively, the “Partnership”) are 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, principally for our sponsor. References to “MPC” refer collectively to Marathon Petroleum
Corporation and its subsidiaries, other than the Partnership. The Partnership’s principal executive office is
located in Findlay, Ohio.
The Partnership was formed on March 27, 2012 as a Delaware limited partnership and completed its Initial
Offering on October 31, 2012. On December 4, 2015, the MarkWest Merger occurred, in which a wholly-owned
subsidiary of the Partnership merged with MarkWest Energy Partners L.P. (“MarkWest”), one of the largest
processors of natural gas in the United States and the largest processor and fractionator in the Marcellus and
Utica shale plays. Effective March 31, 2016, the Partnership acquired MPC’s inland marine business, Hardin
Street Marine LLC (“HSM”). Effective March 1, 2017, the Partnership acquired pipeline, storage and terminal
businesses that are operated through Hardin Street Transportation LLC (“HST”), Woodhaven Cavern LLC
(“WHC”) and MPLX Terminals LLC (“MPLXT”) from MPC. Effective September 1, 2017, the Partnership
acquired certain ownership percentages in joint venture entities from MPC: all of the membership interests of
Lincoln Pipeline LLC, which holds a 35 percent interest in Illinois Extension Pipeline Company, L.L.C. (“Illinois
Extension”); all of the membership interests of MPL Louisiana Holdings LLC, which holds a 41 percent interest
in LOOP LLC (“LOOP”); a 59 percent interest in LOCAP LLC (“LOCAP”); and a 25 percent interest in
Explorer Pipeline Company (“Explorer”). These acquisitions, along with the MarkWest Merger, are described
further in Note 4.
The Partnership’s business consists of two segments based on the nature of services it offers: Logistics and
Storage (“L&S”), which is focused on crude oil and refined petroleum products, and Gathering and Processing
(“G&P”), which is focused on natural gas and NGLs. See Note 10 for additional information regarding
operations.
Basis of Presentation—The Partnership’s consolidated financial statements include all majority-owned and
controlled subsidiaries. For non-wholly-owned consolidated subsidiaries, the interests owned by third parties
have been recorded as Noncontrolling interests in the accompanying Consolidated Balance Sheets. Intercompany
investments, accounts and transactions have been eliminated. The Partnership’s investments in which the
Partnership exercises significant influence but does not control and does not have a controlling financial interest
are accounted for using the equity method. The Partnership’s investments in a VIE in which the Partnership
exercises significant influence but does not control and is not the primary beneficiary are also accounted for
using the equity method. The accompanying consolidated financial statements of the Partnership 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; valuing inventory;
evaluating impairments of long-lived assets, goodwill and equity investments; establishing estimated useful lives
137
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—The Partnership’s assessment of each of the revenue recognition criteria as they relate to
its revenue producing activities are as follows: persuasive evidence of an arrangement exists, delivery, the fee is
fixed or determinable and collectability is reasonably assured. It is upon delivery or title transfer to the customer
that the Partnership meets all four revenue recognition criteria and it is at such time that the Partnership
recognizes Product sales. Additionally, it is upon completion of services provided that the Partnership meets all
four revenue recognition criteria and it is at such time that the Partnership recognizes Service revenue. The
Partnership also recognizes Rental income over the term of implicit operating leases generating this revenue, as
discussed below.
The Partnership generates revenue in the following ways:
• Crude Oil and Refined Product Pipeline Transportation—Revenues are recognized in the L&S
segment for crude oil and product pipeline transportation based on the delivery of actual volumes
transported at regulated tariff rates or at contractually agreed upon rates. These amounts are reported as
Service revenue or Service revenue—related parties on the Consolidated Statements of Income.
Under our MPC transportation service agreements, if MPC fails to transport its minimum throughput
volumes during any quarter, then MPC will pay us a deficiency payment, as described in Note 6. The
deficiency payments are initially recorded as Deferred revenue—related parties in the Consolidated
Balance Sheets. The Partnership recognizes revenues for the deficiency payments at the earlier of when
credits are used for volumes transported in excess of minimum volume commitments, when it becomes
impossible to physically transport volumes necessary to utilize the credits or upon the expiration of the
applicable four-quarter or eight-quarter period. In addition, capital projects the Partnership undertakes
at the request of MPC are reimbursed in cash and recognized in income over the remaining term of the
applicable transportation services agreements.
• Crude Oil and Refined Product Storage—Revenues are recognized in the L&S segment for crude oil
and refined product storage as performed based on contractual rates. Revenue from storage services is
reported as Service revenue or Service revenue—related parties on the Consolidated Statements of
Income.
• Crude Oil and Refined Product Marine Transportation—Revenues are recognized in the L&S segment
for marine transportation services for the transportation of cargo from a designated origin to a
designated destination at a pre-established fixed rate. These amounts are reported as Service revenue,
Service revenue—related parties, Rental income, or Rental income—related parties on the
Consolidated Statements of Income.
•
Terminal Services Agreement—Revenues are recognized in the L&S segment for the operation,
storage, and other terminal related services, primarily performed for MPC, based on the receipt of
actual throughput volumes at a fixed contractual fee. All such amounts are reported as Service
revenue—related parties on the Consolidated Statements of Income. In addition, if MPC fails to meet
its minimum volume commitment during any quarter, then MPC will pay the Partnership a deficiency
payment equal to the volume of the deficiency multiplied by the contractual fee then in effect. The
deficiency payments are recorded as Deferred revenue—related parties in the Consolidated Balance
Sheets. Revenue for the deficiency payments is recognized at the end of each quarter that MPC does
not meet its minimum volume commitment. Contingent revenue is recognized for volume throughput
above MPC’s minimum volume commitment, and is reported as Rental income—related parties on the
Consolidated Statements of Income.
• Operating Services Agreements—Revenues are recognized in the L&S segment for providing operation
and maintenance services for various pipelines owned by MPC and third parties, based on negotiated
fees. All such amounts are reported as Service revenue or Service revenue—related parties on the
Consolidated Statements of Income.
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• Fee-based arrangements—Revenues are recognized in the G&P segment for gathering, processing,
transportation, fractionation, exchange and storage of natural gas, NGL’s or crude oil based on the
volume of natural gas, NGLs or crude oil that flows through the Partnership’s systems and facilities. In
certain cases, the arrangements provide for minimum annual payments or fixed demand charges.
Revenue generated under these agreements is generally reported as Service revenue on the
Consolidated Statements of Income. In certain instances, the Partnership purchases product after
fee-based services have been provided. Revenue from the sale of such product is reported as Product
sales or Product sales—related parties on the Consolidated Statements of Income and recognized on a
gross basis as the Partnership is the principal in the transactions.
• Percent-of-proceeds arrangements—Under percent-of-proceeds arrangements in the G&P segment, the
Partnership 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, the Partnership delivers an
agreed-upon percentage of the residue gas and NGLs to the producer (take-in-kind arrangements) and
sells the volumes the Partnership retains to third parties. Revenue from these arrangements is reported
on a gross basis where the Partnership acts as the principal, as the Partnership has physical inventory
risk and does not earn a fixed dollar amount. The agreed-upon percentage paid to the producer is
reported as Purchased product costs on the Consolidated Statements of Income. Revenue is recognized
on a net basis when the Partnership acts as an agent and earns a fixed dollar amount of physical product
and does not have risk of loss of the gross amount of gas and/or NGLs. Percent-of-proceeds revenue is
reported as Product sales on the Consolidated Statements of Income.
• Keep-whole arrangements—Under keep-whole arrangements in the G&P segment, the Partnership
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, the Partnership must either
purchase natural gas at market prices for return to producers or make cash payment to the producers
equal to the energy content of this natural gas. Certain keep-whole arrangements also have provisions
that require the Partnership 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. 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 the
Partnership is the principal in the arrangement. Natural gas purchased to return to the producer and
shared NGL profits are recorded as Purchased product costs in the Consolidated Statements of Income.
• Purchase arrangements—Under purchase arrangements in the G&P segment, the Partnership
purchases natural gas and/or NGLs at either (1) a percentage discount to a specified index price, (2) a
specified index price less a fixed amount or (3) a percentage discount to a specified index price less an
additional fixed amount. The Partnership may purchase product at the inlet or outlet of the facility. The
Partnership then resells the natural gas or NGLs at the index price or at a different percentage discount
to the index price. Revenue generated from purchase arrangements are reported as Product sales on the
Consolidated Statements of Income and are recognized on a gross basis as the Partnership purchases
and takes title to the product prior to sale and is the principal in the transaction.
In many cases, the Partnership 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 keep-whole
arrangements, percent-of-proceeds arrangements or percent-of-index arrangements, the Partnership records such
fees as Service revenue on the Consolidated Statements of Income.
Amounts billed to customers for shipping and handling, including fuel costs, are included in Product sales on the
Consolidated Statements of Income, except under contracts where we are acting as an agent. Shipping and
handling costs associated with product sales are included in Purchased product costs on the Consolidated
Statements of Income. Taxes collected from customers and remitted to the appropriate taxing authority are
139
excluded from revenue. Facility expenses and depreciation represent those expenses related to operating our
various facilities and are necessary to provide both Product sales and Service revenue.
Based on the terms of certain agreements we are considered to be a lessor under several implicit operating lease
arrangements in accordance with GAAP. In the L&S segment, these agreements primarily include fee-based
transportation and storage services agreements with MPC, under which we are considered to be a lessor of our
pipelines, marine equipment, terminals and storage facilities. Our implicit lease arrangements contain contingent
rental provisions whereby we receive additional fees if the customer exceeds the monthly minimum throughput
volumes. In the G&P segment, these agreements primarily 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. This agreement includes provisions to increase the fixed-fee as the gathering system
is expanded. Other significant implicit leases relate to natural gas processing agreements in the Marcellus Shale
and Southern Appalachia region for which the Partnership earns minimum monthly fees for providing processing
services to a single producer using a dedicated processing plant. Revenue generated under implicit lease
arrangements is reported as Rental income or Rental income—related parties on the Consolidated Statements of
Income. Expenses generated in order to facilitate these agreements are reported as Rental cost of sales or Rental
cost of sales—related parties.
Revenue and Expense Accruals—The Partnership 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 the Partnership’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. The
Partnership 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 the
Partnership’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, 2017 and 2016,
the amount of restricted cash included in Other current assets on the Consolidated Balance Sheets was $4 million
and $5 million, respectively.
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 weighted-average cost or net
realizable value. Materials and supplies are stated at the lower of cost or net realizable value. Cost for materials
and supplies are determined primarily using the weighted-average cost method. Processed natural gas and NGL
inventories include material, labor and overhead. Shipping and handling costs related to purchases of natural gas
and NGLs are included in inventory.
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
140
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. Expenditures that extend
the useful lives of assets are capitalized. Repairs, maintenance and renewals that do not extend the useful lives of
the assets are expensed as incurred. Interest costs for the construction or development of long-lived assets are
capitalized and amortized over the related asset’s estimated useful life. Leasehold improvements are amortized
over the shorter of the useful life or lease term.
When items of property, plant and equipment are sold or otherwise disposed of, any gains or losses are reported
in 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. The Partnership evaluates transactions involving the
sale of property, plant and equipment to determine if they are in-substance, the sale of real estate. Tangible assets
may be considered real estate if the costs to relocate them for use in a different location exceed 10 percent of the
asset’s fair value. Financial assets, primarily in the form of ownership interests in an entity, may be in-substance
real estate based on the significance of the real estate in the entity. Sales of real estate are not considered
consummated if the Partnership maintains an interest in the asset after it is sold or has certain other forms of
continuing involvement. Significant judgment is required to determine if a transaction is a sale of real estate and
if a transaction has been consummated. If a sale of real estate is not considered consummated, the Partnership
cannot record the transaction as a sale and must account for the transaction under an alternative method of
accounting such as a financing or leasing arrangement.
The Partnership’s policy is to evaluate whether there has been an impairment in the value of long-lived assets
when certain events indicate that the remaining balance may not be recoverable. Qualitative and quantitative
information is reviewed in order to determine if a triggering event has occurred or if an impairment indicator
exists. If we determine that a triggering event has occurred we would complete a full impairment analysis. If we
determine that the carrying value of a reporting unit is not recoverable, a loss is recorded for the difference
between the fair value and the carrying value. The Partnership evaluates the carrying value of its property, plant
and equipment on at least a segment level and at lower levels where the cash flows for specific assets can be
identified, which generally is the component level for our G&P and L&S segments. Management considers the
dedicated volume of producer customers’ reserves and future NGL product and natural gas prices to estimate
cash flows. The amount of additional producer customers’ reserves developed by future drilling activity depends,
in part, on expected commodity prices. Projections of producer customers’ reserves, drilling activity and future
commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are
difficult to forecast. Any significant variance in any of these assumptions or factors could materially affect future
cash flows, which could result in the impairment of an asset group.
For assets identified to be disposed of in the future, the carrying value of these assets is compared to the
estimated fair value, less the cost to sell, to determine if impairment is required. Until the assets are disposed of,
an estimate of the fair value is redetermined when related events or circumstances change.
Intangibles—The Partnership’s intangibles are mainly comprised of customer contracts and related relationships
acquired in business combinations and recorded under the acquisition method of accounting at their estimated
fair values at the date of acquisition. Using relevant information and assumptions, management determines the
fair value of acquired identifiable intangible assets. Fair value was calculated using the multi-period excess
earnings method under the income approach for each reporting unit. This valuation method is based on first
forecasting gross profit for the existing customer base and then applying expected attrition rates. The operating
cash flows are calculated by determining the costs required to generate gross profit from the existing customer
base. The key assumptions include overall gross profit growth, attrition rate of existing customers over time and
the discount rate. Amortization of intangibles with definite lives is calculated using the straight-line method
141
which is reflective of benefit pattern in which the estimated economic benefit is expected to be received over the
estimated useful life of the intangible asset. The estimated economic life is determined by assessing the life of the
assets related to the contracts and relationships, likelihood of renewals, the projected reserves, competitive
factors, regulatory or legal provisions and maintenance and renewal costs.
Intangibles with indefinite lives 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. The Partnership has no intangibles with indefinite lives.
Goodwill—Goodwill is the cost of an acquisition less the fair value of the net identifiable assets and
noncontrolling interests, if any, of the acquired business. The Partnership evaluates goodwill for impairment
annually as of November 30, and whenever events or changes in circumstances indicate it is more likely than not
that the fair value of a reporting unit is less than its carrying amount. The Partnership determined its reporting
units based on the criteria included in ASC 280 which requires a component to be a business with discrete
financial information that management reviews on a regular basis. Management reviews its determination of
reporting units on an annual basis. The Partnership may first assess qualitative factors to evaluate whether it is
more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for
determining whether it is necessary to perform the two-step goodwill impairment test. The Partnership may elect
to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step
process goodwill impairment test is elected or required, the first step involves comparing the fair value of the
reporting unit to which goodwill has been allocated, with its carrying amount. If the carrying amount of a
reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to
the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit
exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is
recognized as an impairment loss. During 2016, impairment charges of approximately $130 million were
recorded. There were no impairments as a result of the Partnership’s November 30, 2017 and November 30, 2016
annual goodwill impairment analyses.
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. The Partnership
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. The
Partnership 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.
142
Investment in Unconsolidated Affiliates—Equity investments in which the Partnership 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 in 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.
The Partnership 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. The Partnership 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—The Partnership 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. The Partnership 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 in the Consolidated Statements of Income in accounts related to the item whose value or
cash flows are being managed. All derivative instruments were marked to market through Product sales,
Purchased product costs, or Cost of revenues on the Consolidated Statements of Income. Revenue gains and
losses relate to contracts utilized to manage the cash flow for the sale of a product, typically NGLs. Purchased
product costs gains and losses relate to contracts utilized to manage the cost of natural gas purchases, typically
related to keep-whole arrangements. Cost of revenues gains and losses relate to a contract utilized to manage
electricity costs. Changes in risk management for unrealized activities are reported as an adjustment to net
income in computing cash flow from operating activities on the accompanying Consolidated Statements of Cash
Flows.
During the years ended December 31, 2017, 2016 and 2015, the Partnership did not elect hedge accounting for
any derivatives. The Partnership 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 15). Derivative instruments are recorded at fair value, based on available market information (see
Note 16).
Fair Value Measurement—Financial assets and liabilities recorded at fair value in the Consolidated Balance
Sheets are categorized based upon the fair value hierarchy established by GAAP, which classifies the inputs used
to measure fair value into Level 1, Level 2 or Level 3. A financial instrument’s categorization within the
valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The
methods and assumptions utilized may produce a fair value that may not be realized in future periods upon
settlement. Furthermore, while the Partnership 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
143
financial instruments could result in a different estimate of fair value at the reporting date. For further discussion
see Note 15.
Equity-Based Compensation Arrangements—The Partnership issues phantom units under its share-based
compensation plan as described further in Note 20. 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, the Partnership 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—The Partnership 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 in the accompanying
Consolidated Balance Sheets.
Income Taxes—The Partnership is not a taxable entity for federal income tax purposes. As a result of the
MarkWest Merger, discussed further in Note 4, MarkWest was the surviving entity for tax purposes. MarkWest
is not a taxable entity for federal income tax purposes. As such, the Partnership does not directly pay federal
income tax. Taxes on the Partnership’s net income generally are borne by its partners through the allocation of
taxable income. The Partnership’s taxable income or loss, which may vary substantially from the net income or
loss reported in the Consolidated Statements of Income, is includable in the federal income tax returns of each
partner. The Partnership and certain legal entities are, however, taxable entities under certain state jurisdictions.
As a result of the Class A Reorganization discussed in Note 8, MarkWest Hydrocarbon, L.L.C. (“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 the Partnership, even though for financial
reporting purposes such income or loss was eliminated in consolidation. The Class A units represented limited
partner interests with the same rights as common units except that the Class A units did not have voting rights,
except as required by law. Class A units were not treated as outstanding common units in the Consolidated
Balance Sheets as they were eliminated in the consolidation of MarkWest Hydrocarbon. 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 the Partnership 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 the Partnership.
The Partnership 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
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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 IDRs are made, earnings
equal to the amount of those distributions are first allocated to the general partner before the remaining earnings
are allocated to the limited partner unitholders based on their respective ownership percentages. The allocation of
net income attributable to MPLX LP for purposes of calculating net income per limited partner unit is described
in below.
Net Income Per Limited Partner Unit—The Partnership 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, subordinated units, general partner units, preferred
units, certain equity-based compensation awards and 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, when distributions related to the IDRs are made, earnings
equal to the amount of those distributions are first allocated to the general partner before the remaining earnings
are allocated to the unitholders, except Class B unitholders, based on their respective ownership percentages.
In preparing net income per limited partner units, during periods in which a net loss attributable to the
Partnership is reported or periods in which the total distributions exceed the reported net income attributable to
the Partnership’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 the Partnership’s common unitholders, after deducting amounts allocable to other
participating securities, by the weighted average number of common units and potential common units
outstanding during the period. Potential common units are excluded from the calculation of diluted earnings per
unit during periods in which net income attributable to the Partnership’s unitholders, after deducting amounts that
are allocable to the outstanding equity-based compensation awards, Preferred units, and IDRs, is a loss as the
impact would be anti-dilutive.
Business Combinations—The Partnership 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, the Partnership will record any material adjustments to the initial
estimate based on new information obtained about facts and circumstances that existed as of the acquisition
date. An income, market or cost valuation method may be utilized to estimate the fair value of the assets
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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—The Partnership’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 in 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
In October 2016, the FASB issued an accounting standards update to amend the consolidation guidance issued in
February 2015 to require that a decision maker consider, in the determination of the primary beneficiary, its
indirect interest in a VIE held by a related party that is under common control on a proportionate basis only. The
change was effective for the financial statements for fiscal years beginning after December 15, 2016, and interim
periods within those fiscal years. The Partnership was required to apply the standard retrospectively to January 1,
2016, the date on which the Partnership adopted the consolidation guidance issued in February 2015. The
Partnership adopted this accounting standards update in the first quarter of 2017 and it did not have an impact on
the consolidated financial statements.
In March 2016, the FASB issued an accounting standards update on the accounting for employee share-based
payments. This update requires the recognition of income tax effects of awards through the income statement
when awards vest or are settled. It also increases the amount an employer can withhold for tax purposes without
triggering liability accounting. Lastly, it allows employers to make a policy election to account for forfeitures as
they occur. The changes were effective for fiscal years beginning after December 15, 2016, and interim periods
within those fiscal years. Under the new guidance, the Partnership will continue estimating forfeiture rates to
calculate compensation cost. The Partnership adopted this accounting standards update in the first quarter of
2017 and it did not have a material impact on the consolidated financial statements.
Not Yet Adopted
In August 2017, the FASB issued an accounting standards update to amend the hedge accounting rules to
simplify the application of hedge accounting guidance and better portray the economic results of risk
management activities in the financial statements. The guidance expands the ability to hedge nonfinancial and
financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the
requirement to separately measure and report hedge ineffectiveness, as well as eases certain hedge effectiveness
assessment requirements. The guidance is effective beginning in 2019 with early adoption permitted. The
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Partnership is in the process of determining the impact of this guidance, including transition elections and
required disclosures, on the consolidated financial statements and the timing of adoption.
In May 2017, the FASB issued an accounting standards update to provide guidance about when changes to the
terms or conditions of a share-based payment award require an entity to apply modification accounting. An entity
should account for the effects of a modification unless the fair value, vesting conditions and balance sheet
classification of the modified award is the same as the original award immediately before the original award is
modified. The Partnership will adopt the new standard on a prospective basis beginning on January 1, 2018. The
application of this new accounting standard will not have a material impact on the consolidated financial
statements.
In February 2017, the FASB issued an accounting standards update addressing the derecognition of nonfinancial
assets. The guidance defines in-substance nonfinancial assets, and states that the derecognition of business
activities should be evaluated under the consolidation guidance, with limited exceptions related to conveyances
of oil and gas mineral rights or contracts with customers. The standard eliminates the previous exclusion for
businesses that are in-substance real estate, and eliminates some differences based on whether a transferred set is
that of assets or a business and whether the transfer is to a joint venture. The standard must be adopted in
conjunction with the adoption date of the revenue recognition accounting standards update, which the Partnership
will adopt on January 1, 2018. The Partnership plans to adopt the new standard using the modified retrospective
method and does not expect the application of this accounting standards update to have a material impact on the
consolidated financial statements.
In January 2017, the FASB issued an accounting standards update which simplifies the subsequent measurement
of goodwill by eliminating Step 2 from the goodwill impairment test. Under the new guidance, the recognition of
an impairment charge is calculated based on the amount by which the carrying amount exceeds the reporting
unit’s fair value, which could be different from the amount calculated under the current method using the implied
fair value of the goodwill; however, the loss recognized should not exceed the total amount of goodwill allocated
to that reporting unit. The guidance should be applied on a prospective basis, and is effective for annual or
interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted
for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017.
In January 2017, the FASB issued an accounting standards update to clarify the definition of a business with the
objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as
acquisitions (or disposals) of assets or businesses. The standard is intended to narrow the definition of a business
by specifying the minimum inputs and processes and by narrowing the definition of outputs. The change is
effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The
guidance will be applied prospectively and early adoption is permitted for certain transactions. The Partnership
will adopt this new standard on a prospective basis beginning on January 1, 2018. The application of this
accounting standards update will not have a material impact on the consolidated financial statements.
In November 2016, the FASB issued an accounting standards update requiring that the statement of cash flows
explain the change during the period in the total of cash, cash equivalents and amounts generally described as
restricted cash or restricted cash equivalents. The change is effective for fiscal years beginning after
December 15, 2017, and interim periods within those fiscal years. Retrospective application is required.
Application of this accounting standards update is not expected to have a material impact on the Consolidated
Statements of Cash Flows.
In August 2016, the FASB issued an accounting standards update related to the classification of certain cash
flows. The accounting standards update provides specific guidance on eight cash flow classification issues,
including debt prepayment or debt extinguishment costs and distributions received from equity method investees,
to reduce diversity in practice. The change is effective for fiscal years beginning after December 15, 2017, and
interim periods within those fiscal years, with early adoption permitted. Retrospective application is required.
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The Partnership will adopt this new standard beginning on January 1, 2018. The application of this accounting
standards update adds additional disclosures related to the Partnership’s Consolidated Statements of Cash Flows
but otherwise has no impact on the consolidated financial statements.
In June 2016, the FASB issued an accounting standards update related to the accounting for credit losses on
certain financial instruments. The guidance requires that for most financial assets, losses are based on an
expected loss approach which includes estimates of losses over the life of exposure that considers historical,
current and forecasted information. Expanded disclosures related to the methods used to estimate the losses as
well as a specific disaggregation of balances for financial assets are also required. The change is effective for
fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption
permitted for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The
Partnership does not expect application of this accounting standards update to have a material impact on the
consolidated financial statements.
In February 2016, the FASB issued an accounting standards update requiring lessees to record virtually all leases
on their balance sheets. The accounting standards update also requires expanded disclosures to help financial
statement users better understand the amount, timing and uncertainty of cash flows arising from leases. For
lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct
financing leases. The change will be effective on a modified retrospective basis for fiscal years beginning after
December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. The Partnership
is currently evaluating the impact of this standard on the Partnership’s financial statements and disclosures,
internal controls, and accounting policies. This evaluation process includes reviewing all forms of leases,
performing a completeness assessment over the lease population and analyzing the practical expedients in order
to determine the best path to implementation. The Partnership completed its system implementation evaluation
during the fourth quarter of 2017, and concluded a third-party supported lease accounting information system
solution will be implemented to account for its leases. A project to implement this system has begun and the
Partnership is currently collecting the necessary information on its lease population, establishing a new lease
accounting process and designing new internal controls for the new process. The Partnership does not plan to
early adopt the standard. The Partnership believes the impact may be material on the consolidated financial
statements as all operating leases will be recognized as a right of use asset and lease obligation. Based on results
of the evaluation process to date, the Partnership also believes the impact on existing processes, controls and
information systems may be material.
In January 2016, the FASB issued an accounting standards update requiring unconsolidated equity investments,
not accounted for under the equity method, to be measured at fair value with changes in fair value recognized in
net income. The update also requires the use of the exit price notion when measuring the fair value of financial
instruments for disclosure purposes and the separate presentation of financial assets and liabilities by
measurement category and form on the balance sheet and accompanying notes. The update eliminates the
requirement to disclose the methods and assumptions used in estimating the fair value of financial instruments
measured at amortized cost. Lastly, the accounting standards update requires separate presentation in other
comprehensive income of the portion of the total change in the fair value of a liability resulting from a change in
the instrument-specific credit risk when electing to measure the liability at fair value in accordance with the fair
value option for financial instruments. The changes are effective for fiscal years and interim periods within those
fiscal years beginning after December 15, 2017. Early adoption is permitted only for guidance regarding
presentation of the liability’s credit risk. The Partnership does not expect application of this accounting standards
update to have a material impact on the consolidated financial statements.
In May 2014, the FASB issued an accounting standards update for revenue recognition for contracts with
customers. The guidance in the accounting standards update states that revenue is recognized when a customer
obtains control of a good or service. Recognition of the revenue will involve 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 the revenue as the obligations are satisfied.
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Additional disclosures will be required to provide adequate information to understand the nature, amount, timing
and uncertainty of reported revenues and revenues expected to be recognized. The Partnership completed the
evaluation of the impact of this standard on the consolidated financial statements and disclosures, internal
controls and accounting policies in the fourth quarter of 2017. The Partnership will adopt the standard January 1,
2018, using the modified retrospective method applied to contracts not complete as of the adoption date, resulting
in an immaterial cumulative effect adjustment as of the date of adoption. The Partnership will monitor the
changes in processes and internal controls throughout 2018. There will be no significant system or process
changes as a result of adoption. The major changes as a result of adoption are analyzed below. Our equity method
investments in private companies that we do not manage are still in the process of analyzing the impact of ASC
606 which will be adopted as of January 1, 2019. Based on the nature of these companies operations and
similarities to our operations for which we have analyzed the impact of ASC 606, we do not expect the impact to
be material.
Under ASC 606, the Partnership’s service arrangements will generally be recognized over time when the
performance obligation is satisfied as services are provided in a series. The transaction price has both fixed
components, related to minimum volume commitments, and variable components which are primarily dependent
on volumes delivered. Variable consideration will not be estimated at contract inception as the transaction price
is specifically allocable to the services provided each period end. Product sales will be recognized at a point in
time when control of the product transfers to the customer. The primary changes on the Consolidated Statements
of Income as a result of the adoption of ASC 606 are as follows:
•
Third party reimbursements—Amounts received from customers for reimbursement of costs such as
electricity and storage historically were recorded net in the statement of operations. Upon adoption,
these amounts will be included in the transaction price for services performed and thus will be a gross
up on the statement of operations. Had the Partnership adopted ASC 606 for fiscal year-ended
December 31, 2017, the Partnership believes the impact would have been an increase of between
$365 million to $403 million on Service revenue and Cost of revenues.
• Non-cash consideration—The Partnership receives commodity product for services performed in
percent-of-liquids and keep-whole arrangements. A new service revenue stream for non-cash
consideration received in these arrangements will be recorded when the performance obligation is
completed based on the value of the product received at the time services are performed. At this time,
the variability of the non-cash consideration related to both form (price) and other-than-form (volume
and product mix), which are interrelated, is resolved. Fuel and loss allowances will not be included in
the transaction price from contracts with customers as the Partnership does not obtain control of the
product prior to being used or burned, which is consistent with historical accounting. Had the
Partnership adopted ASC 606 for fiscal year-ended December 31, 2017, the Partnership believes the
impact would have been an increase of between $52 million to $58 million on Service revenue and
Cost of revenues.
• Percent-of-proceeds revenues—The Partnership’s percentage of proceeds revenue received was
historically recorded in product revenues. Upon adoption of ASC 606, these revenues will be 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 the
Partnership does not control the product prior to sale. Had the Partnership adopted ASC 606 for fiscal
year-ended December 31, 2017, the Partnership believes the impact would have been an increase on
Service revenue and a decrease on Product sales of between $119 million to $131 million.
•
Imbalances—Historically, all imbalances were recorded net. In certain instances, the Partnership’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. Had the Partnership adopted ASC
606 for fiscal year-ended December 31, 2017, the Partnership believes the impact would have been an
increase of between $63 million to $69 million on Product sales and Purchased product costs.
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There were various other adoption differences between ASC 605 and ASC 606 identified as a result of adopting
ASC 606; however, these changes did not have a material impact on the Partnership’s consolidated financial
statements. These changes in process or recognition patterns relate specifically to oil allowances, deferred
customer credits, arrangements with tiered pricing features or discounts and aid-in-construction payments.
4. Acquisitions
Joint-Interest Acquisition
On September 1, 2017, the Partnership entered into a Membership Interests and Shares Contributions Agreement
(the “September 2017 Contributions Agreement”) with MPLX GP LLC (“MPLX GP”), MPLX Logistics
Holdings LLC (“MPLX Logistics”), MPLX Holdings Inc. (“MPLX Holdings”) and MPC Investment LLC
(“MPC Investment”), each a wholly-owned subsidiary of MPC, whereby the Partnership agreed to acquire
certain ownership interests in joint venture entities indirectly held by MPC. Pursuant to the September 2017
Contributions Agreement, MPC Investment agreed to contribute: all of the membership interests of Lincoln
Pipeline LLC, which holds a 35 percent interest in Illinois Extension; 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 the Partnership for an agreed
upon purchase price of approximately $420 million in cash and equity consideration valued at approximately
$630 million, for total consideration of $1.05 billion (collectively, the “Joint-Interest Acquisition”). The number
of common units representing the equity consideration was then determined by dividing the contribution amount
by the simple average of the ten day trading volume weighted average NYSE price of a common unit for the ten
trading days ending at market close on August 31, 2017. The fair value of the common and general partner units
issued was approximately $653 million based on the closing common unit price as of September 1, 2017, as
recorded on the Consolidated Statements of Equity, for a total purchase price of $1.07 billion. The equity issued
consisted of: (i) 13,719,017 common units to MPLX GP, (ii) 3,350,893 common units to MPLX Logistics and
(iii) 1,441,224 common units to MPLX Holdings. The Partnership also issued 377,778 general partner units to
MPLX GP in order to maintain its two percent general partner interest (“GP Interest”) in the Partnership.
Illinois Extension operates the 168-mile, 24-inch diameter Southern Access Extension (“SAX”) crude oil
pipeline from Flanagan, Illinois to Patoka, Illinois, as well as additional tankage and two pump stations. LOOP
owns and operates midstream crude oil infrastructure, including a deep water oil port offshore of Louisiana,
pipelines and onshore storage facilities. LOOP also manages the operations of LOCAP, an affiliate pipeline.
LOCAP owns and operates a crude oil pipeline and tank facility in St. James, Louisiana, which distributes oil
received from LOOP’s storage facilities and other connecting pipelines to nearby refineries and into the
mid-continent region of the United States. Explorer owns and operates an approximate 1,830-mile common
carrier pipeline that primarily transports gasoline, diesel, diluent and jet fuel from the Gulf Coast refining
complex to the Midwest United States. The Partnership accounts for the Joint-Interest Acquisition entities as
equity method investments within its L&S segment.
As a transfer between entities under common control, the Partnership recorded the Joint-Interest Acquisition on
its Consolidated Balance Sheets at MPC’s historical basis, which included accumulated other comprehensive
loss. The Partnership recognizes an accumulated other comprehensive loss on its Consolidated Balance Sheets
relating to pension and other post-retirement benefits provided by the LOOP and Explorer joint-interests to their
employees. MPLX LP is not a sponsor of these benefit plans. There were no changes to Accumulated other
comprehensive loss during the period September 1, 2017 through December 31, 2017.
Distributions of cash received from the entities and interests acquired in the Joint-Interest Acquisition related to
periods prior to the acquisition will be prorated on a daily basis with MPLX LP retaining the portion of
distributions beginning on the closing date. All amounts distributed to MPLX LP related to periods before the
acquisition will be paid to MPC. Additionally, MPLX LP has agreed to pay MPC for any distributions of cash
from LOOP related to the sale of LOOP’s excess crude oil inventory. Because the future distributions or
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payments cannot 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 and recorded a liability
to MPC and a corresponding decrease to the general partner’s equity for $32 million, as shown on the
Consolidated Statements of Equity.
The Partnership accounts for the interests acquired in the Joint-Interest Acquisition in arrears using the most
recently available information. The amount of income (loss) associated with these investments included in the
Consolidated Statements of Income under the caption Income (loss) from equity method investments for the four
months ended December 31, 2017 totaled $21 million. MPC agreed to waive approximately two-thirds of the
third quarter 2017 distributions on the common units issued in connection with the Joint-Interest Acquisition. As
a result of this waiver, MPC did not receive approximately two-thirds of the distributions or IDRs that would
have otherwise accrued on such common units with respect to the third quarter 2017 distributions. The value of
these waived distributions was $10 million.
Acquisition of Hardin Street Transportation LLC, Woodhaven Cavern LLC and MPLX Terminals LLC
MPC contributed the assets of HST, WHC and MPLXT to newly created and wholly-owned subsidiaries and
entered into commercial agreements related to services provided by these new entities to MPC on January 1,
2015 for HST and WHC and April 1, 2016 for MPLXT. Pursuant to a Membership Interests Contributions
Agreement entered into on March 1, 2017, by the Partnership with MPLX GP, MPLX Logistics, MPLX Holdings
and MPC Investment, each a wholly-owned subsidiary of MPC, MPC Investment agreed to contribute the
outstanding membership interests in HST, WHC and MPLXT through a series of intercompany contributions to
the Partnership for approximately $1.5 billion in cash and equity consideration valued at approximately
$504 million (the “Transaction”). The number of common units representing the equity consideration was
determined by dividing the contribution amount by the simple average of the ten day trailing volume weighted
average NYSE price of a common unit for the ten trading days ending at market close on February 28, 2017. The
fair value of the common and general partner units issued was approximately $503 million, as recorded on the
Consolidated Statements of Equity, and consisted of (i) 9,197,900 common units to MPLX GP, (ii) 2,630,427
common units to MPLX Logistics and (iii) 1,132,049 common units to MPLX Holdings. The Partnership also
issued 264,497 general partner units to MPLX GP in order to maintain its two percent GP Interest in the
Partnership. MPC agreed to waive two-thirds of the first quarter 2017 distributions on the common units issued
in connection with the Transaction. As a result of this waiver, MPC did not receive two-thirds of the general
partner distributions or IDRs that would have otherwise accrued on such common units with respect to the first
quarter 2017 distributions. The value of these waived distributions was $6 million.
HST owns and operates various crude oil and refined product pipelines and associated storage tanks. As of the
acquisition date, these pipelines 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 had a combined shell capacity of approximately 23.6 million barrels as
of the acquisition date. The terminal facilities are located primarily in the Midwest, Gulf Coast and Southeast
regions of the United States. The Partnership accounts for these businesses within its L&S segment.
The Partnership retrospectively adjusted the historical financial results for all periods to give effect to the
acquisition of HST and WHC effective January 1, 2015, and the acquisition of MPLXT effective April 1, 2016,
as required for transactions between entities under common control. Prior to these dates, these entities were not
considered businesses and, therefore, there are no financial results from which to recast.
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Acquisition of Ozark Pipeline
On March 1, 2017, the Partnership acquired the Ozark pipeline from Enbridge Pipelines (Ozark) LLC for
approximately $219 million, including purchase price adjustments made in the second quarter of 2017. Based on
the final fair value estimates of assets acquired and liabilities 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. The Partnership accounts for the Ozark pipeline within its L&S segment.
The amounts of revenue and income from operations associated with the acquisition included in the Consolidated
Statements of Income, since the March 1, 2017 acquisition date, are as follows:
(In millions)
Revenues and other income
Income from operations
Ten 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, the Partnership closed on a joint venture, MarEn Bakken Company, LLC (“MarEn
Bakken”), with Enbridge Energy Partners L.P. in which MPLX LP acquired a partial, 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, L.P. The
Partnership contributed $500 million of the $2.0 billion purchase price paid by MarEn Bakken to acquire a
36.75 percent indirect interest in the Bakken Pipeline system. The Partnership holds, through a subsidiary, a
25 percent interest in MarEn Bakken, which equates to a 9.1875 percent indirect interest in the Bakken Pipeline
system.
The Partnership accounts for its investment in MarEn Bakken as an equity method investment and bases the
equity method accounting for this joint venture in arrears using the most recently available information. The
amount of income (loss) associated with these investments included in the Consolidated Statements of Income
under the caption Income (loss) from equity method investments for the year ended December 31, 2017 totaled
$15 million. In connection with the Partnership’s acquisition of a partial, indirect equity interest in the Bakken
Pipeline system, MPC agreed to waive its right to receive incentive distributions of $1.6 million per quarter for
twelve consecutive quarters, beginning with distributions declared in the first quarter of 2017 and paid to MPC in
the second quarter of 2017, which was prorated to $0.8 million from the acquisition date. This waiver is no
longer applicable as a result of the GP IDR Exchange on February 1, 2018.
Acquisition of Hardin Street Marine LLC
On March 14, 2016, the Partnership entered into a Membership Interests Contribution Agreement (the
“Contribution Agreement”) with MPLX GP, MPLX Logistics and MPC Investment, each a wholly-owned
subsidiary of MPC, related to the acquisition of HSM, MPC’s inland marine business, from MPC. Pursuant to the
Contribution Agreement, the transaction was valued at $600 million, consisting of a fixed number of common
units and general partner units of 22,534,002 and 459,878, respectively. The general partner units maintain
MPC’s two percent GP Interest in the Partnership. The acquisition closed on March 31, 2016 and the fair value of
the common units and general partner units issued was $669 million and $14 million, respectively, as recorded
on the Consolidated Statements of Equity. MPC agreed to waive distributions in the first quarter of 2016 on
common units issued in connection with this transaction. As a result of this waiver, MPC did not receive general
partner distributions or IDRs that would have otherwise accrued on such common units with respect to the first
quarter 2016 distributions. The value of these waived distributions was $15 million.
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The inland marine business, comprised of 18 tow boats and 219 owned and leased barges as of the acquisition
date, which transport light products, heavy oils, crude oil, renewable fuels, chemicals and feedstocks in the
Midwest and Gulf Coast regions of the United States, accounted for nearly 60 percent of the total volumes MPC
shipped by inland marine vessels as of March 31, 2016. The Partnership accounts for HSM within its L&S
segment.
Purchase of MarkWest Energy Partners, L.P.
On December 4, 2015, a wholly-owned subsidiary of the Partnership merged with MarkWest. Each common unit
of MarkWest issued and outstanding immediately prior to the effective time of the MarkWest Merger was
converted into a right to receive 1.09 common units representing limited partner interests in MPLX LP, plus a
one-time cash payment of $6.20 per unit. Each Class B unit of MarkWest issued and outstanding immediately
prior to the effective time of the MarkWest Merger was converted into the right to receive one Class B unit of
MPLX LP. The Class B units of MPLX LP automatically converted, in two equal installments, into 1.09 common
units of MPLX LP and the right to receive $6.20 in cash, on July 1, 2016 and July 1, 2017. MPC contributed
approximately $1.3 billion of cash to the Partnership to pay the aggregate cash consideration to MarkWest
unitholders, without receiving any new equity in exchange. At closing, MPC made a payment of $1.2 billion to
MarkWest common unitholders and the remaining $50 million was paid, in equal amounts, during July 2016 and
July 2017, in connection with the conversion of the remaining outstanding Class B units to MPLX LP common
units. The Partnership’s financial results reflect the results of MarkWest from the date of the acquisition.
The components of the fair value of consideration transferred was as follows:
(In millions)
Fair value of units issued
Cash
Paid to MarkWest Class B unitholders
Total fair value of consideration transferred
$7,326
1,230
50
$8,606
153
The following table summarizes the final purchase price allocation. Subsequent to December 31, 2015, additional
analysis was completed and adjustments were made to the preliminary purchase price allocation as noted in the
table below. The fair value of assets acquired and liabilities and noncontrolling interests assumed at the
acquisition date as of December 31, 2016, was as follows:
(In millions)
Cash and cash equivalents
Receivables
Inventories
Other current assets
Equity method investments
Property, plant and equipment
Intangibles
Other noncurrent assets
Total assets acquired
Accounts payable
Accrued liabilities
Accrued taxes
Other current liabilities
Long-term debt
Deferred income taxes
Deferred credits and other liabilities
Noncontrolling interests
Total liabilities and noncontrolling interests assumed
Net assets acquired excluding goodwill
Goodwill
Net assets acquired
As Originally
Reported
Adjustments
As
Adjusted
$
12
164
33
44
2,457
8,474
468
5
11,657
322
13
21
44
4,567
374
151
13
5,505
6,152
2,454
$ —
—
(1)
—
143
43
65
—
250
—
6
—
—
—
—
—
3
9
241
(241)
$
12
164
32
44
2,600
8,517
533
5
11,907
322
19
21
44
4,567
377
151
13
5,514
6,393
2,213
$ 8,606
$ —
$ 8,606
Adjustments to the preliminary purchase price stem mainly from additional information obtained by management
in the first and second quarters of 2016 about facts and circumstances that existed at the acquisition date,
including updates to forecasted employee benefit costs, maintenance capital expenditures and completion of
certain valuations to determine the underlying fair value of certain acquired assets. The adjustment to intangibles
mainly related to a misstatement in the original preliminary purchase price allocation, resulting in a $68 million
reduction to the carrying value of goodwill and an offsetting increase of $64 million in intangibles, $2 million in
equity method investments and $2 million in property, plant and equipment. Management concluded that the
correction of the error was immaterial to the consolidated financial statements. As further discussed in Note 18,
in the first quarter of 2016 the Partnership recorded a goodwill impairment charge based on the implied fair value
of goodwill as of the interim impairment analysis date. During the second quarter of 2016, the Partnership
finalized its analysis of the final purchase price allocation. The completion of the purchase price allocation
resulted in a refinement of the impairment expense recorded, as more fully discussed in Note 18.
The increase to the fair value of intangibles and property, plant and equipment noted above resulted in additional
amortization and depreciation expense of approximately $1 million recognized for the year ended December 31,
2016, in Depreciation and amortization in the Consolidated Statements of Income, that would have been
recorded for the year ended December 31, 2015, had the fair value adjustments been recorded as of December 4,
2015. The increase in the fair value of equity investments above would not have had a material effect on the
income from equity method investments had the fair value adjustment been recorded as of December 4, 2015.
The purchase price allocation resulted in the recognition of $2.2 billion of goodwill in three reporting units
within the Partnership’s G&P segment, substantially all of which is not deductible for tax purposes. Goodwill
154
represents the complimentary aspects of the highly diverse asset base of MarkWest and MPLX LP that provides
significant additional opportunities across multiple segments of the hydrocarbon value chain.
The Partnership recognized $36 million of acquisition-related costs associated with the MarkWest Merger. These
costs were expensed, with $30 million included in General and administrative expenses and $6 million included
in Other financial costs.
The fair value of the common units issued was determined on the basis of the closing market price of the
Partnership’s units as of the effective time of the transaction and is considered a Level 1 measurement. The fair
value of the Class B units issued was determined based on reference to the value of the common units, adjusted
for a lack of distributions prior to their stated conversion dates, and is considered a Level 2 measurement. The
fair values of the long-term debt and SMR liabilities were determined as of the acquisition date using the
methods discussed in Note 15.
The fair value of the equity method investments was determined based on applying the discounted cash flow
method, which is an income approach, to the Partnership’s equity method investments on an individual basis.
Key assumptions included discount rates of 9.4 percent to 11.1 percent and terminal values based on the Gordon
growth method to capitalize the cash flows, using a 2.5 percent long-term growth rate. Intangibles represented
customer contracts and related relationships. 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. The fair value of property, plant and equipment was determined primarily based on
the cost approach. Key assumptions included inputs to the valuation methodology such as recent purchases of
similar items and published data for similar items. Components were adjusted for economic and functional
obsolescence, location, normal useful lives, and capacity (if applicable). The fair value measurements for equity
method investments, intangibles and property, plant and equipment were based on significant inputs that were
not observable in the market and, therefore, represent Level 3 measurements.
The amounts of revenue and income from operations associated with MarkWest in the Consolidated Statements
of Income for 2015 were as follows:
(In millions)
Revenues and other income
Income from operations
2015
$126
32
Unaudited Pro Forma Financial Information
The following unaudited pro forma financial information presents consolidated results assuming the MarkWest
Merger occurred on January 1, 2014.
(In millions, except per unit data)
Revenues and other income
Net income attributable to MPLX LP
Net income attributable to MPLX LP per unit—basic
Net income attributable to MPLX LP per unit—diluted
2015
$2,817
228
0.47
0.45
The unaudited pro forma financial information includes adjustments primarily to align accounting policies, adjust
depreciation expense to reflect the fair value of property, plant and equipment, increase amortization expense
related to identifiable intangible assets and adjust interest expense related to the fair value of MarkWest’s long-
term debt, as well as the related income tax effects. The pro forma financial information does not give effect to
potential synergies that could result from the acquisition and is not necessarily indicative of the results of future
operations.
155
MarkWest had a 60 percent legal ownership interest in MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”)
for the year ended December 31, 2015. MarkWest Utica EMG’s inability to fund its planned activities without
subordinated financial support qualify it as a VIE. The financing structure for MarkWest Utica EMG at its
inception resulted in a de-facto agent relationship under which MarkWest was deemed to be the primary
beneficiary of MarkWest Utica EMG. Therefore, MarkWest consolidated MarkWest Utica EMG in its historical
financial statements. In the fourth quarter of 2015, based on economic conditions and other pertinent factors, the
accounting for its investment in MarkWest Utica EMG was reassessed. As of December 4, 2015, the entity has
been deconsolidated. For purposes of this pro forma financial information, MarkWest Utica EMG has been
consolidated for the period prior to the acquisition consistent with its treatment in the historical periods
presented.
The following table is a summary of the amounts included in the historical financial statements of MarkWest for
the period from January 1, 2015 through December 3, 2015 related to MarkWest Utica EMG:
(in millions)
Revenues and other income
Cost of revenue excluding depreciation and amortization
Depreciation and amortization
Net income attributable to noncontrolling interests
Net loss
2015
$152
27
61
64
(5)
EMG Utica, LLC (“EMG Utica”), a joint venture partner in MarkWest Utica EMG, received a special non-cash
allocation of income of approximately $41 million for the period from January 1, 2015 through December 3,
2015. See Note 5 for a description of the transaction and its impact on the financial statements. Net income of
MarkWest would not have changed had MarkWest Utica EMG been deconsolidated for the period from
January 1, 2015 through December 3, 2015.
Purchase of Pipe Line Holdings
Effective December 4, 2015, the Partnership purchased the remaining 0.5 percent interest in MPLX Pipe Line
Holdings LLC (“Pipe Line Holdings”) from subsidiaries of MPC for consideration of $12 million. This resulted
in Pipe Line Holdings becoming a wholly-owned subsidiary of the Partnership. The Partnership recorded the
0.5 percent interest at its historical carrying value of $6 million and the excess cash paid and equity contributed
over historical carrying value of $6 million as a decrease to general partner equity. Prior to this transaction, the
0.5 percent interest was held by MPC and was reflected as the noncontrolling interest retained by MPC in the
consolidated financial statements. There was no material change to MPLX LP’s equity resulting from this
transaction.
156
5. Investments and Noncontrolling Interests
The following table presents the Partnership’s equity method investments at the dates indicated:
(In millions)
Centrahoma Processing LLC
Explorer
Illinois Extension Pipeline
LOCAP
LOOP
MarEn Bakken
MarkWest EMG Jefferson Dry Gas Gathering Company, LLC
MarkWest Utica EMG, L.L.C.
Ohio Condensate Company, L.L.C.
Panola Pipeline Company, L.L.C.
Sherwood Midstream LLC
Sherwood Midstream Holdings LLC
Other
Total
Ownership as of
December 31,
2017
Carrying value at
December 31,
2017
2016
40%
25%
35%
59%
41%
25%
67%
56%
60%
15%
50%
69%
$ 121
89
284
24
225
520
164
2,139
11
24
236
165
8
$ 104
—
—
—
—
—
67
2,224
10
25
—
—
41
$4,010
$2,471
The following tables present summarized financial information for the Partnership’s equity method investments
for the years ended December 31, 2017, 2016 and from the date of the MarkWest Merger through December 31,
2015:
(In millions)
Revenues and other income
Costs and expenses
Income from operations
Net income
Income from equity method investments(1)
(In millions)
Revenues and other income
Costs and expenses
Income (loss) from operations
Net income (loss)
Income (loss) from equity method investments(1)
(In millions)
Revenues and other income
Costs and expenses
Income from operations
Net income
Income from equity method investments(1)
157
Year Ended December 31, 2017
MarkWest Utica
EMG
Other VIEs Non-VIEs
Total
$187
97
90
90
10
$86
42
44
43
20
$954
520
434
345
48
$1,227
659
568
478
78
Year Ended December 31, 2016
MarkWest Utica
EMG
Other VIEs(2) Non-VIEs
Total
$216
100
116
114
8
$ 18
111
(93)
(93)
(89)
$148
117
31
31
7
$382
328
54
52
(74)
Period Ended December 31, 2015
MarkWest Utica
EMG
Other VIEs Non-VIEs
Total
$18
9
9
10
2
$
2
2
1
—
—
$
9
8
1
1
—
$29
19
10
11
3
(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 the
Partnership’s investment in Ohio Condensate Company, L.L.C. (“Ohio Condensate”), which does not
appear separately in this table.
The following tables present summarized balance sheet information for the Partnership’s equity method
investments as of December 31, 2017 and 2016:
(In millions)
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
(In millions)
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
December 31, 2017
MarkWest Utica
EMG(1)
Other VIEs Non-VIEs
Total
$
65
2,077
39
3
$ 46
930
44
11
$ 399
4,624
220
904
$ 510
7,631
303
918
December 31, 2016
MarkWest Utica
EMG(1)
Other VIEs Non-VIEs
Total
$
45
2,173
30
2
$
2
132
4
13
$ 40
390
26
—
$
87
2,695
60
15
(1) 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 $790 million
and $794 million as of December 31, 2017 and 2016, respectively.
As of December 31, 2017, the carrying value of the Partnership’s equity method investments exceeded the
underlying net assets of its investees by $1.0 billion. This basis difference is being amortized or accreted into net
income over the remaining estimated useful lives of the underlying net assets, except for $459 million of excess
related to goodwill.
MarkWest Utica EMG
Effective January 1, 2012, MarkWest Utica Operating Company, LLC (“Utica Operating”), a wholly-owned and
consolidated subsidiary of MarkWest, 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 10 percent of each capital call for MarkWest Utica EMG, and Utica Operating will be
required to fund all remaining capital not elected to be funded by EMG Utica. After the Second Equalization
Date, Utica Operating and EMG Utica will have the right, but not the obligation, to fund their pro rata portion
(based on their respective investment balances) of any additional required capital and may also fund additional
capital that the other party elects not to fund. As of December 31, 2017, EMG Utica has contributed
approximately $1.2 billion and Utica Operating has contributed approximately $1.5 billion to MarkWest Utica
EMG.
158
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 and $4 million for the 28 days ended
December 31, 2015.
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, 2017, Utica Operating’s investment balance in MarkWest Utica EMG was approximately
56 percent.
MarkWest Utica EMG is deemed to be a VIE. Utica Operating is not deemed to be the primary beneficiary, due
to EMG Utica’s voting rights on significant matters. The Partnership’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. The Partnership did not provide any financial support to
MarkWest Utica EMG that it was not contractually obligated to provide during the years ended December 31,
2017, 2016 and the 28 days ended December 31, 2015. The Partnership receives management fee revenue for
engineering and construction and administrative services for operating MarkWest Utica EMG, and is also
reimbursed for personnel services (“Operational Service revenue”). Operational Service revenue is reported as
Other income—related parties in the Consolidated Statements of Income. The amount of Operational Service
revenue related to MarkWest Utica EMG for the years ended December 31, 2017, 2016, and the 28 days ended
December 31, 2015 totaled $17 million, $16 million, and less than $1 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, 2017, the Partnership 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, the Partnership reports its portion of Ohio Gathering’s
net assets as a component of its investment in MarkWest Utica EMG. The Partnership receives Operational
Service revenue for operating Ohio Gathering which is reported as Other income-related parties in the
Consolidated Statements of Income. The amount of Operational Service revenue related to Ohio Gathering for
the years ended December 31, 2017, 2016 and the 28 days ended December 31, 2015 totaled $16 million,
$15 million, and $2 million, respectively.
Ohio Condensate
Ohio Condensate Company, L.L.C. (“Ohio Condensate”) is a joint venture between MarkWest Utica EMG
Condensate, L.L.C., a wholly-owned and consolidated subsidiary of MarkWest, and Summit. The Partnership
accounts for Ohio Condensate, which is a VIE, as an equity method investment as MPLX LP exercises
significant influence, but does not control Ohio Condensate and is not its primary beneficiary due to Summit’s
voting rights on significant matters. During the second quarter of 2016, forecasts for Ohio Condensate were
reduced to align with updated forecasts for customer requirements. As the operator of that entity responsible for
maintaining its financial records, the Partnership completed a fixed asset impairment analysis as of June 30,
2016, in accordance with ASC Topic 360, to determine the potential fixed asset impairment charge. The resulting
fixed asset impairment charge recorded within Ohio Condensate’s financial statements was $96 million. Based
on the Partnership’s 60 percent ownership of Ohio Condensate, approximately $58 million was recorded in the
second quarter of 2016 in (Loss) income from equity method investments on the accompanying Consolidated
Statements of Income.
159
The Partnership’s investment in Ohio Condensate, which was established at fair value in connection with the
MarkWest Merger, exceeded its proportionate share of the underlying net assets. Therefore, in conjunction with
the ASC Topic 360 impairment analysis, the Partnership completed an equity method impairment analysis in
accordance with ASC Topic 323 to determine the potential additional equity method impairment charge to be
recorded on the Partnership’s consolidated financial statements resulting from an other-than-temporary
impairment. As a result, an additional impairment charge of approximately $31 million was recorded in the
second quarter of 2016 in (Loss) income from equity method investments on the accompanying Consolidated
Statements of Income, which eliminated the basis differential established in connection with the MarkWest
Merger.
The fair value of Ohio Condensate and its underlying fixed assets was determined based upon 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 estimate of the fair
value under the discounted cash flow method include management’s best estimates of the expected future results
using a probability-weighted average set of cash flow forecasts and a discount rate of 11.2 percent. An increase
to the discount rate of 50 basis points would have resulted in an additional charge of $1 million on the
Consolidated Statements of Income. Fair value determinations require considerable judgment and are sensitive to
changes in underlying assumptions and factors. As such, the fair value of the Ohio Condensate equity method
investment and its underlying fixed assets represents a Level 3 measurement. As a result, there can be no
assurance that the estimates and assumptions made for purposes of the interim impairment test will prove to be
an accurate prediction of the future.
Sherwood Midstream
Effective January 1, 2017, MarkWest Liberty Midstream & Resources, L.L.C. (“MarkWest Liberty Midstream”),
a wholly-owned and consolidated subsidiary of MarkWest, and Antero Midstream Partners LP (“Antero
Midstream”) formed a joint venture, Sherwood Midstream LLC (“Sherwood Midstream”), to support Antero
Resources’ development in the Marcellus Shale. MarkWest Liberty Midstream has a 50 percent ownership
interest in Sherwood Midstream. Pursuant to the terms of the related limited liability company agreement (the
“LLC Agreement”), MarkWest Liberty Midstream contributed assets then under construction with a fair value of
approximately $134 million and cash of approximately $20 million. Antero Midstream made an initial capital
contribution of approximately $154 million.
Also effective January 1, 2017, MarkWest Liberty Midstream converted all of its ownership interests in
MarkWest Ohio Fractionation Company, L.L.C. (“Ohio Fractionation”), a previously wholly-owned subsidiary,
to Class A Interests and amended its LLC Agreement to create Class B-3 Interests, which were sold to Sherwood
Midstream for $126 million in cash. The Class B-3 Interests provide Sherwood Midstream with the right to
fractionation revenue and the obligation to pay expenses related to 20 mbpd of capacity in the Hopedale 3
fractionator. Sherwood Midstream accounts for its investment in Ohio Fractionation, which is a VIE, as an equity
method investment as Sherwood Midstream does not control Ohio Fractionation. MarkWest Liberty Midstream
has been deemed to be the primary beneficiary of Ohio Fractionation because it has control over the decisions
that could significantly impact its financial performance, and as a result, consolidates Ohio Fractionation. The
carrying amounts of assets and liabilities included in the Partnership’s Consolidated Balance Sheets pertaining to
Ohio Fractionation at December 31, 2017, were current assets of $63 million, non-current assets of $405 million
and current liabilities of $14 million. The creditors of Ohio Fractionation do not have recourse to MPLX LP’s
general credit through guarantees or other financial arrangements. The assets of Ohio Fractionation are the
property of Ohio Fractionation and cannot be used to satisfy the obligations of MPLX LP. Sherwood
Midstream’s interests are reflected in Net income attributable to noncontrolling interests in the Consolidated
Statements of Income and Noncontrolling interests in the Consolidated Balance Sheets.
Under the LLC Agreement, cash generated by Sherwood Midstream that is available for distribution will be
allocated to the members in proportion to their respective investment balances.
160
Sherwood Midstream is deemed to be a VIE. MarkWest Liberty Midstream is not deemed to be the primary
beneficiary, due to Antero Midstream’s voting rights on significant matters. The Partnership’s maximum
exposure to loss as a result of its involvement with Sherwood Midstream includes its equity investment, any
additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in
excess of its compensation received for the performance of the operating services. The Partnership did not
provide any financial support to Sherwood Midstream that it was not contractually obligated to provide during
the year ended December 31, 2017. The Partnership receives Operational Service revenue for operating
Sherwood Midstream. The amount of Operational Service revenue related to Sherwood Midstream for the year
ended December 31, 2017 totaled approximately $8 million and is reported as Other income-related parties in
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 deethanization facilities owned by MarkWest Liberty Midstream.
MarkWest Liberty Midstream initially contributed certain real property, equipment and facilities with a fair value
of approximately $209 million to Sherwood Midstream Holdings in exchange for a 79 percent initial ownership
interest. Sherwood Midstream contributed cash of approximately $44 million to Sherwood Midstream Holdings
in exchange for a 21 percent ownership interest. During the second quarter ended June 30, 2017, true-ups to the
initial contributions were finalized. MarkWest Liberty Midstream contributed certain additional real property,
equipment and facilities with a fair value of approximately $10 million to Sherwood Midstream Holdings and
Sherwood Midstream contributed cash of approximately $4 million to Sherwood Midstream Holdings.
Collectively, the real property, equipment, facilities and cash initially contributed, or that may be subsequently
constructed by or contributed, to Sherwood Midstream Holdings are referred to as the “Shared Assets.” The net
book value of the contributed assets was approximately $203 million. The contribution was determined to be an
in-substance sale of real estate. As such, the Partnership only recognized a gain for the portion attributable to
Antero Midstream’s indirect interest of approximately $2 million, included in Gain on sale of assets in the
Consolidated Statements of Income. MarkWest Liberty Midstream’s portion of the gain attributable to its direct
and indirect interests of approximately $14 million is included in its investment in Sherwood Midstream
Holdings and is reported under the caption Equity method investments on the Consolidated Balance Sheets. In
connection with the initial contributions, MarkWest Liberty Midstream received a special distribution of
approximately $45 million.
MarkWest Liberty Midstream’s and Sherwood Midstream’s ownership interests in Sherwood Midstream
Holdings will fluctuate over time. As new Shared Assets are constructed, the members will make additional
capital contributions to Sherwood Midstream Holdings. The amount that each member must contribute will be
based on the expected utilization of the Shared Assets, as defined in the LLC Agreement. Pursuant to the terms of
the LLC Agreement, MarkWest Liberty Midstream will serve as the operator for Sherwood Midstream Holdings.
The Partnership accounts for Sherwood Midstream Holdings, which is a VIE, as an equity method investment as
Sherwood Midstream is considered to be the general partner and controls all decisions. The Partnership’s
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. The
Partnership did not provide any financial support to Sherwood Midstream Holdings that it was not contractually
obligated to provide during the year ended December 31, 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, the Partnership also reports its portion of Sherwood
Midstream Holdings’ net assets as a component of its investment in Sherwood Midstream. As of December 31,
161
2017, the Partnership has a 15.7 percent indirect ownership interest in Sherwood Midstream Holdings through
Sherwood Midstream.
6. Related Party Agreements and Transactions
The Partnership’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, 2017.
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, 2017. 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, 2017.
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 85 percent total direct and indirect interest
as of December 31, 2017. Sherwood Midstream Holdings owns certain infrastructure at the Sherwood
Complex that is shared by and supports the operation of both the Sherwood Midstream and MarkWest
gas processing plants and deethanization 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, 2017. Jefferson Dry Gas provides natural dry
gas gathering and related services in the Utica Shale region of Ohio.
Commercial Agreements
The Partnership has various long-term, fee-based commercial agreements with MPC. Under these agreements,
the Partnership provides transportation, terminal and storage services to MPC, and MPC has committed to
provide the Partnership with minimum quarterly throughput volumes on crude oil and refined products systems,
and minimum storage volumes of crude oil and refined products. 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. The Partnership believes the terms and conditions under these agreements, as
well as the initial agreements with MPC described below, are generally no less favorable to either party than
those that could have been negotiated with unaffiliated parties with respect to similar services.
As discussed in Note 4, the Partnership acquired HST, WHC and MPLXT on March 1, 2017, and HSM on
March 14, 2016. HST, WHC, MPLXT and HSM have various operating, transportation services, terminal
services, storage services, and employee services agreements with MPC, which were assumed by the Partnership
with the closing of these transactions.
The commercial agreements with MPC include:
•
Transportation services agreements—The Partnership has various separate transportation services
agreements with terms ranging from five to 15 years, under which MPC pays the Partnership fees for
transporting crude oil and refined products on various of the Partnership’s crude oil and refined product
pipelines. The Partnership also has a five-year agreement under which MPC pays the Partnership fees
for handling crude oil and products at the Partnership’s Wood River, Illinois barge dock, and a six-year
transportation services agreement under which MPC pays the Partnership fees for providing marine
transportation of crude oil, feedstocks and refined petroleum products, and related services.
162
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 the Partnership 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—The Partnership has two storage services agreements, with 10-year and
17-year terms, respectively, under which MPC pays the Partnership fees for providing storage services
at the Partnership’s Neal, West Virginia butane cavern and Woodhaven, Michigan butane and propane
caverns. The Partnership also has various separate three-year storage services agreements under which
MPC pays the Partnership fees for providing storage services at the Partnership’s tank farms, and
various separate three-year storage services agreements under which MPC pays the Partnership fees for
providing storage services at the Partnership’s storage tanks associated with the Partnership’s crude oil
and refined product pipelines.
The Partnership’s butane cavern storage services agreement with MPC does not automatically renew,
and the Partnership’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, the
Partnership 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 the Partnership a per-barrel fee for such storage
capacity, regardless of whether MPC fully utilizes the available capacity.
•
Terminal services agreement—The Partnership has a 10-year terminal services agreement under which
MPC pays the Partnership 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 the Partnership
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
The Partnership operates various pipelines owned by MPC under operating services agreements. Under these
operating services agreements, the Partnership 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.
163
Management Services Agreement
The Partnership, 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.
Omnibus Agreement
The Partnership 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 the
Partnership’s reimbursement of MPC for the provision of certain general and administrative services to it. It also
provides for MPC’s indemnification of the Partnership 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
The Partnership has various employee services agreements with MPC under which the Partnership reimburses
MPC for employee benefit expenses, along with the provision of operational and management services in support
of both our L&S and G&P segments’ operations, including those in support of HST, WHC, MPLXT and HSM.
Loan Agreement
On December 4, 2015, the Partnership entered into a loan agreement with MPC Investment LLC (“MPC
Investment”), a wholly-owned subsidiary of MPC. Under the terms of the agreement, MPC Investment will make
a loan or loans to the Partnership on a revolving basis as requested by the Partnership and as agreed to by MPC
Investment, in an amount or amounts that do not result in the aggregate principal amount of all loans outstanding
exceeding $500 million 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. In connection with this loan agreement,
the Partnership terminated the previous revolving credit agreement of $50 million with MPC, effective
December 31, 2015.
During 2017, the Partnership borrowed $2.4 billion and repaid $2.0 billion, resulting in a $386 million
outstanding balance at December 31, 2017, which is included in Payables—related parties on the Consolidated
Balance Sheets. During 2016, the Partnership borrowed $2.5 billion and repaid $2.5 billion, resulting in no
outstanding balance at December 31, 2016. Borrowings were at an average interest rate of 2.777 percent and
1.939 percent per annum for 2017 and 2016, respectively.
Related Party Transactions
The Partnership believes that transactions with related parties were conducted on terms comparable to those with
unrelated parties. Related party sales to MPC consisted of crude oil and refined products pipeline transportation
services based on regulated tariff rates, storage and terminal services based on contracted rates and marine
transportation services. Related party sales to MPC also consist of revenue related to volume deficiency credits.
164
Revenue received from related parties related to service and product sales were as follows:
(In millions)
Service revenue
MPC
Rental income
MPC
Product sales (1)
MPC
2017
2016
2015
$1,082
$936
$701
$ 279
$235
$146
$
8
$ 11
$
1
(1)
For 2017, 2016, and 2015, there were $254 million, $46 million and $1 million, respectively, of 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.
The revenue received from 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
2017
2016
2015
$40
17
16
6
8
5
$92
$ 45
16
15
3
—
7
$ 55
—
—
—
2
1
$ 86
$ 58
MPC provides executive management services and certain general and administrative services to the Partnership
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 the Partnership’s operations and maintenance activities, as well as
compensation expenses. Charges for services included in General and administrative expenses primarily relate to
services that support the Partnership’s executive management, accounting and human resources activities. These
charges were as follows:
(In millions)
Purchases—related parties
General and administrative expenses
Total
2017
2016
2015
$ 67
37
$104
$39
45
$84
$32
53
$85
Also under terms of the omnibus agreement, some service costs related to engineering services are associated
with assets under construction. These costs added to Property, plant and equipment, net were as follows:
(In millions)
MPC
2017
$42
2016
$47
2015
$16
MPLX LP obtains employee services from MPC under employee services agreements. Expenses incurred under
these agreements are shown in the table below by the income statement line where they were recorded. The costs
of personnel directly involved in or supporting operations and maintenance activities 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 in the Consolidated Statements of
Income.
165
Employee services expenses from related parties were as follows:
(In millions)
Purchases—related parties
General and administrative expenses
Total
2017
2016
2015
$385
101
$486
$349
100
$449
$140
22
$162
Purchases of products from MPC are classified as Purchases—related parties. Product purchases from related
parties were as follows:
(In millions)
MPC
2017
2016
2015
$3
$—
$—
Receivables from related parties, which for December 31, 2016, included reimbursements from the MarkWest
Merger to be provided by MPC for the conversion of Class B units, were as follows:
(In millions)
MPC
MarkWest Utica EMG
Ohio Gathering
Jefferson Dry Gas
Other
Total
December 31,
2017
2016
$153
1
2
2
2
$160
$242
2
2
—
1
$247
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,
2017
$20
2016
$11
December 31,
2017
2016
$470
29
8
8
1
$516
$ 63
24
—
—
—
$ 87
(1) Balance includes approximately $386 million related to the loan with MPC Investment discussed above.
Other current assets included $8 million of related party prepaid insurance as of December 31, 2017.
From time to time, the Partnership 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,
2017 and 2016 were $11 million and $3 million, respectively. Purchases from related parties during the years
ended December 31, 2017 and 2016 were approximately $44 million and $6 million, respectively.
166
During 2017 and 2016, MPC did not ship its minimum committed volumes on certain pipelines. Under the
Partnership’s pipeline transportation services agreements, if MPC fails to transport its minimum throughput
volumes during any quarter, then MPC will pay the Partnership 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. The Partnership recognizes
revenues for the 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 the Partnership 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,
2017
2016
$53
33
$86
$48
9
$57
7. Net Income (Loss) Per Limited Partner Unit
Net income (loss) per unit applicable to common limited partner units and to subordinated limited partner units is
computed by dividing the respective limited partners’ interest in net income (loss) attributable to MPLX LP by
the weighted average number of common units and subordinated units outstanding. Because the Partnership has
more than one class of participating securities, it uses the two-class method when calculating the net income
(loss) per unit applicable to limited partners. The classes of participating securities include common units,
subordinated units, general partner units, preferred units, certain equity-based compensation awards 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.
As discussed further in Note 8, the subordinated units, all of which were owned by MPC, were converted into
common units during the third quarter of 2015. For purposes of calculating net income (loss) per unit, the
subordinated units were treated as if they converted to common units on July 1, 2015.
In 2017, 2016 and 2015, the Partnership had dilutive potential common units consisting of certain equity-based
compensation awards and Class B units. Potential common units omitted from the diluted earnings per unit
calculation for the years ended December 31, 2017, 2016 and 2015 were less than one 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(1)
Limited partner’s distributions declared on subordinated units(1)
Undistributed net loss attributable to MPLX LP
2017
2016
2015
$ 794
65
328
895
—
$ 233
$ 156
41 —
60
205
224
692
31
—
$(494) $(705) $(159)
167
(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.
(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 (includes IDRs)(1)(2)
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
(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 (including IDRs)
Undistributed net loss attributable to
MPLX LP
Net income attributable to MPLX
LP(1)
Weighted average units outstanding:
Basic
Diluted
Net income attributable to MPLX LP per
limited partner unit:
Basic
Diluted
General
Partner
Limited Partners’
Common Units
Redeemable
Preferred Units
Total
2017
$328
$ 895
(10)
(484)
$318
$ 411
8
8
385
388
$ 65
—
$ 65
$1,288
(494)
$ 794
393
396
$1.07
$1.06
2016
General
Partner
Limited Partners’
Common Units
Redeemable
Preferred Units
Total
$205
(14)
$ 692
$ 41
$ 938
(691)
—
(705)
$191
$
1
$ 41
$ 233
7
7
331
338
$ —
$ —
338
345
168
(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
2015
General
Partner
Limited Partners’
Common Units
Limited
Partner’s
Subordinated
Units
Total
$ 60
$ 224
$ 31
$ 315
MPLX LP
(3)
(127)
(29)
(159)
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
$ 57
$ 97
$
2
$ 156
2
2
79
80
$1.23
$1.22
18
18
$0.11
$0.11
99
100
(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—The Partnership had 407,130,020 common units outstanding as of December 31, 2017. Of
that number, 118,090,823 were owned by MPC, which also owned the two percent GP Interest represented by
8,308,773 general partner units.
Subordinated Unit Conversion—Following payment of the cash distribution for the second quarter of 2015, the
requirements for the conversion of all subordinated units were satisfied under the Partnership Agreement. As a
result, effective August 17, 2015, the 36,951,515 subordinated units owned by MPC were converted into
common units on a one-for-one basis and thereafter participate on terms equal with all other common units in
distributions of available cash. The conversion did not impact the amount of the cash distributions paid by the
Partnership or the total units outstanding.
Reorganization Transactions—On September 1, 2016, the Partnership and various affiliates initiated a series of
reorganization transactions in order to simplify the Partnership’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, 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 the Partnership. 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 the Partnership and its subsidiaries.
MarkWest Merger—On December 4, 2015, the Partnership completed the MarkWest Merger. As defined in the
merger agreement, each common unit of MarkWest issued and outstanding at the effective time of the MarkWest
169
Merger was converted into the right to receive 1.09 common units of MPLX LP. This resulted in the issuance of
216,350,465 common units. The Class A units of MarkWest outstanding immediately prior to the MarkWest
Merger were converted into 28,554,313 Class A units of MPLX LP having substantially similar rights and
obligations that the Class A units of MarkWest had immediately prior to the combination. Each outstanding
Class B unit of MarkWest had, immediately prior to the merger, converted into the right to receive one Class B
unit of MPLX LP having substantially similar rights, including conversion and registration rights, and obligations
that the Class B units of MarkWest had immediately prior to the merger. This resulted in the issuance of
7,981,756 MPLX LP Class B units. 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, on July 1, 2016 and July 1, 2017. 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 the Partnership was limited to a maximum of
five percent of the Partnership’s outstanding common units. Additionally, M&R was given the right with respect
to such converted units to participate in the Partnership’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 the Partnership. 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 the Partnership.
ATM Program—On August 4, 2016, the Partnership entered into a second amended and restated distribution
agreement (the “Distribution Agreement”), providing for the at-the-market issuances of common units, in
amounts, at prices and on terms determined by market conditions and other factors at the time of the offerings
(such continuous offering program, or at-the-market program is referred to as the “ATM Program”). During the
years ended December 31, 2017, 2016, and 2015, the Partnership issued an aggregate of 13,846,998, 26,347,887,
and 25,166 common units, respectively, under our ATM Program, generating net proceeds of approximately
$473 million, $776 million, and $1 million, respectively. The Partnership used the net proceeds from sales under
the ATM Program for general partnership purposes, including repayment or refinancing of debt, and funding for
acquisitions, working capital requirements and capital expenditures.
170
The table below summarizes the changes in the number of units outstanding for the years ended December 31,
2015, 2016, and 2017:
(In units)
Common
Class B
Subordinated
General
Partner(1)
Total
—
—
36,951,515
—
1,638,625
386
81,931,238
19,318
43,341,098
18,932
25,166
36,951,515
216,350,465
296,687,176
120,989
—
— (36,951,515)
—
7,981,756
7,981,756
—
Balance at December 31, 2014
Unit-based compensation awards
Issuance of units under the ATM
Program
Subordinated unit conversion
MarkWest Merger
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
26,347,887
22,534,002
4,350,057
7,153,177
—
—
(3,990,878)
—
357,193,288
268,167
3,990,878
—
13,846,998
12,960,376
18,511,134
4,350,057
—
—
—
(3,990,878)
514
—
5,160,950
6,800,475
2,470
25,680
—
229,493,171
311,469,407
123,459
537,710
459,878
7,330
(436,758)
26,885,597
22,993,880
366,509
6,716,419
7,371,105
5,472
368,555,271
273,639
282,591
14,129,589
264,497
13,224,873
377,778
7,330
18,888,912
366,509
8,308,773
415,438,793
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Balance at December 31, 2017
407,130,020
—
(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 and the Joint Interest Acquisition, 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 the Partnership to issue an unlimited
number of additional partnership securities for the consideration and on the terms and conditions determined by
the general partner without the approval of the unitholders.
171
Net Income Allocation—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. However, when distributions
related to the IDRs are made, earnings equal to the amount of those distributions are first allocated to the general
partner before the remaining earnings are allocated to the unitholders, based on their respective ownership
percentages. The following table presents the allocation of the general partner’s GP Interest in net income
attributable to MPLX LP:
(In millions)
Net income attributable to MPLX LP
Less: Preferred unit distributions
General partner’s IDRs and other
Net income attributable to MPLX LP available to general and limited partners
General partner’s two percent GP Interest in net income attributable to MPLX LP
General partner’s IDRs and other
General partner’s GP Interest in net income attributable to MPLX LP
2017
2016
2015
$794
65
310
$233
$156
41 —
55
191
$419
$
1
$101
$
8
310
$— $
191
2
55
$318
$191
$ 57
Cash Distributions—The Partnership Agreement sets forth the calculation to be used to determine the amount
and priority of cash distributions that the common unitholders, Preferred unitholders and general partner will
receive. In accordance with the Partnership Agreement, on January 26, 2018, the Partnership declared a quarterly
cash distribution, based on the results of the fourth quarter of 2017, totaling $346 million, or $0.6075 per unit.
This distribution was paid on February 14, 2018 to unitholders of record on February 5, 2018. See the table
below for the IDR impact for 2017.
The allocation of total quarterly cash distributions to general, limited, and Preferred unitholders is as follows for
the years ended December 31, 2017, 2016 and 2015. The Partnership’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
Subordinated unitholders
Total limited partners’ distributions
Preferred unit distributions
Total cash distributions declared
2017
2016
2015
$
25
303
328
895
—
895
65
$ 18
187
205
$
6
54
60
692
—
224
31
692
255
41 —
$1,288
$938
$315
(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 (the “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 partnership purposes.
172
The Preferred units rank senior to all common units with respect to distributions and rights upon liquidation. The
holders of the Preferred units are entitled to receive cumulative quarterly distributions equal to $0.528125 per
unit, commencing for the quarter ended June 30, 2016, with a prorated amount from the date of issuance.
Following the second anniversary of the issuance of the Preferred units, the holders of the Preferred units will be
entitled to receive as a quarterly distribution the greater of $0.528125 per unit or the amount of per unit
distributions paid to holders of MPLX LP common units. Since the Preferred unit distribution was declared
subsequent to the end of the second quarter of 2016, the distribution was not accrued to the Preferred unitholders’
capital account. For the quarter ended June 30, 2016, the Preferred units received an earned aggregate cash
distribution of $9 million, based on the quarterly per unit distribution prorated for the 49-day period the Preferred
units were outstanding during the second quarter of 2016.
The changes in the redeemable preferred balance for 2017 and 2016 are summarized below:
(In millions)
Balance at beginning of period
Issuance of Preferred units
Net income allocated
Distributions received by Preferred unitholders
Balance at end of period
2017
2016
$1,000
—
65
(65)
$ —
984
41
(25)
$1,000
$1,000
The holders may convert their Preferred units into common units at any time after the third anniversary of the
issuance date or prior to liquidation, dissolution or winding up of the Partnership, in full or in part, subject to
minimum conversion amounts and conditions. After the fourth anniversary of the issuance date, the Partnership
may convert the Preferred units into common units at any time, in whole or in part, subject to certain minimum
conversion amounts and conditions, if the closing price of MPLX LP common units is greater than $48.75 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. The holders of the Preferred units are entitled to vote on an as-converted
basis with the common unitholders and (as proportionately adjusted for unit splits, unit distributions and similar
transactions) 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 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 the Partnership’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 decreased 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
The Partnership’s chief operating decision maker is the chief executive officer (“CEO”) of its general partner.
The CEO reviews the Partnership’s discrete financial information, makes operating decisions, assesses financial
performance and allocates resources on a type of service basis. The Partnership 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 and distributes crude oil and refined petroleum products. Segment information
for prior periods includes retrospective adjustments in connection with the acquisitions of HSM, HST,
173
WHC and MPLXT. Segment information is not included for periods prior to the Joint-Interest
Acquisition and the Ozark pipeline acquisitions. See Note 4 for more detail of these acquisitions.
• G&P—gathers, processes and transports natural gas; gathers, transports, fractionates, stores and
markets NGLs. This segment is the result of the MarkWest Merger on December 4, 2015 discussed in
more detail in Note 4. Segment information for periods prior to the MarkWest Merger does not include
amounts for these operations.
The Partnership has investments in entities that are accounted for using the equity method of accounting (see
Note 5). However, the CEO only views the Partnership-operated equity method investments’ financial
information as if those investments were consolidated, in contrast to the non-operated equity method
investments.
Segment operating income represents income from operations attributable to the reportable segments. Corporate
general and administrative expenses, unrealized derivative gains (losses), goodwill impairment, certain
management fees and depreciation and amortization are not allocated to the reportable segments. Management
does not consider these items allocable to or controllable by any individual segment and, therefore, excludes
these items when evaluating segment performance. Segment results are also adjusted to exclude the portion of
income from operations attributable to the noncontrolling interests related to partially-owned entities that are
either consolidated or accounted for as equity method investments. Segment operating income attributable to
MPLX LP excludes the operating income related to Predecessors of the HSM, HST, WHC and MPLXT
businesses prior to the dates they were acquired by MPLX LP.
The tables below present information about income from operations and capital expenditures for the reported
segments:
(In millions)
Revenues and other income:
Segment revenues
Segment other income
Total segment revenues and other income
Costs and expenses:
Segment cost of revenues
Segment operating income before portion attributable to noncontrolling interests
and Predecessor
Segment portion attributable to noncontrolling interests and Predecessor
Segment operating income attributable to MPLX LP
(In millions)
Revenues and other income:
Segment revenues
Segment other income
Total segment revenues and other income
Costs and expenses:
Segment cost of revenues
Segment operating income before portion attributable to noncontrolling interests
and Predecessor
Segment portion attributable to noncontrolling interests and Predecessor
Segment operating income attributable to MPLX LP
174
L&S
2017
G&P
Total
$1,480
47
$2,609
1
$4,089
48
1,527
2,610
4,137
692
1,105
1,797
835
53
1,505
170
2,340
223
$ 782
$1,335
$2,117
L&S
2016
G&P
Total
$1,241
53
$2,185
1
$3,426
54
1,294
2,186
3,480
552
907
1,459
742
289
1,279
147
2,021
436
$ 453
$1,132
$1,585
(In millions)
Revenues and other income:
Segment revenues
Segment other income
Total segment revenues and other income
Costs and expenses:
Segment cost of revenues
Segment operating income before portion attributable to noncontrolling interests
and Predecessor
Segment portion attributable to noncontrolling interests and Predecessor
L&S
2015
G&P
Total
$ 913
62
$ 150
—
$1,063
62
975
416
559
237
150
1,125
62
88
12
76
478
647
249
$ 398
Segment operating income attributable to MPLX LP
$ 322
$
(In millions)
Reconciliation to Income from operations:
L&S segment operating income attributable to MPLX LP
G&P segment operating income attributable to MPLX LP
Segment operating income attributable to MPLX LP
Segment portion attributable to unconsolidated affiliates
Segment portion attributable to Predecessor
Income (loss) from equity method investments(1)
Other income—related parties
Unrealized derivative (losses) gains(2)
Depreciation and amortization
Impairment expense
General and administrative expenses
Income from operations
(In millions)
Reconciliation to Total revenues and other income:
Total segment revenues and other income
Revenue adjustment from unconsolidated affiliates
Income (loss) from equity method investments(1)
Other income—related parties
Unrealized derivative gains (losses) related to product sales(2)
Total revenues and other income
2017
2016
2015
$ 782
1,335
$ 453
1,132
$ 322
76
2,117
(178)
53
78
51
(6)
(683)
—
(241)
398
(8)
236
3
2
4
(129)
1,585
(173)
289
(74)
40
(36)
(591)
(130) —
(227)
(125)
$1,191
$ 683
$ 381
2017
2016
2015
$4,137
(403)
78
51
4
$3,480
(402)
(74)
40
(15)
$1,125
(28)
3
2
(1)
$3,867
$3,029
$1,101
(1)
(2)
Includes an impairment expense of $89 million related to one of the Partnership’s equity method
investments for the year ended December 31, 2016.
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During
the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded
as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded
unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.
175
(In millions)
2017
2016
2015
Reconciliation to Net income attributable to noncontrolling interests and
Predecessor:
Segment portion attributable to noncontrolling interests and Predecessor
Portion of noncontrolling interests and Predecessor related to items below segment
$ 223
$ 436
$ 249
income from operations
Portion of operating income attributable to noncontrolling interests of unconsolidated
affiliates
(106)
(203)
(67)
(75)
(32)
(5)
Net income attributable to noncontrolling interests and Predecessor
$
42
$ 201
$ 177
The following table reconciles segment capital expenditures to total capital expenditures:
(In millions)
L&S segment capital expenditures
G&P segment capital expenditures
Total segment capital expenditures
Less: Capital expenditures for Partnership-operated, non-wholly-owned subsidiaries in
2017
2016
2015
$ 498
1,297
$ 550
894
$258
100
1,795
1,444
358
384
131
24
$1,411
$1,313
$334
G&P segment
Total capital expenditures
Total assets by reportable segment were:
(In millions)
Cash and cash equivalents
L&S
G&P
Total assets
December 31,
2017
2016
$
5
4,611
14,884
$
234
2,978
14,297
$19,500
$17,509
Equity method investments included in L&S assets were $1,148 million and $4 million at December 31, 2017
and 2016, respectively. Equity method investments included in G&P assets were $2,862 million and
$2,467 million at December 31, 2017 and 2016, respectively.
11. Major Customers and Concentration of Credit Risk
MPC accounted for 37 percent of the Partnership’s operating revenues for 2017, and 41 percent and 82 percent of
the Partnership’s total revenues and other income for 2016 and 2015, respectively. 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.
The Partnership 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 the Partnership’s overall exposure to credit risk as they may be similarly affected by
changes in economic, regulatory and other factors. The Partnership 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
The Partnership 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 the Partnership’s net income generally are borne by its partners through the
176
allocation of taxable income. On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. The new
law included several key changes to tax law for United States tax payers, as the Partnership is not a taxable entity
the new legislation has no impact for federal tax purposes. The Partnership’s income tax provision (benefit)
primarily results from partnership activity in the states of Texas, Ohio and Tennessee.
As a result of the Class A Reorganization discussed in Note 8, MarkWest Hydrocarbon (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. The Partnership recorded a residual
tax provision during the year ending 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.
The Partnership and MarkWest Hydrocarbon recorded income tax expense (benefit) of $1 million, $(12) million
and $1 million for the years ended December 31, 2017, 2016 and 2015, respectively. The effective tax rate was
less than one percent for 2017, five percent for 2016 and less than one percent for 2015.
The components of the provision for income tax expense (benefit) are as follows:
(In millions)
Current income tax expense:
Federal
State
Total current
Deferred income tax expense (benefit):
Federal
State
Total deferred
Provision (benefit) for income tax
December 31,
2017
2016
2015
$—
2
2
—
(1)
(1)
$
1
$ 4
1
5
(16)
(1)
(17)
$(12)
$—
—
—
3
(2)
1
1
$
A reconciliation of the (benefit) provision for income tax and the amount computed by applying the federal
statutory rate of 35 percent to the income before income taxes for each of the years ended December 31, 2016
and 2015 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
December 31, 2016
MarkWest
Hydrocarbon(1)
Partnership
Eliminations
Consolidated
$(41)
35%
(14)
(2)
3
(1)
1
$461
— %
$
2
— %
—
1
—
—
—
—
—
—
—
—
$—
$422
(14)
(1)
3
(1)
1
$ (12)
(Benefit) provision for income tax
$(13)
$
1
177
(In millions)
Income before provision (benefit) 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
Other
Provision (benefit) for income tax
December 31, 2015
MarkWest
Hydrocarbon(1)
Partnership
Eliminations
Consolidated
$
9
35%
3
—
1
(1)
$
3
$324
— %
—
(2)
—
—
$ (2)
$
1
— %
—
—
—
—
$—
$334
3
(2)
1
(1)
$
1
(1) MarkWest Hydrocarbon paid tax on its share of the Partnership’s income or loss as a result of its ownership
of MPLX LP Class A units through September 1, 2016.
In taxable jurisdictions, the Partnership recorded deferred income taxes on all temporary differences between the
book and tax basis of assets and liabilities. The Partnership has a net deferred tax liability of $5 million and
$6 million for the years ended December 31, 2017 and 2016, 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 the Partnership 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, the Partnership and MarkWest
Hydrocarbon did not have any material uncertain tax positions for the years ended December 31, 2017, 2016 or
2015.
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 benefit of less than $1 million in 2017 and 2016, and a net expense of less than
$1 million for 2015. As of December 31, 2017 and 2016, no interest and penalties were accrued related to income
taxes. In addition, the Partnership and MarkWest Hydrocarbon’s former corporate entity have federal tax years
2013 through 2016 and state tax years 2012 through 2016 open to examination.
13. Inventories
Inventories consist of the following:
(In millions)
NGLs
Line fill
Spare parts, materials and supplies
Total inventories
December 31,
2017
2016
$
4
8
53
$
2
9
44
$ 65
$ 55
178
14. Property, Plant and Equipment
Property, plant and equipment with associated accumulated depreciation is shown below:
(In millions)
Natural gas gathering and NGL transportation pipelines and facilities
Processing, fractionation and storage facilities(1)
Pipelines and related assets
Barges and towing vessels
Terminals and related assets(1)
Land, building, office equipment and other
Construction-in-progress
Total
Less accumulated depreciation
Property, plant and equipment, net
Estimated
Useful Lives
5 - 30 years
10 - 40 years
15 - 49 years
20 years
4 - 30 years
3 - 35 years
December 31,
2017
2016
$ 5,178
3,893
2,253
490
821
770
1,057
14,462
2,275
$ 4,748
3,547
1,799
479
759
757
1,013
13,102
1,694
$12,187
$11,408
(1) Certain prior period amounts have been updated to conform to current period presentation.
Property, plant and equipment includes gross assets acquired under capital leases of approximately $25 million at
December 31, 2017 and 2016, respectively, with related amounts in accumulated depreciation of approximately
$9 million and $8 million at December 31, 2017 and 2016, respectively.
15. Fair Value Measurements
Fair Values—Recurring
The following table presents the financial instruments carried at fair value on a recurring basis as of
December 31, 2017 and 2016 by fair value hierarchy level. The Partnership 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, 2017
December 31, 2016
Assets
Liabilities
Assets
Liabilities
$—
—
$—
$ (2)
(64)
$(66)
$—
—
$—
$ (6)
(54)
$(60)
Level 2 instruments include all crude oil and natural gas swap contracts. The valuations are based on the
appropriate commodity prices and contain no significant unobservable inputs. LIBO rates are an observable input
for the measurement of all derivative contracts. The measurements for commodity contracts contain observable
inputs in the form of forward prices based on WTI crude oil prices; and Columbia Appalachia, Henry Hub, PEPL
and Houston Ship Channel natural gas prices.
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, 2017 used significant
unobservable inputs including: (1) NGL prices interpolated and extrapolated due to inactive markets ranging
from $0.24 to $1.45 and (2) the probability of renewal of 60 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 these
contracts, increases in forward NGL prices result in a decrease in the fair value of the derivative assets and an
179
increase in the fair value of derivative liabilities. The forward prices for NGL products generally increase or
decrease in positive correlation with one another. Increases or decreases in forward NGL prices result in an
increase or decrease in the fair value of the embedded derivative. An increase in the probability of renewal would
result in an increase in the fair value of the related embedded derivative liability.
Fair Values—Nonrecurring
See Note 5 for detail of the Ohio Condensate equity method impairment charge, which included a Level 3
valuation adjustment for the year ended December 31, 2016.
See Note 18 for a rollforward of goodwill, which included a Level 3 valuation adjustment for the year ended
December 31, 2016.
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 loss (realized and unrealized) included in
earnings(1)
Settlements
Fair value at end of period
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
2017
2016
Commodity
Derivative
Contracts (net)
Embedded
Derivatives in
Commodity
Contracts (net)
Commodity
Derivative
Contracts (net)
Embedded
Derivatives in
Commodity
Contracts (net)
$(6)
(5)
9
$(2)
$(54)
(19)
9
$(64)
$
7
(13)
—
$ (6)
$(32)
(29)
7
$(54)
$(2)
$ (6)
$ (6)
$(26)
(1) Gains and losses on commodity derivatives classified as Level 3 are recorded in Product sales in the
accompanying Consolidated Statements of Income. Gains and losses on derivatives embedded in
commodity contracts are recorded in Purchased product costs and Cost of revenues.
Fair Values—Reported
The Partnership’s primary financial instruments are cash and cash equivalents, receivables, receivables from
related parties, accounts payable, payables to related parties and long-term debt. The Partnership’s fair value
assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments,
(2) MPC’s investment-grade credit rating and (3) the historical incurrence of and expected future insignificance
of bad debt expense, which includes an evaluation of counterparty credit risk. The Partnership believes the
carrying values of its current assets and liabilities approximate fair value. The recorded value of the amounts
outstanding under the bank revolving credit facility, if any, approximates fair value due to the variable interest
rate that approximates current market rates. Derivative instruments are recorded at fair value, based on available
market information (see Note 16).
The fair value of the Partnership’s long-term debt is estimated based on recent market non-binding indicative
quotes. The fair value of the steam methane reformer (“SMR”) liability is estimated using a discounted cash flow
approach based on the contractual cash flows and the Partnership’s unsecured borrowing rate. The long-term debt
180
and SMR liability fair values are considered Level 3 measurements. The following table summarizes the fair
value and carrying value of the Partnership’s long-term debt, excluding capital leases, and SMR liability.
(In millions)
Long-term debt
SMR liability
16. Derivative Financial Instruments
December 31,
2017
2016
Fair Value
Carrying Value
Fair Value
Carrying Value
$7,718
104
$6,966
91
$4,953
108
$4,422
96
As of December 31, 2017, the Partnership had the following outstanding commodity contracts that were executed
to manage the cash flow risk associated with future sales of NGLs and purchases of natural gas:
Derivative contracts not designated as hedging instruments
Financial Position
Natural Gas (MMBtu)
NGLs (gal)
Long
Short
Notional Quantity
(net)
928,003
9,586,503
Embedded Derivative—The Partnership 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 in the Consolidated Statements of Income. As of December 31, 2017 and 2016,
the estimated fair value of this contract was a liability of $64 million and $54 million, respectively.
Certain derivative positions are subject to master netting agreements; therefore the Partnership has elected to
offset derivative assets and liabilities that are legally permissible to be offset. As of December 31, 2017 and
2016, there were no derivative assets or liabilities that were offset in the Consolidated Balance Sheets. The
impact of the Partnership’s derivative instruments on its Consolidated Balance Sheets is summarized below:
(In millions)
December 31, 2017 December 31, 2016
Derivative contracts not designated as hedging instruments and their balance sheet location
Asset
Liability
Asset
Liability
Commodity contracts(1)
Other current assets / other current liabilities
Other noncurrent assets / deferred credits and other liabilities
Total
$—
—
$—
$(14)
$—
(52) —
$(66)
$—
$(13)
(47)
$(60)
(1)
Includes embedded derivatives in commodity contracts as discussed above.
For further information regarding the fair value measurement of derivative instruments, including the effect of
master netting arrangements or collateral, see Note 15. See Note 2 for a discussion of derivatives the Partnership
uses and the reasons for them. The Partnership does not designate any of its commodity derivative positions as
hedges for accounting purposes.
181
The impact of the Partnership’s derivative contracts not designated as hedging instruments and the location of
(loss) or gain recognized in the Consolidated Statements of Income is summarized below:
(In millions)
Product sales
Realized (loss) gain
Unrealized gain (loss)
Total derivative loss related to product sales
Purchased product costs
Realized loss
Unrealized loss
Total derivative loss related to purchased product costs
Cost of revenues
Realized loss
Unrealized gain
Total derivative loss related to cost of revenues
Total derivative losses
December 31,
2017
2016
$ (9) $ 2
(15)
4
(5)
(13)
(9)
(10)
(19)
(5)
(22)
(27)
—
—
—
(3)
1
(2)
$ (24) $(42)
17. Debt
The Partnership’s outstanding borrowings at December 31, 2017 and 2016 consisted of the following:
(In millions)
MPLX LP:
Bank revolving credit facility due 2022
Term loan facility due 2019
5.500% senior notes due February 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
5.200% senior notes due March 2047
Consolidated subsidiaries:
MarkWest—4.500%—5.500% senior notes, due 2023-2025
MPL—capital lease obligations due 2020
Total
Unamortized debt issuance costs
Unamortized discount(1)
Amounts due within one year
Total long-term debt due after one year
December 31,
2017
2016
$ 505
—
710
989
1,149
500
1,189
1,250
1,000
$ —
250
710
989
1,149
500
1,189
—
—
63
7
7,362
(27)
(389)
(1)
63
8
4,858
(7)
(428)
(1)
$6,945
$4,422
(1)
Includes $374 million and $420 million discount as of December 31, 2017 and 2016, respectively, related to
the difference between the fair value and the principal amount of the assumed MarkWest debt.
182
The following table shows five years of scheduled debt payments.
(In millions)
2018
2019
2020
2021
2022
Credit Agreements
$
1
1
5
—
505
On November 20, 2014, MPLX LP 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. The term loan
facility was drawn in full on November 20, 2014. In connection with the closing of 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, the Partnership replaced the previously outstanding revolving credit facility
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, the
Partnership prepaid the entire outstanding principal of this loan facility 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 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. The Partnership 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 the Partnership’s long-term debt.
The MPLX Credit Agreement contains certain representations and warranties, affirmative and restrictive
covenants and events of default that the Partnership considers to be usual and customary for an agreement of this
type, including a financial covenant that requires the Partnership 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 the Partnership
and/or certain of its subsidiaries from incurring debt, creating liens on our assets and entering into transactions
with affiliates. As of December 31, 2017, the Partnership was in compliance with the covenants contained in the
MPLX Credit Agreement.
During 2017, the Partnership had no borrowings under the previous bank revolving credit facility. During the
year ended December 31, 2017, the Partnership 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, the Partnership had $505 million outstanding borrowings and $3 million letters of credit outstanding under
the new facility, resulting in total availability of $1.7 billion, or 77.4 percent of the borrowing capacity.
183
During 2016, the Partnership borrowed $434 million under the previous bank revolving credit facility, at an
average interest rate of 1.899 percent, per annum, and repaid $1.3 billion of these borrowings. At December 31,
2016, the Partnership had no borrowings and $3 million letters of credit outstanding under this facility, resulting
in total unused loan availability of $2 billion, or 99.9 percent of the borrowing capacity.
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
5.500% 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
5.200% senior notes due 2047
February 15th and August 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 1st and September 1st
On February 10, 2017, the Partnership 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 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 partnership 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 the Partnership 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. The Partnership 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, 2017 and 2016, 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
December 31, 2017 December 31, 2016
$56
5
86
$61
5
91
184
18. Goodwill and Intangibles
Goodwill
The Partnership 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. The Partnership has performed its annual impairment tests, and no additional
impairments in the carrying value of goodwill were identified in the periods presented.
During the first quarter of 2016, the Partnership 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 the
Partnership’s producer 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, the Partnership recorded an impairment charge of approximately $129 million in the first quarter of
2016. In the second quarter of 2016, the Partnership 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 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.
185
The changes in carrying amount of goodwill were as follows for the periods presented:
(In millions)
Gross goodwill as of December 31, 2015
Accumulated impairment losses
Balance as of December 31, 2015
Purchase price allocation adjustments(1)
Impairment losses
Acquisitions from MPC
Balance as of December 31, 2016
Impairment losses
Acquisitions
Balance as of December 31, 2017
Gross goodwill as of December 31, 2017
Accumulated impairment losses
Balance as of December 31, 2017
L&S
G&P
Total
$141
—
$2,454 $2,595
—
—
141
—
—
21
162
—
—
2,454
(241)
(130)
—
2,083
—
—
2,595
(241)
(130)
21
2,245
—
—
$162
$2,083 $2,245
$162
—
$2,213 $2,375
(130)
(130)
$162
$2,083 $2,245
(1)
See Note 4 for further discussion on purchase price allocation adjustments.
Intangible Assets
The Partnership’s intangible assets as of December 31, 2017 and 2016 are comprised of customer contracts and
relationships, as follows:
(In millions)
Useful Life
Gross
December 31, 2017
Accumulated
Amortization
Net
Gross
December 31, 2016
Accumulated
Amortization
L&S
G&P
N/A
11-25 years
$—
533
$ 533
$—
(80)
$ (80)
$—
453
$ 453
$—
533
$ 533
$ —
(41)
$ (41)
Net
$ —
492
$ 492
Estimated future amortization expense related to the intangible assets at December 31, 2017 is as follows:
(In millions)
2018
2019
2020
2021
2022
Thereafter
Total
$ 38
38
38
38
38
263
$453
186
19. Supplemental Cash Flow Information
(In millions)
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)
Acquisition:
Fair value of MPLX LP units issued(3)
Payable to seller
2017
2016
2015
$ 263
3
$ 213
4
$
13
—
$
6
337
1,133
—
—
$
(3)
$
—
669
—
—
5
—
—
7,326
50
(1) Contribution of assets to Sherwood Midstream and Sherwood Midstream Holdings. See Note 4.
(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. See Note 4.
Limited partner units issued as consideration in the MarkWest Merger. See Note 4.
(3)
Net cash used for financing activities also includes $4.1 million of debt issuance costs incurred to enter into a
commitment letter for a $4.1 billion 364-day term loan. This term loan had not yet been drawn upon as of
December 31, 2017. See Note 24.
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)
Increase (decrease) in capital accruals
2017
2016
2015
$
71
$ (22)
$ 27
20. Equity-Based Compensation
Description of the Plan
The MPLX LP 2012 Incentive Compensation Plan (“MPLX 2012 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 Partnership’s or any of its affiliates’ employees, officers and directors, including directors and officers of
MPC. No more than 2.75 million MPLX LP common limited partner units may be delivered under the MPLX
2012 Plan. Units delivered pursuant to an award granted under the MPLX 2012 Plan may be funded through
acquisition on the open market, from the Partnership or from an affiliate of the Partnership, as determined by the
Board.
Unit-based Awards under the Plan
The Partnership 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.
187
Phantom Units—The Partnership grants phantom units under 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.
The Partnership grants phantom units under 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, 2017 and
2016 were $4 million and $2 million, respectively.
The fair values of phantom units are based on the fair value of MPLX LP common limited partner units on the
grant date.
Performance Units—The Partnership grants performance units under the MPLX 2012 Plan to certain officers of
the general partner and certain eligible MPC officers who make significant contributions to its business. These
awards are intended to have a per unit payout determined by 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 the average of the results of four measurement periods during the 36 month requisite service period.
These performance units will 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 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. The
performance units paying out in units have a weighted average grant date fair value of $0.90 per unit for 2017
and $0.63 per unit for 2016, as calculated using a Monte Carlo valuation model.
Outstanding Phantom Unit Awards
The following is a summary of phantom unit award activity of MPLX LP common limited partner units in 2017:
Outstanding at December 31, 2016
Granted
Settled
Forfeited
Outstanding at December 31, 2017
Vested and expected to vest at December 31, 2017
Convertible at December 31, 2017
Phantom Units
Weighted
Average
Fair Value
Aggregate
Intrinsic
Value
(In millions)
$33.09
36.26
33.45
34.57
34.53
34.52
34.57
$47
$13
Number
of Units
1,173,411
716,587
(419,953)
(118,522)
1,351,523
1,326,940
356,400
The 356,400 convertible units are held by our non-employee directors and certain officers. These units are
non-forfeitable and issuable upon the holder’s departure from service to the company.
188
The following is a summary of the values related to phantom units held by officers and non-employee directors:
Phantom Units
Intrinsic Value of Units
Issued During the Period
(in millions)
Weighted Average Grant Date
Fair Value of Units Granted
During the Period
$15
5
3
$36.26
29.42
35.00
2017
2016
2015
As of December 31, 2017, unrecognized compensation cost related to phantom unit awards was $25 million,
which is expected to be recognized over a weighted average period of 1.9 years.
Outstanding Performance Unit Awards
The following table presents a summary of the 2017 activity for performance unit awards to be settled in MPLX
LP common units:
Outstanding at December 31, 2016
Granted
Settled
Forfeited
Outstanding at December 31, 2017
Performance Units
Number of
Units
1,799,249
1,407,062
(464,500)
(205,217)
2,536,594
Weighted
Average
Fair Value
$0.89
0.90
1.16
0.89
0.85
The number of limited partner units that would be issued upon target vesting, using the closing price of our units
on December 31, 2017 would be 71,514 units.
As of December 31, 2017, 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 1.8 years.
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
1.52%
0.96%
0.95%
2.83 years
2.83 years
2.84 years
49.34%
0.90
$
47.59%
0.63
$
30.12%
1.03
$
2017
2016
2015
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.
Total Unit-Based Compensation Expense
Total unit-based compensation expense for awards settling in MPLX LP common units was $18 million in 2017,
$10 million in 2016 and $4 million in 2015. Approximately $15 million was charged to the MarkWest purchase
price in 2015 for MPLX LP unit-based compensation awards granted in connection with the MarkWest Merger.
189
MPC’s Stock-based Compensation
Stock-based compensation expenses charged to MPLX LP under our employee services agreement with MPC
were $2 million, $5 million and $1 million for 2017, 2016 and 2015, respectively.
21. Lease Operations
Based on the terms of certain natural gas gathering, transportation and processing agreements, the Partnership is
considered to be the lessor under several implicit operating lease arrangements in accordance with GAAP. The
Partnership’s primary 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
2023 and will continue thereafter on a year-to-year basis until terminated by either party. Other significant
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 the Partnership 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 2032.
Based on the terms of the Partnership’s fee-based transportation services and storage services agreements with
MPC, the Partnership is also considered to be a lessor of its pipelines, marine equipment and storage facilities in
accordance with GAAP. The Partnership’s revenue from its implicit lease arrangements, excluding executory
costs, totaled approximately $601 million in 2017, $586 million in 2016 and $127 million in 2015.
The Partnership’s implicit lease arrangements related to the processing facilities contain contingent rental
provisions whereby the Partnership receives additional fees if the producer customer exceeds the monthly
minimum processed volumes. During the years ended December 31, 2017 and 2016, the Partnership received
$9 million and $7 million, respectively, in contingent lease payments.
The following is a schedule of minimum future rental revenue on the non-cancellable operating leases as of
December 31, 2017:
(In millions)
2018
2019
2020
2021
2022
2023 and thereafter
Total minimum future rentals
Related Party
Third Party
Total
$ 247
242
247
135
137
535
$1,543
$ 194
194
193
181
172
320
$1,254
$ 441
436
440
316
309
855
$2,797
190
The following schedule summarizes the Partnership’s investment in assets held for operating lease by major
classes as of December 31, 2017 and 2016:
(In millions)
Natural gas gathering and NGL transportation pipelines and
facilities
Processing, fractionation and storage facilities(1)
Pipelines and related assets
Barges and towing vessels(1)
Terminals and related assets(1)
Construction-in-progress
Total
Less accumulated depreciation
December 31,
2017
2016
$
735
733
253
491
822
85
3,119
(1,056)
$ 650
924
307
479
759
275
3,394
(843)
Property, plant and equipment, net
$ 2,063
$2,551
(1) Certain prior period amounts have been updated to conform to current period presentation.
22. Asset Retirement Obligations
The Partnership’s assets subject to AROs are primarily certain gas-gathering pipelines and processing facilities, a
crude oil pipeline and other related pipeline assets. The Partnership also has land leases that require the
Partnership to return the land to its original condition upon termination of the lease. The Partnership reviews
current laws and regulations governing obligations for asset retirements and leases, as well as the Partnership’s
leases and other agreements.
The following is a reconciliation of the changes in the ARO from January 1, 2016 to December 31, 2017:
(In millions)
AROs at beginning of period
Liabilities incurred
Adjustments to AROs
Accretion expense
AROs at end of period
2017
2016
$ 25
2
—
1
$ 28
$17
8
(1)
1
$25
At December 31, 2017 and 2016, there were no assets legally restricted for purposes of settling AROs. The
AROs have been recorded as part of Deferred credits and other liabilities in the accompanying Consolidated
Balance Sheets.
In addition to recorded AROs, the Partnership has other AROs related to certain gathering, processing and other
assets as a result of environmental and other legal requirements. The Partnership is not required to perform such
work until it permanently ceases operations of the respective assets. Because the Partnership considers the
operational life of these assets to be indeterminable, an associated ARO cannot be estimated and is not recorded.
23. Commitments and Contingencies
The Partnership is the subject of, or a party to, a number of pending or threatened legal actions, contingencies
and commitments involving a variety of matters, including laws and regulations relating to the environment.
Some of these matters are discussed below. For matters for which the Partnership has not recorded an accrued
liability, the Partnership 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.
191
Environmental Matters—The Partnership 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, 2017 and 2016, accrued liabilities for remediation totaled $13 million and $3 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, 2016, there was less than
$1 million in receivables from MPC for indemnification of environmental costs related to incidents occurring
prior to the Initial Offering. At December 31, 2017, there was less than $1 million in payables to MPC for these
costs.
In July 2015, representatives from the EPA and the United States Department of Justice conducted a search at a
MarkWest Liberty Midstream pipeline launcher/receiver site utilized for pipeline maintenance operations in
Washington County, Pennsylvania pursuant to a search warrant. The criminal investigation ended without any
charges against MarkWest Liberty Midstream. With respect to the civil enforcement allegations associated with
permitting or other related regulatory obligations for its launcher/receiver and compressor station facilities in the
region, MarkWest Liberty Midstream and its affiliates have agreed in principle 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.
The Partnership 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—The Partnership, 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. Weston 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. The MPLX Parties seek in excess of $10 million, plus an unspecified amount of punitive
damages. 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 the Partnership cannot be predicted with certainty, and the Partnership is not able
to provide a reasonable estimate of the potential loss (or range of loss), if any, for these claims, the Partnership
believes the resolution of these claims will not 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
192
environmental cleanup costs that may be imposed on Premcor and Apex by the State of Illinois. On September 6,
2016, the trial court approved a settlement between Apex and the State of Illinois whereby Apex agreed to settle
all claims against it for a $10 million payment. Premcor has objected to this ruling and is seeking an appeal.
There are several third-party defendants in the litigation and MPL has asserted cross-claims in contribution
against the various third-party defendants. This litigation is currently pending in the Third Judicial Circuit Court,
Madison County, Illinois. The State’s case against Premcor is currently scheduled to commence trial on June 25,
2018, and Premcor’s claims against third-party defendants, including MPL, is currently scheduled to commence
August 13, 2018. While the ultimate outcome of these litigated matters remains uncertain, neither the likelihood
of an unfavorable outcome nor the ultimate liability, if any, with respect to this matter can be determined at this
time and the Partnership is unable to estimate a reasonably possible loss (or range of loss) for this litigation.
Under the omnibus agreement, MPC will indemnify the Partnership for the full cost of any losses should MPL be
deemed responsible for any damages in this lawsuit. The Partnership is also a party to a number of other lawsuits
and other proceedings arising in the ordinary course of business. While the ultimate outcome and impact to the
Partnership cannot be predicted with certainty, the Partnership 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, the Partnership 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 the Partnership to perform upon the occurrence of a triggering event or condition.
These guarantees and indemnifications are part of the normal course of selling assets. The Partnership 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, 2017, the Partnership’s contractual
commitments to acquire property, plant and equipment totaled $355 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, the Partnership and its affiliates provide guarantees of the Partnership’s
subsidiaries payment and performance obligations in the G&P segment. Certain natural gas processing and
gathering arrangements require the Partnership 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, 2017, management does not believe there are any indications that the Partnership 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.
193
Lease and Other Contractual Obligations—The Partnership executed transportation and terminalling
agreements that obligate us to minimum volume, throughput or payment commitments over the terms of the
agreements, which range from three to ten years. After the minimum volume commitments are met in the
transportation and terminalling agreements, the Partnership pays additional amounts based on throughput. There
are escalation clauses in the transportation and terminalling agreements, which are based on CPI adjustments.
The minimum future payments under these agreements as of December 31, 2017 are as follows:
(In millions)
2018
2019
2020
2021
2022
2023 and thereafter
Total
$ 52
61
62
62
62
275
$574
The Partnership has various non-cancellable operating lease agreements and a long-term propane storage
agreement expiring at various times through fiscal year 2040. Most of these leases include renewal options. The
Partnership also leases certain pipelines under a capital lease that has a fixed price purchase option in 2020.
Future minimum commitments as of December 31, 2017, 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)
2018
2019
2020
2021
2022
Later years
Total minimum lease payments
Less: imputed interest costs
Present value of net minimum lease payments
Capital
Lease
Obligations
Operating
Lease
Obligations
$ 54
42
37
34
28
54
$249
$
$
—
—
—
1
2
5
8
1
7
Operating lease rental expense was:
(In millions)
Minimum rental expense
2017
$64
2016
$57
2015
$ 21
194
SMR Transaction—On September 1, 2009, MarkWest entered into a product supply agreement creating a long-
term contractual obligation for the payment of processing fees in exchange for the entire product processed by
the SMR. See Note 17 for additional discussion. The product received under this agreement is sold to a refinery
customer pursuant to a corresponding long-term agreement. The minimum amounts payable annually under the
product supply agreement, excluding the potential impact of inflation adjustments per the agreement, are as
follows:
(In millions)
2018
2019
2020
2021
2022
2023 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
$ 17
17
17
17
17
126
211
80
40
91
5
$ 86
24. Subsequent Events
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 MPLX LP issued 111.6 million common units and 2.3 million general partner units to
maintain MPC’s two percent GP interest.
Immediately following the dropdown, MPC exchanged its economic GP interest in MPLX LP, which included
IDRs, for 275 million newly issued MPLX LP common units. MPC continues to own the non-economic GP
interest in MPLX LP. For purposes of calculating year to date net income attributable to MPLX LP per unit for
2017, any fourth quarter distributions declared on the GP common units resulting from this transaction were
allocated to the economic GP interests to align with the weighted shares outstanding at December 31, 2017. See
Note 7 for more information on the net income per unit calculation.
On January 2, 2018, the Partnership entered into a term loan agreement with a syndicate of lenders providing for
a $4.1 billion, 364-day term loan facility. The Partnership 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.
On February 8, 2018, the Partnership issued $5.5 billion 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, which was drawn on
February 1, 2018, to fund the cash portion of the consideration MPLX paid MPC for the dropdown of assets on
February 1, 2018. The remaining proceeds were used to repay outstanding borrowings under the MPLX Credit
195
Agreement and the intercompany loan agreement with MPC Investment, as well as for general partnership
purposes.
Select Quarterly Financial Data (Unaudited)
(In millions, except per unit data)
1st Qtr.
2nd Qtr.
3rd Qtr.
4th Qtr.
1st Qtr.(1) 2nd Qtr.(2)
3rd Qtr.
4th Qtr.
2017
2016
Total revenues and other income
Income from operations
Net income (loss)
Net income (loss) attributable to
MPLX LP
Net income (loss) 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
Limited partner units—GP
IDRs—MPC
Redeemable preferred units
Total distributions
$
886 $
265
187
916 $
280
191
980 $ 1,085 $
311
217
335
241
645 $
50
(14)
698 $
128
72
838 $
258
194
150
190
216
238
(60)
19
141
848
247
182
133
$
0.20 $
0.19
0.26 $
0.26
0.29 $
0.29
0.31 $ (0.33) $ (0.11) $
0.31
(0.11)
(0.33)
0.22 $
0.21
0.17
0.17
—
—
—
—
—
—
—
—
$0.5400 $0.5625 $0.5875 $0.6075 $0.5050 $0.5100 $0.5150 $0.5200
$
149 $
47
5
2
60
16
162 $
51
6
5
70
17
170 $
54
7
8
81
16
175 $
58
—
113
—
16
127 $
29
4
—
40
—
131 $
41
4
—
46
9
135 $
44
5
—
49
16
140
45
5
—
52
16
declared
$
279 $
311 $
336 $
362 $
200 $
231 $
249 $
258
(1)
(2)
First quarter 2016 results included goodwill impairment expense of $129 million. See Note 18 for more
information.
Second quarter 2016 results included impairment expense related to equity method investments of
$89 million. See Note 5 for more information.
196
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
None
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
The Partnership’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, 2017. Based on this evaluation, the Partnership’s management, including our
Chief Executive Officer and Chief Financial Officer, concluded that as of December 31, 2017, 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, 2017, 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 the Partnership.
Item 9B. Other Information
None
197
Part III
Item 10. Directors, Executive Officers and Corporate Governance
MANAGEMENT OF MPLX LP
We are managed by the directors and executive officers of our general partner, MPLX GP LLC. Our general
partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future.
MPC indirectly owns all of the membership interests in our general partner. Our general partner has a board of
directors, and our unitholders are not entitled to elect the directors or directly or indirectly to participate in our
management or operations. Our general partner is liable, as general partner, for all of our debts (to the extent not
paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it.
Whenever possible, we intend to incur indebtedness that is non-recourse to our general partner.
The board of directors of our general partner has twelve members. MPC appoints all members to the board of
directors of our general partner, which we may refer to as our board. Our board has determined that each of
Michael L. Beatty, David A. Daberko, Christopher A. Helms, Garry L. Peiffer, Dan D. Sandman and John P.
Surma meets the independence standards in our Governance Principles, has no material relationship with the
Partnership other than that arising solely from the capacity as a director and, in addition, satisfies the
independence requirements of the NYSE, including the NYSE independence standards applicable to the
committees on which each such director serves. Mr. Wilson, who retired from the board of directors of our
general partner effective December 31, 2017, also met the independence standards referred to in the preceding
sentence during his service on the board in 2017. In making its determinations, our board considered that
Mr. Helms serves on the board of directors of Range Resources Corporation. During 2017, MPLX LP provided
gathering, processing and NGL fractionation services to Range Resources, and certain affiliates of our general
partner purchased natural gas from Range Resources. The relationship with Range Resources was entered into in
the ordinary course of business on arms-length terms in amounts and under circumstances that did not affect
Mr. Helms’s independence under our Governance Principles or under applicable law and NYSE listing standards.
Neither we nor our subsidiaries have 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 employed by affiliates of our general partner, but we sometimes refer to these individuals as our
employees for ease of reference.
Director Independence
Although most companies listed on the NYSE are required to have a majority of independent directors serving on
the board of directors of the listed company, the NYSE does not require a publicly traded limited partnership like
us to have a majority of independent directors on our board or to establish a compensation or a nominating and
corporate governance committee. We are, however, required to have an audit committee of at least three
members, and all of our audit committee members are required to meet the independence and financial literacy
tests established by the NYSE and the Exchange Act.
Committees of the Board of Directors
Our board has an audit committee and a conflicts committee, and may have such other committees as the board
shall determine from time to time. The audit committee and the conflicts committee are comprised entirely of
independent directors. Additionally, an executive committee of the board, comprised of Gary R. Heminger and
Dan D. Sandman, has been established 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.
Each of the standing committees of the board of directors has the composition and responsibilities described
below.
198
Audit Committee
Garry L. Peiffer serves as the chairman, and Michael L. Beatty, Christopher A. Helms and Dan D. Sandman are
members, of our audit committee. Our audit committee assists the board of directors 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 is given unrestricted access
to our audit committee.
Our audit committee has a written charter adopted by the board of directors of our general partner, which is
available on our website at http://ir.mplx.com by selecting “Corporate Governance” and clicking on “Board
Committees and Charters,” “Audit Committee,” “Audit Committee Charter.” The audit committee charter
requires our audit committee to assess and report to the board on the adequacy of the charter on an annual basis.
Each of the members of our audit committee is independent as independence is defined in the Exchange Act, and
also satisfies the general independence requirements of the NYSE.
Audit Committee Financial Expert
Based on the attributes, education and experience requirements set forth in the rules of the SEC, the board of
directors of our general partner has determined that Christopher A. Helms and Garry L. Peiffer each qualify as an
“Audit Committee Financial Expert.”
Mr. Helms served in various capacities at NiSource Inc. and its affiliate, NiSource Gas Transmission and
Storage, including as executive vice president and group chief executive officer and group president, Pipeline of
NiSource Inc., where he was also a member of the executive council and corporate risk management committee.
He also served as chief executive officer and executive director of NiSource Gas Transmission and Storage and
has extensive experience in the areas of finance, accounting, compliance, strategic planning and risk oversight.
Mr. Helms has served on the finance and audit committee of another public company.
Mr. Peiffer previously served as the controller and assistant controller of various MPC divisions and was senior
vice president of Finance and Commercial Services of Marathon Ashland Petroleum LLC and its successors for
more than a decade. During his various accounting and finance assignments while at MPC, Mr. Peiffer was
responsible for preparing financial statements, supervising financial statement preparation, reviewing internal
controls and attending audit committee meetings. Mr. Peiffer holds a bachelor’s degree in accounting and passed
the certified public accountant exam in Ohio.
199
Audit Committee Report
The Audit Committee has reviewed and discussed the Partnership’s audited financial statements and its report on
internal control over financial reporting for 2017 with the management of MPLX GP LLC, the Partnership’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 the Partnership’s Annual Report on Form
10-K for the year ended December 31, 2017, for filing with the SEC.
Garry L. Peiffer, Chairman
Michael L. Beatty
Christopher A. Helms
Dan D. Sandman
Conflicts Committee
Christopher A. Helms serves as the chairman, and Michael L. Beatty and Dan D. Sandman are members, of our
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 us or our unitholders. 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 Exchange Act to serve on an audit
committee of a board of directors. 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 has a written charter adopted by the board of directors of our general partner, which is
available on our website at http://ir.mplx.com by selecting “Corporate Governance” and clicking on “Board
Committees and Charters,” “Conflicts Committee,” “Conflicts Committee Charter.” The conflicts committee
charter requires our conflicts committee to assess and report to the board on the adequacy of the charter on an
annual basis. Each of the members of our conflicts committee is independent as independence is defined in the
Exchange Act, and also satisfies the general independence requirements of the NYSE.
200
DIRECTORS AND EXECUTIVE OFFICERS OF MPLX GP LLC
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. Executive officers are
appointed by, and serve at the discretion of, the board of directors. The following table shows information for the
directors, and executive and corporate officers of MPLX GP LLC.
Name
Gary R. Heminger
Michael J. Hennigan
Pamela K.M. Beall
Michael L. Beatty
David A. Daberko
Timothy T. Griffith
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
Frank M. Semple
John P. Surma
Donald C. Templin
Gregory S. Floerke
John S. Swearingen
Raymond L. Brooks(1)
Thomas M. Kelley(1)
C. Michael Palmer(1)
Timothy J. Aydt(1)
Molly R. Benson(1)
Suzanne Gagle
Peter Gilgen(1)
C. Kristopher Hagedorn
(1) Corporate officer.
Age as of
January 31, 2018
Position with MPLX GP LLC
64
58
61
70
72
48
63
66
69
66
63
54
54
58
57
58
64
54
51
52
61
41
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
Executive Vice President, Gathering and Processing
Executive Vice President, Logistics and Storage
Senior Vice President
Senior Vice President
Senior Vice President
Vice President, Operations
Vice President, Corporate Secretary and Chief Compliance Officer
Vice President and General Counsel
Vice President and Treasurer
Vice President and Controller
Gary R. Heminger. Gary R. Heminger was appointed chief executive officer and elected chairman of the board of
directors of our general partner in June 2012. He is also chairman of the board and chief executive officer of
MPC, and a member of the boards of directors of Fifth Third Bancorp and PPG Industries, Inc. Mr. Heminger
began his career with Marathon in 1975 and has served in a variety of capacities. In addition to holding various
finance and administration roles, he spent three years in London as part of the Brae Project and served in several
marketing and commercial positions with Emro Marketing Company, the predecessor of Speedway LLC. He also
served as president of Marathon Pipe Line Company. Mr. Heminger was named vice president of Business
Development for Marathon Ashland Petroleum LLC upon its formation in 1998, senior vice president in 1999
and executive vice president in 2001. Mr. Heminger was appointed president of Marathon Petroleum Company
LLC and executive vice president Marathon Oil Corporation—Downstream in 2001. He was named president
and chief executive officer of MPC on July 1, 2011, and was named chairman in 2016. He served as president of
MPC from 2011 until 2017. Mr. Heminger is past-chairman of the board of trustees of Tiffin University. He
serves on the boards of directors and executive committees of the American Petroleum Institute (API) and the
American Fuel & Petrochemicals Manufacturers (AFPM). He also serves on the board of directors of JobsOhio.
Mr. Heminger is a member of the Oxford Institute for Energy Studies. Mr. Heminger earned a bachelor’s degree
in accounting from Tiffin University in 1976 and a master’s degree in business administration from the
University of Dayton, Ohio, in 1982. He is a graduate of the Wharton School Advanced Management Program at
the University of Pennsylvania.
201
Qualifications: Mr. Heminger has extensive knowledge of all aspects of our business. As our chief executive
officer, he leverages that expertise in advising on the strategic direction of the Partnership and apprising the
board on issues of significance to the Partnership and our industry. Mr. Heminger also serves on two outside
public company boards of directors, which affords him a fresh perspective on management and governance.
Mr. Heminger brings to our board energy industry expertise and a breadth of transactional experience.
Other Public Company Directorships: Marathon Petroleum Corporation (2011 to present); Fifth Third Bancorp
(2006 to present); PPG Industries, Inc. (2017 to present)
Michael J. Hennigan. Michael J. Hennigan was appointed president of our general partner and was elected a
member of the board of directors of our general partner in June 2017. Prior to joining our general partner,
Mr. Hennigan was president, crude, NGL and refined products of the general partner of Energy Transfer Partners
L.P. Prior to that, he served as president and chief executive officer of Sunoco Logistics Partners L.P. where he
was responsible for all operations and business activities, including setting the direction, strategy and vision for
the company from 2012 until 2017. Mr. Hennigan joined Sunoco Logistics as vice president, business
development in 2009. He was named president and chief operating officer in 2010 and was appointed president
and chief executive officer in 2012. Mr. Hennigan has 35 years of industry experience. He graduated from Drexel
University in 1982 with a bachelor’s degree in chemical engineering.
Qualifications: With more than 35 years of industry experience, including as the President and CEO of a
successful growth-oriented master limited partnership, Mr. Hennigan provides a unique perspective and valued
guidance to the board.
Other Public Company Directorships: Sunoco Partners LLC (2010 to 2017); Niska Gas Storage Partners LLC
(2014 to 2016)
Pamela K. M. Beall. Pamela K. M. Beall was elected a member of the board of directors of our general partner in
January 2014 and is executive vice president and chief financial officer of our general partner. She also serves on
the board of directors of National Retail Properties, Inc., the board of trustees of The University of Findlay, and
is a member of The Ohio Society of CPAs. Ms. Beall began her career with Marathon in 1978 as an auditor and
held positions with the Corporate Risk and Environmental Affairs and Domestic Funds organizations before
transferring to USX Corporation as general manager, Treasury Services. She was vice president and treasurer at
NationsRent, Inc. and OHM Corporation, and served on the boards of directors of System One Services, Inc. and
Boyle Engineering. Ms. Beall rejoined Marathon in 2002, as manager, Business Development for Marathon
Ashland Petroleum LLC. She was named director, Corporate Affairs in 2003 and appointed director, Business
Development in 2005. She then served as organizational vice president, Business Development—Downstream
for Marathon Petroleum Company LLC in 2006. Ms. Beall was named vice president of Global Procurement for
Marathon Oil Company in 2007, vice president of Products, Supply & Optimization for Marathon Petroleum
Company LLC in 2010 and vice president, Investor Relations and Government & Public Affairs in 2011. She
was named president of our general partner and senior vice president, Corporate Planning, Government and
Public Affairs of MPC in 2014. Ms. Beall was named executive vice president, Corporate Planning and Strategy
of our general partner and then assumed her current position in 2016. Ms. Beall graduated from The University
of Findlay with a bachelor’s degree in accounting in 1978. In 1984, she received her master’s degree in business
administration from Bowling Green State University. Ms. Beall is licensed as a certified public accountant in
Ohio. She attended the Oxford Institute for Energy Studies in 2003.
Qualifications: As the executive vice president and chief financial officer of our general partner, Ms. Beall has
extensive energy industry experience, specifically in the areas of finance and accounting, business development,
risk management, procurement, investor relations and government affairs. She has also served as a senior
executive in the environmental remediation and industrial products rental sectors, as well as on the boards of
directors of other companies. Ms. Beall brings to our board her knowledge of the Partnership’s business and
operations, and her perspective on its prospects for growth.
202
Other Public Company Directorships: National Retail Properties, Inc. (2016 to present)
Michael L. Beatty. Michael L. Beatty was elected a member of the board of directors of our general partner
effective December 4, 2015, at the time of the MarkWest Merger in fulfillment of our obligations under the
merger agreement with MarkWest to appoint two directors identified by MarkWest to the board of our general
partner effective at the close of the merger. Mr. Beatty was a member of the board of directors of MarkWest’s
general partner from 2008 until the MarkWest Merger, and served on the MarkWest board’s nominating and
corporate governance committee and compensation committee. He also serves on the board of directors of the
Cystic Fibrosis Foundation. Mr. Beatty is a former chairman of the law firm of Beatty & Wozniak, P.C.
headquartered in Denver, Colorado, with a practice focused exclusively on energy, including oil and gas
exploration, regulatory affairs, public lands, litigation and title. Prior to being appointed to the board of directors
of MarkWest Energy Partners, L.P. in 2008, he served as a member of the board of directors of MarkWest
Hydrocarbon. Mr. Beatty 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 is a graduate of the
Harvard Law School.
Qualifications: Through his experience as a director, officer and legal counsel of various energy companies,
Mr. Beatty has extensive experience in the oil and gas industry, including significant experience in government
energy policy and energy regulation. Mr. Beatty brings to our board his vast knowledge of the energy business,
an acute awareness of current developments in the industry, as well as extensive historical knowledge of
MarkWest.
Other Public Company Directorships: Denbury Resources Inc. (2007-2015); MarkWest Energy GP, L.L.C.
(2008-2015)
David A. Daberko. David A. Daberko was elected a member of the board of directors of our general partner
effective October 2012. Mr. Daberko serves on the boards of directors of MPC and RPM International, Inc. He
joined National City Bank in 1968, and went on to hold a number of management positions with National City.
In 1987, Mr. Daberko was elected deputy chairman of National City Corporation, a financial services
corporation, now part of PNC Financial Services Group, Inc., and president of National City Bank in Cleveland.
He served as president and chief operating officer from 1993 until 1995, when he was named chairman of the
board and chief executive officer. He retired as chief executive officer in June 2007 and as chairman of the board
in December 2007. Mr. Daberko holds a bachelor’s degree from Denison University and a master’s degree in
business administration from Case Western Reserve University.
Qualifications: With nearly forty years of experience in the banking industry, including twelve years as the
chairman and chief executive officer of a large financial services corporation, Mr. Daberko has extensive
knowledge of the financial services and investment banking sectors. He also has considerable experience from
his service as a member of other public company boards of directors, including within the energy industry.
Mr. Daberko brings to our board his knowledge of public company financial reporting requirements and an
understanding of the energy business.
Other Public Company Directorships: Marathon Petroleum Corporation (2011 to present); RPM International,
Inc. (2007 to present); Williams Partners GP LLC (2010 to 2015)
Timothy T. Griffith. Timothy T. Griffith was elected a member of the board of directors of our general partner
effective March 2015. Mr. Griffith is also senior vice president and chief financial officer of MPC. Prior to
joining MPC in 2011, he 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
203
officer for Comerica Incorporated and as a derivatives specialist with Citicorp Securities. He was vice president,
Finance and Investor Relations, and treasurer of MPC and our general partner, and the vice president and chief
financial officer of our general partner before assuming his current position in 2015. Mr. Griffith earned a
bachelor’s degree in economics from Michigan State University and a master’s degree in business administration
from the University of Michigan. He is also a chartered financial analyst, a designation he has held since 1995.
He attended the Oxford Institute for Energy Studies in 2013.
Qualifications: Mr. Griffith has extensive experience and held a variety of roles in finance over the course of his
career, dating from his first position in banking, his increasing responsibilities at several publicly traded and
privately sponsored businesses, continuing through his roles managing the financial affairs of both MPC and our
general partner, having served as the treasurer and chief financial officer of both entities. Mr. Griffith has been
deeply involved in the Partnership’s strategy formation and execution.
Other Public Company Directorships: None within the last five years
Christopher A. Helms. Christopher A. Helms was elected a member of the board of directors of our general
partner 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. He also serves on the board of
directors of Range Resources Corporation. 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. 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 his
tenure at 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 graduated with a bachelor of
arts degree from Southern Illinois University at Edwardsville and a juris doctor degree from the Tulane
University School of Law.
Qualifications: As the chief executive officer of an energy midstream logistics company and a former senior
executive with several vertically integrated natural gas companies, Mr. Helms has significant experience in the
oil and natural gas businesses. His background includes overseeing joint ventures and mergers and acquisitions
within the midstream energy sector. He draws upon his prior capacity supervising financial reporting functions in
his role as one of our named audit committee financial experts. Through his service on other public company
boards of directors, Mr. Helms has been exposed to a variety of management styles and governance approaches,
and he serves as chair of our conflicts committee. He brings his considerable midstream energy expertise,
particularly in operations and business combinations, and his skills in the areas of finance, accounting,
compliance, strategic planning and risk oversight, to his service on our board.
Other Public Company Directorships: Range Resources Corporation (2014 to present); Questar Corporation
(2013 to 2016)
Garry L. Peiffer. Garry L. Peiffer was elected a member of the board of directors of our general partner in June
2012. Mr. Peiffer retired as president of our general partner and as executive vice president, Corporate Planning
and Investor & Government Relations of MPC in 2014. He is a member of the board of directors of the Fifth
Third Bank (Northwestern Ohio). Mr. Peiffer is also a member of the boards of trustees of the Blanchard Valley
Health System and the Findlay-Hancock County Community Foundation, and serves on the Blanchard Valley
Port Authority Board. Mr. Peiffer began his career with Marathon Oil Company in 1974. During his career, he
held a variety of management positions with increasing responsibilities. These responsibilities included
supervisor of employee savings and retirement plans, controller of Speedway Petroleum Corporation and
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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 Oil 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. Mr. Peiffer was named senior vice president of
Finance and Commercial Services for Marathon Ashland Petroleum LLC in 1998, executive vice president of
MPC in 2011 and president of our general partner in 2012. Mr. Peiffer graduated with a bachelor’s degree in
accounting from Bowling Green State University in 1974 and passed the certified public accountant exam in
Ohio that same year.
Qualifications: As the retired president of our general partner and retired executive vice president, Corporate
Planning and Investor & Government Relations of MPC, Mr. Peiffer has an extensive energy industry
background. His significant career accomplishments include leading finance organizations, successfully realizing
several joint ventures and corporate reorganizations and implementing new information technology solutions. As
a recognized leader in the industry, Mr. Peiffer led the Partnership through the initial public offering process and
in its first year of operations. He draws upon his prior capacity in various accounting and finance functions in his
role as chair of the audit committee of our board and in serving as a named audit committee financial expert.
Other Public Company Directorships: None within the last five years
Dan D. Sandman. Dan D. Sandman was elected a member of the board of directors of our general partner
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 board of directors of CONSOL
Coal Resources GP LLC, 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 Oil Company in 1973 and served in a series of legal
positions of increasing responsibility. In 1986, Mr. Sandman was appointed general counsel and secretary of
Marathon, and 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 responsible at various times for management
and oversight of aspects of Human Resources, Executive Compensation, Public Relations, Environmental and
Government Affairs, as well as the Law Organization and the corporate secretary’s office. Mr. Sandman
graduated with a bachelor of arts degree from The Ohio State University in 1970 and a juris doctor degree from
The Ohio State University College of Law in 1973. Mr. Sandman attended the Stanford Executive Program in
1989.
Qualifications: As the former vice chairman and chief legal officer of a large industrial firm, Mr. Sandman has
considerable experience in legal and business affairs, transactional law, regulatory compliance and corporate
governance, ethics and risk management matters that may arise in the context of the Partnership’s business. He
has also served as general counsel of a large integrated oil company and thus has an energy industry background.
Mr. Sandman teaches corporate governance law as an adjunct professor and serves on the board of directors of a
publicly held company and a private company, each engaged in manufacturing. Mr. Sandman brings to our board
his valuable perspective, specifically on matters of strategic focus, governance and leadership.
Other Public Company Directorships: CONSOL Coal Resources GP LLC (2017 to present)
Frank M. Semple. Frank M. Semple was elected a member of the board of directors of our general partner
effective December 4, 2015, at the time of the MarkWest Merger in fulfillment of our obligations under the
merger agreement with MarkWest to appoint two directors identified by MarkWest to the board of our general
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partner effective at the close of the merger. He also serves as a member of the board of directors of MPC.
Mr. Semple was appointed vice chairman of our general partner effective at the close of the MarkWest Merger
and served in that position until his retirement effective November 1, 2016. Prior to joining our general partner,
Mr. Semple was the president and chief executive officer of MarkWest beginning on November 1, 2003, and was
elected chairman of the board in 2008. Prior to joining MarkWest he completed a 22-year career with The
Williams Companies, Inc. (“Williams”) and WilTel Communications. He served as the chief operating officer of
WilTel Communications, senior vice president/general manager of Williams Natural Gas Company, vice
president of operations and engineering for Northwest Pipeline Company and division manager for Williams
Pipe Line Company. Prior to joining Williams, Mr. Semple served in the United States Navy. Mr. Semple earned
a bachelor’s degree in mechanical engineering from the United States Naval Academy. He has completed the
Program for Management Development at Harvard Business School.
Qualifications: As the former chairman and chief executive officer of MarkWest, Mr. Semple has proven
leadership abilities in managing a complex business and a deep understanding of the midstream sector.
Mr. Semple has significant experience regarding operations, strategic planning, finance and corporate
governance matters.
Other Public Company Directorships: Marathon Petroleum Corporation (2015 to present); MarkWest Energy
GP, L.L.C. (2003-2015)
John P. Surma. John P. Surma was elected a member of the board of directors of our general partner effective
October 2012. Mr. Surma is a member of the boards of directors of MPC, Ingersoll-Rand plc and Concho
Resources Inc. He is on the boards of directors of the National Safety Council and the University of Pittsburgh
Medical Center. He formerly served as the chair of the board of directors 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 and served as its vice chairman. Mr. Surma retired as the chief executive officer of
United States Steel Corporation, an integrated steel producer, in September 2013, and as executive chairman in
December 2013. Prior to joining United States Steel, Mr. Surma served in several executive positions with
Marathon Oil Corporation. He was named senior vice president, Finance & Accounting of Marathon Oil
Company in 1997, president, Speedway SuperAmerica LLC in 1998, senior vice president, Supply and
Transportation of Marathon Ashland Petroleum LLC in 2000 and president of Marathon Ashland Petroleum LLC
in 2001. Prior to joining Marathon, Mr. Surma worked for Price Waterhouse LLP where he was admitted to the
partnership in 1987. In 1983, Mr. Surma participated in the President’s Executive Exchange Program in
Washington, D.C., where he served as executive staff assistant to the vice chairman of the Federal Reserve
Board. Mr. Surma earned a bachelor of science degree in accounting from Pennsylvania State University in 1976.
Qualifications: As the retired chairman and chief executive officer of a large industrial firm, Mr. Surma has a
broad range of experiences that shape his viewpoint on the strategic direction and operations of the Partnership.
Mr. Surma brings to the board his significant experience in public accounting and in executive leadership in the
energy and steel industries. His service on other public company boards of directors also affords him a
perspective that is particularly valuable to our board.
Other Public Company Directorships: Marathon Petroleum Corporation (2011 to present); Concho Resources
Inc. (2014 to present); Ingersoll-Rand plc (2012 to present); United States Steel Corporation (2001 to 2013)
Donald C. Templin. Donald C. Templin was elected a member of the board of directors of our general partner in
June 2012. He is president of MPC. He is a member of the board of directors of Calgon Carbon Corporation.
Mr. Templin is chairman of the Downstream Committee of API. Prior to joining MPC in 2011, Mr. Templin was
the managing partner of the audit practice for PricewaterhouseCoopers LLP (“PwC”) in Georgia, Alabama and
Tennessee. While at PwC, he completed more than 25 years of providing auditing and advisory services to a
wide variety of private, public and multinational companies. Mr. Templin joined PwC in Pittsburgh in 1984.
While at PwC, he went on to serve in London, Kazakhstan and Baltimore before assuming his position in Atlanta
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in 2009. Mr. Templin was appointed senior vice president and chief financial officer of MPC in 2011, vice
president and chief financial officer of our general partner in 2012, executive vice president, supply,
transportation and marketing of MPC in 2015, president of our general partner and executive vice president of
MPC in 2016, and assumed his current position in 2017. Mr. Templin is a graduate of Grove City College, a
certified public accountant and a member of the American Institute of Certified Public Accountants. He attended
the Oxford Institute for Energy Studies in 2012.
Qualifications: As the current president of MPC, along with his prior positions with both MPC and our general
partner, Mr. Templin has direct insight into all aspects of our business, from an operational and commercial
perspective, and in the areas of accounting, audit and financial management. Mr. Templin also has a long and
successful background in public accounting for energy sector clients and draws from that experience on matters
relating to public company financial reporting requirements. Mr. Templin serves on one outside public company
board of directors, which provides him exposure to perspectives on management and governance that may differ
from those of our general partner. Mr. Templin brings his extensive energy industry background, particularly his
expertise in accounting, financial reporting and strategic planning, to his service on our board.
Other Public Company Directorships: Calgon Carbon Corporation (2013 to present)
Gregory S. Floerke. Gregory S. Floerke is executive vice president, Gathering and Processing of our general
partner. He joined our general partner in December 2015, at the time of the MarkWest Merger and was named
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 our general partner, Mr. Floerke was executive vice president and chief commercial officer at MarkWest
beginning in 2015 and senior vice president, Northeast region at MarkWest beginning in 2013. Previously,
Mr. Floerke held senior management positions at Access Midstream Partners, L.P. from 2011 until 2013, and
One Communications Corp. from 2007 until 2011.
John S. Swearingen. John S. Swearingen is executive vice president, Logistics and Storage of our general partner.
He was previously vice president, crude oil and refined products pipelines and chief operating officer of pipeline
operations of our general partner and senior vice president, Transportation and Logistics of MPC from 2015 until
he was appointed executive vice president, Transportation and Logistics of our general partner in 2017. He was
appointed to his current position in 2018. Prior to that, Mr. Swearingen was vice president and chief operating
officer since 2014. Previously, Mr. Swearingen served in various leadership positions, including as vice
president, Health, Environment, Safety and Security beginning in 2011 and president of Marathon Pipeline LLC
beginning in 2009.
Raymond L. Brooks. Raymond L. Brooks is senior vice president of our general partner and senior vice president,
Refining of MPC. He was appointed to his current position with our general partner effective February 1, 2018,
and has served in his position with MPC since March 1, 2016. Prior to these appointments, Mr. Brooks was
general manager, Galveston Bay refinery of MPC beginning in February 2013, general manager, Robinson
refinery of MPC beginning in 2010 and general manager, St. Paul Park, Minnesota refinery (no longer owned by
MPC) beginning in 2006.
Thomas M. Kelley. Thomas M. Kelley is senior vice president of our general partner and senior vice president,
Marketing of MPC. He was appointed to his current position with our general partner effective February 1, 2018,
and has served in his position with MPC since June 30, 2011. Prior to these appointments, Mr. Kelley served as
senior vice president, Marketing for Marathon Petroleum Company LP beginning in January 2010.
C. Michael Palmer. C. Michael Palmer is senior vice president of our general partner and senior vice president,
Supply Distribution and Planning of MPC. He was appointed to his current position with our general partner
effective February 1, 2018, and has served in his position with MPC since June 30, 2011. Prior to these
appointments, Mr. Palmer served as vice president, Crude, Supply and Logistics of Marathon Petroleum
Company LP beginning in June 2010.
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Timothy J. Aydt. Timothy J. Aydt is vice president, operations of our general partner and president of Marathon
Pipe Line. He was appointed to his current positions effective January 1, 2017. Prior to these appointments,
Mr. Aydt served as the Terminal, Transport and Rail general manager of MPC beginning in 2013, and the project
director for the Detroit Heavy Oil Upgrade Project beginning in 2008.
Molly R. Benson. Molly R. Benson is vice president, corporate secretary and chief compliance officer of our
general partner and of MPC. She was appointed to her current position effective March 1, 2016. Prior to this
appointment, Ms. Benson was assistant general counsel, Corporate and Finance of MPC beginning in April 2012,
and group counsel, Corporate and Finance of MPC beginning in 2011.
Suzanne Gagle. Suzanne Gagle is vice president and general counsel of our general partner and of MPC. She was
appointed to her current position with our general partner effective October 1, 2017, and has served in her
position with MPC since March 1, 2016. Prior to these appointments, Ms. Gagle was 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.
Peter Gilgen. Peter Gilgen is vice president and treasurer of our general partner. He was appointed to his current
position effective February 1, 2017. Prior to this appointment, Mr. Gilgen was assistant treasurer of MPC
beginning in 2012, and Corporate Finance and Banking manager beginning in 2011.
C. Kristopher Hagedorn. C. Kristopher Hagedorn is vice president and controller of our general partner. He
joined our general partner in 2017. Prior to joining our general partner, Mr. Hagedorn was vice president and
controller at CONSOL Energy Inc. 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
from 2014 to 2015. Previously, Mr. Hagedorn served in positions of increasing responsibility with
PricewaterhouseCoopers beginning in 1998.
GOVERNANCE PRINCIPLES
Our governance principles are available on our website at http://ir.mplx.com by selecting “Corporate
Governance” and clicking on “Governance Principles.” In summary, our Governance Principles provide the
functional framework of the board of directors of our general partner, including its roles and responsibilities.
These principles also address board independence, committee composition, the process for director selection and
director qualifications, the board’s performance review, the board’s planning and oversight functions, director
compensation and director retirement and resignation.
LEADERSHIP STRUCTURE OF THE BOARD
As provided in our governance principles, our board of directors does not have a policy requiring the roles of
chairman of the board and chief executive officer to be filled by separate persons or requiring the chairman of the
board to be a non-management director. Mr. Heminger, our general partner’s chief executive officer, serves as
chairman of the board. Our board has determined that due to his extensive knowledge of all aspects of the
Partnership’s business, as well as the continued relationship between the Partnership and MPC, Mr. Heminger is
in the best position to lead the board as its chairman.
Our governance principles also provide that when the role of chairman of the board is filled by the chief
executive officer, the board may appoint an independent director as a “lead director” to preside over executive
sessions of the board or other board meetings when the chairman is absent. Dan D. Sandman, an independent
director, serves as the “lead director” of the board of directors of our general partner.
The leadership structure of our board, with the combined role of chairman and chief executive officer and the
independent oversight promoted by our lead director, offers a balanced approach that our board believes serves
the Partnership well at this time.
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COMMUNICATIONS FROM INTERESTED PARTIES
All interested parties may communicate directly with our independent directors by submitting a communication
in an envelope addressed to the “Board of Directors (non-management members)” in care of the corporate
secretary of our general partner, MPLX GP LLC, 200 East Hardin Street, Findlay, Ohio 45840. Additionally,
interested parties may communicate with our audit and conflicts committee chairs and the independent directors,
individually or as a group, by sending an e-mail to the following e-mail addresses:
Audit Committee Chair
Conflicts Committee Chair
Independent Directors
auditchair@mplx.com
conflictschair@mplx.com
non-managedirectors@mplx.com
The corporate secretary of our general partner will forward to the directors all communications that, in the
corporate secretary’s judgment, are appropriate for consideration by the directors. Examples of communications
that would not be considered appropriate include commercial solicitations.
BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Exchange Act, as amended, requires the directors and executive officers of our general
partner and persons who own more than 10 percent of a registered class of our equity securities, to file reports of
beneficial ownership on Form 3 and changes in beneficial ownership on Forms 4 or 5 with the SEC. Based solely
on our review of the reporting forms and written representations provided to us from the persons required to file
reports, we believe that each of the directors and executive officers of our general partner and persons who own
more than 10 percent of a registered class of our equity securities has complied with the applicable reporting
requirements for transactions in our equity securities during the fiscal year ended December 31, 2017.
CODE OF BUSINESS CONDUCT
Our code of business conduct is available on our website at http://ir.mplx.com by selecting “Corporate
Governance” and clicking on “Code of Business Conduct.”
CODE OF ETHICS FOR SENIOR FINANCIAL OFFICERS
Our code of ethics for senior financial officers is available on the Partnership’s website at http://ir.mplx.com by
selecting “Corporate Governance” and clicking on “Code of Ethics for Senior Financial Officers.” This code of
ethics applies to our chairman of the board of directors and chief executive officer, chief financial officer, chief
accounting officer, controller and treasurer and other persons performing similar functions, as well as to those
designated as senior financial officers by our chairman and chief executive officer or our audit committee.
Under this code of ethics, these senior financial officers shall, among other things:
•
•
•
•
act with honesty and integrity, including the ethical handling of actual or apparent conflicts of interest
between personal and professional relationships;
provide full, fair, accurate, timely and understandable disclosure in reports and documents filed with,
or submitted to, the SEC, and in other public communications;
comply with applicable laws, governmental rules and regulations, including insider trading laws; and
promote the prompt internal reporting of potential violations or other concerns related to this code of
ethics to the chair of the audit committee and to the appropriate person or persons identified in the code
of business conduct.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The chairman and the independent directors of our board review compensation related matters for our general
partner. During 2017, none of our general partner’s executive officers served as a member of a compensation
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committee or board of directors of any unaffiliated entity that has an executive officer serving as an independent
director on our board. Gary R. Heminger serves as an officer and director of our general partner and MPC.
Item 11. Executive Compensation
COMPENSATION COMMITTEE REPORT
The chairman of the board and independent directors of our general partner (for purposes of this report and
certain disclosures made within the following Compensation Discussion and Analysis, the “Committee”) have
reviewed and discussed MPLX LP’s Compensation Discussion and Analysis for 2017 with MPLX LP’s
management. Based on its review and discussions, the Committee has recommended to the board of directors of
our general partner that the Compensation Discussion and Analysis be included in this Annual Report on Form
10-K for the fiscal year ended December 31, 2017.
Gary R. Heminger, Chairman
Michael L. Beatty
David A. Daberko
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
John P. Surma
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COMPENSATION DISCUSSION AND ANALYSIS
In this section, we describe the material components of our general partner’s executive compensation program
for our named executive officers (“NEOs”) and we explain how and why 2017 compensation decisions were
made. We recommend that this compensation discussion and analysis be read in conjunction with the tabular and
narrative disclosures in the “Executive Compensation” section of this Annual Report on Form 10-K.
Named Executive Officer Compensation
Our NEOs consist of the principal executive officer (“PEO”), principal financial officer (“PFO”), and the
executive officers of our general partner as of December 31, 2017, listed below. The names and titles of our six
NEOs as of that date were as follows:
Name
Title (as of December 31, 2017)
Gary R. Heminger
Pamela K.M. Beall
Michael J. Hennigan
C. Corwin Bromley
Gregory S. Floerke
Donald C. Templin
Chairman of the Board and Chief Executive Officer
Executive Vice President and Chief Financial Officer
President
Executive Vice President
Executive Vice President, MarkWest Operations
Former President, MPLX
Mr. Hennigan was appointed MPLX President on June 20, 2017, succeeding Mr. Templin who was appointed
MPC President effective July 1, 2017.
Mr. Bromley retired effective January 1, 2018.
Overview
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. As consideration for MPC’s and its affiliates’ provision of these services, we pay MPC a fixed amount
that reflects the cost incurred by MPC and its affiliates in providing the services of our executive officers, in
accordance with the terms of the omnibus agreement.
Mr. Heminger generally devotes less than a majority of his total business time to our general partner and us and
receives compensation from MPC that is not intended as remuneration for the services he provides to our
business (including the business of our general partner). With respect to the services he provides to our business,
we reimburse MPC for the fixed fee amount in accordance with the terms of the omnibus agreement.
Mr. Heminger’s fixed fee and his long-term incentive grants made by our general partner, which represent all of
the material elements of his compensation attributable to the services he provides to our business, are disclosed in
this compensation discussion and analysis. In 2017, Ms. Beall and Messrs. Hennigan, Bromley and Floerke
devoted substantially all of their total business time to our business; accordingly, all of the material elements of
their compensation are disclosed in this compensation discussion and analysis. Mr. Templin devoted 90 percent
of his total business time during his tenure as MPLX President to our business; thus, the material elements of his
compensation for the services he provides to our business are discussed below, subject to appropriate proration.
Our general partner has adopted the MPLX 2012 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. Any
award under the MPLX 2012 Plan for our NEOs must be first recommended by the compensation committee of
the board of directors of MPC (the “MPC Compensation Committee”). If a recommendation is made, an award
will be granted to one of our NEOs only if it is approved by the board of directors of our general partner, which
is typically done on an annual basis.
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Except with respect to awards that may be granted under our MPLX 2012 Plan, all responsibility and authority
for compensation-related decisions for our NEOs remain with the MPC Compensation Committee, currently
comprised of five independent directors, and are not subject to any approval by us, the board of directors of our
general partner or any committees thereof. Other than awards granted under the MPLX 2012 Plan, MPC has the
ultimate decision-making authority with respect to the total compensation of its and its subsidiaries’ executive
officers and employees. The fixed amount charged to us for the services of our NEOs is provided for in the
omnibus agreement as previously described in this Annual Report on Form 10-K.
All final determinations with respect to awards under the MPLX 2012 Plan will be made by the board of
directors of our general partner or any committee thereof that may be established for such purpose.
Compensation Consultants
Our general partner does not have a standing compensation committee, and its board of directors has not hired its
own compensation consultant. Pay Governance, LLC (“Pay Governance”) has been engaged to provide
compensation consulting services and benchmarking information to the MPC Compensation Committee. The
advice Pay Governance provides to the MPC Compensation Committee is typically shared with the board of
directors of our general partner for use in making certain compensation decisions with respect to our NEOs.
Compensation of Our New President
Concurrent with the announcement of the appointment of Mr. Templin, MPLX’s former president, to his new
role as President of MPC, MPLX announced that the board of directors of our general partner appointed
Mr. Hennigan to succeed Mr. Templin as President of our general partner effective June 20, 2017.
Mr. Hennigan’s annual base salary is $800,000 with an annual bonus target of 100 percent of his base salary.
Mr. Hennigan received a $1,000,000 cash sign-on bonus.
Mr. Hennigan also received grants of MPLX phantom units with an intended value of $1,600,000 and MPC
restricted stock with an intended value of $400,000, which were granted as part of Mr. Hennigan’s regular annual
compensation and in lieu of regular annual long-term incentive grants, which had been made to other NEOs
earlier in the year. These units/shares will vest in three equal installments on the first, second and third
anniversaries of the date of grant. In addition, Mr. Hennigan received special, one-time grants of MPLX phantom
units with an intended value of $2,400,000 and MPC restricted stock with an intended value of $600,000, both of
which will fully vest in one installment on the third anniversary of the grant date. These equity awards were
intended to partially replace the outstanding equity Mr. Hennigan forfeited upon termination with his former
employer.
Mr. Hennigan participates in the same executive officer compensation programs and benefit plans as other NEOs.
He does not have an employment agreement.
ELEMENTS OF COMPENSATION
Base Compensation
Our NEOs earn a base salary for their services to MPC and to us, which is paid by MPC or its affiliates. We incur
only a fixed expense per month with respect to the compensation paid to each of our NEOs, as provided for in the
omnibus agreement. As of December 31, 2017, we incurred the annualized fixed fee for Mr. Heminger of
$1,310,000. The MPC Compensation Committee made the following base salary adjustments in 2017, which
were paid by MPC:
Name
Title
Gregory S. Floerke Executive Vice President, MarkWest Operations
Donald C. Templin Former President, MPLX
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Previous
Base Salary
($)
Base Salary
Effective
Dec. 31,
2017 ($)(1)
420,000
720,000
450,000
742,500
Increase
(%)
7.1
3.1
(1)
The amount for Mr. Templin represents his base salary on June 20, 2017, when his tenure as MPLX
President ended.
The increases for Messrs. Floerke and Templin reflect an adjustment to bring the base salary for each closer to
the market median for his position. Annual base salary adjustments are made on April 1 of each year. As
Mr. Hennigan was not employed on that date, he was not eligible for an increase. Ms. Beall’s and Mr. Bromley’s
base salaries were deemed to be market competitive and therefore did not receive an adjustment.
Annual Cash Bonus Payments
Ms. Beall and Messrs. Hennigan, Bromley, Floerke and Templin were eligible to earn an annual bonus payment
under MPC’s Annual Cash Bonus (“ACB”) program for the services they provide to our business. Any bonus
payment made to our NEOs will be determined solely by MPC without input from us or the board of directors of
our general partner. Under the provisions of the omnibus agreement, no portion of any bonus paid by MPC to our
NEOs will be charged back to us. The ACB program is a variable incentive program intended to motivate and
reward NEOs for achieving short-term (annual) financial and operational business objectives that drive overall
shareholder value while encouraging responsible risk-taking and accountability. The majority (70 percent) of the
ACB is determined by pre-established financial and operational (including environmental and safety)
performance measures and the remaining 30 percent is driven by a number of discretionary factors, including
adjustments due to the volatility in petroleum-related commodity prices throughout the year, which makes it
difficult to establish reliable, pre-determined goals.
The financial and operational performance metrics used for the 2017 ACB program were:
Performance Metric
Description
Operating Income Per Barrel(1)
EBITDA(2)
Mechanical Availability(3)
Selling, General and
Administrative Costs (SG&A)(4)
Distributable Cash Flow (DCF)
Attributable to MPLX(5)(6)
Asset Dropdown Readiness and
Execution(6)
Measures domestic operating income per
barrel of crude oil throughput, adjusted
for unusual business items and accounting
changes. This metric compares a group of
nine integrated or downstream companies,
including MPC.
As derived from MPC’s consolidated
financial statements and adjusted for
certain items.
Measures the mechanical availability and
reliability of MPC’s and MPLX’s
operated Refining and Marketing and
Midstream segment operations.
MPC’s actual selling, general and
administrative expenses adjusted for
certain items.
As derived from MPLX’s consolidated
financial statements and disclosed to
investors as part of the quarterly earnings
materials.
Actual readiness and execution of
dropping assets and services generating a
specified amount of EBITDA to MPLX.
Type of Measure
Financial (relative)
Financial (absolute)
Operational (absolute)
Financial (absolute)
Financial (absolute)
Financial (absolute)
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Performance Metric
Description
Type of Measure
Responsible Care(7)
Marathon Safety Performance
Index(8)
Process Safety Events Rate
Designated Environmental
Incidents
Quality
The metrics below measure MPC’s
success in meeting its goals for the health
and safety of its employees, contractors
and neighboring communities, while
continuously improving on its
environmental stewardship commitment
by minimizing its environmental impact.
Measurement of MPC’s success and
commitment to employee safety. Goals
are set annually at best-in-class industry
performance, focusing on continual
improvement. This includes common
industry metrics such as Occupational
Safety and Health Administration (or
OSHA) Recordable Incident Rates and
Days Away Rates.
Measures the success of MPC’s ability to
identify, understand and control process
hazards, which can be defined as
unplanned or uncontrolled releases of
highly hazardous chemicals or materials
that have the potential to cause
catastrophic fires, explosions, injury,
plant damage and high-potential near
misses or toxic exposures.
Measures environmental performance and
consists of tracking certain: a) releases of
hazardous substances into air, water or
land; b) permit exceedances; and c)
government agency enforcement actions.
Measures the impact of product quality
incidents and cumulative costs to MPC
(no Category 4 Incident, and costs of
Category 3 Incidents).(9)
Operational (absolute)
Operational (absolute)
Operational (absolute)
Operational (absolute)
(1)
(2)
This is a per barrel measure of throughput—U.S. downstream segment income adjusted for certain items. It
includes a total of nine comparator companies (including MPC). Comparator company income is adjusted
for special items or other like items as adjusted by MPC. The comparator companies for 2017 were:
Andeavor; BP p.l.c.; Chevron Corporation; ExxonMobil Corporation; HollyFrontier Corporation; PBF
Energy; Phillips 66; and Valero Energy Corporation. This is a non-GAAP performance metric which is
calculated as income before taxes, as presented in MPC’s audited consolidated financial statements, as
adjusted, divided by the total number of barrels of crude oil throughput at the peer’s respective U.S. refinery
operations. To ensure consistency of this metric when comparing results to the comparator group,
adjustments to MPC’s and peer company segment income before taxes are sometimes necessary to remove
certain items such as the gain/loss on asset sales and certain asset and goodwill impairment expenses.
This is a non-GAAP performance metric. It is calculated as MPC’s earnings before interest and financing
costs, interest income, income taxes, depreciation and amortization expense adjusted to exclude the effects
of impairment expense, pension settlement expense, inventory market valuation adjustments, EBITDA
related to acquisitions and divestitures and certain other non-cash adjustments.
214
(3) Mechanical availability represents the percentage of capacity available for critical downstream and
(4)
(5)
(6)
(7)
(8)
midstream equipment to perform its primary function for the full year.
This represents SG&A expenses per MPC’s consolidated financial statements adjusted to exclude costs
related to employee bonus program accruals, pension settlement expense, credit card processing fees,
allocations of employee benefit expenses, inter-department cost allocations and expenses related to
acquisitions and divestitures.
This is a non-GAAP performance metric. A reconciliation to the nearest GAAP financial measure is
included in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations—Non-GAAP Financial Information.
Subject to limitations imposed by Section 162(m) of the Code, the Company reserved the right to recalibrate
the performance levels if significant tax reform suggested a portion of the dropdowns should be delayed into
2018.
Excludes Speedway.
This metric measures the personal safety performance level of MPC employees and contractors based on
lost time, the number of OSHA recordable injuries or fatalities, and restricted duty incidents. In the event of
a fatality, payout is determined by the MPC Compensation Committee.
(9) A Category 4 Incident is one that involves a fatality. Category 3 Incidents include those in which: we incur
out-of-pocket costs for incident response and recovery activities, mitigation of customer claims or
regulatory penalties in excess of $100,000; a media advisory is issued by MPC; or the extenuating
circumstances are deemed to be of such severity by MPC’s Quality Committee that a recommendation for
this category is made to the MPC Quality Steering Committee and is subsequently approved. Quality
incidents exclude MarkWest assets. Category 3 Incidents exclude assets acquired in 2017; Category 4
Incidents include assets acquired in 2017.
The threshold, target and maximum levels of performance for each performance metric were established for 2017
by evaluating factors such as performance achieved in the prior year(s), anticipated challenges for 2017, MPC’s
business plan and overall strategy. At the time the performance levels were set for 2017, the threshold levels
were viewed as likely achievable, the target levels were viewed as challenging but achievable, and the maximum
levels were viewed as extremely difficult to achieve.
215
The table below provides both the goals for each metric and MPC’s performance achieved in 2017:
Performance Metric
Operating Income Per
Barrel
EBITDA(1)
Mechanical
Availability
Selling, General and
Administrative
Costs(1)
Distributable Cash
Flow Attributable
to MPLX LP(1)
Asset Dropdown
Readiness and
Execution
Responsible Care
Marathon Safety
Performance Index
Process Safety Events
Rate
Designated
Environmental
Incidents
Quality
Threshold Level
50% Payout
Target Level
100% Payout
Maximum Level
200% Payout
Performance Metric
Result
Target
Weighting
Performance
Achieved
5th or 6th
Position
3,500
$
3rd or 4th
Position
5,800
$
1st or 2nd
Position
6,500
$
93.5%
94.5%
95.5%
$
1,915
$
1,875
$
1,845
$
1,200
$
1,400
$
1,450
2nd Position
(200% of target)
$6,026
(132% of target)
95.7%
(200% of target)
$1,839
(200% of target)
$1,628
(200% of target)
15.0%
30.0%
10.0%
13.2%
10.0%
20.0%
5.0%
10.0%
5.0%
10.0%
See Footnote for Performance Target
Breakdown(2)
Maximum
(200% of target)
5.0%
10.0%
1.00
0.58
72
0.65
0.39
51
0.40
0.31
30
0.95
(57% of target)
0.31
(200% of target)
31
(200% of target)
5.0%
2.9%
5.0%
10.0%
5.0%
10.0%
$500,000
$250,000
$125,000
$0
(200% of target)
Total
5.0%
10.0%
70.0% 126.1%
(1) Represented in millions.
(2)
Threshold: Complete readiness for dropping an estimated $800 million of EBITDA generating assets into
MPLX by December 31, 2017.
Target: Complete Threshold level and execute drops totaling an estimated $600 million in EBITDA
generating assets into MPLX by December 31, 2017.
Maximum: Complete Threshold level and execute drops totaling an estimated $800 million in EBITDA
generating assets into MPLX by December 31, 2017.
The MPC Compensation Committee determined Maximum performance was achieved as definitive
agreements for the contribution of $1.4 billion in EBITDA-generating assets and services were executed in
2017 with closing for a portion deferred until the first quarter of 2018 due to tax reform.
216
Organizational and Individual Performance Achievements for the 2017 ACB Program
At the beginning of the year, each NEO develops individual performance goals relative to their 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 2017 fell into the following general categories:
Mr. Hennigan Ms. Beall Mr. Floerke Mr. Bromley Mr. Templin
Talent development, retention, succession and
acquisition
Enhancement of unitholder value through return of
capital and unlocking midstream asset value
System integration, optimization and
debottlenecking
Growth through organic expansion and acquisition
opportunities
Preparation of MPC assets for potential dropdown
to MPLX LP
Progress on diversity initiatives
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
MPC’s Chairman and CEO reviews the organizational and individual performance of our NEOs and makes
annual bonus recommendations to the MPC Compensation Committee. Key factors considered for 2017
included:
• Completed strategic initiatives announced by MPC and MPLX in early 2017, including the dropdown
to MPLX of assets generating MLP-qualifying EBITDA and executed the exchange of MPC’s
economic general partner interest in MPLX, including its incentive distribution rights (or IDRs), for a
non-economic general partner interest and MPLX LP common units.
• MPC’s net income attributable to MPC increased to $3.43 billion, or $6.70 per diluted share, in 2017
from $1.17 billion, or $2.21 per diluted share, in 2016. Earnings in 2017 include a tax benefit of
approximately $1.5 billion (or $2.93 per diluted share) related to tax reform legislation enacted in the
fourth quarter of 2017.
• MPC increased its quarterly dividend by 11 percent to $0.40 per share from $0.36 per share in 2017,
and again increased the dividend by 15 percent to $0.46 per share in the first quarter of this year,
representing a 26.5 percent compound annual growth rate from the dividend established when it
became an independent company on June 30, 2011.
• MPC continued to focus on returning capital to shareholders returning $3.1 billion to shareholders
through dividends and share repurchases.
• MPC Total Shareholder Return (“TSR”) for 2017 was 34.6 percent compared with median TSR of
26.7 percent for its performance unit peer group.
• MPLX Total Unitholder Return (“TUR”) for 2017 was 17.5 percent compared with median TUR of
0.4 percent for its performance unit peer group.
• MPLX reported record financial results on record volume growth across the gathering and processing
business. MPLX delivered on its 12.1 percent distribution growth guidance for 2017 distributions and
has increased its quarterly cash distribution for 20 consecutive quarters, representing an 18.3 percent
compound annual growth rate over the minimum quarterly distribution established at its formation in
late 2012.
Bonus opportunities for our NEOs under the ACB program are communicated as a target percentage of
annualized base salary at year end. Each of our NEOs can generally earn a maximum of 200 percent of the target
award, or earn no award at all, depending on MPC and MPLX’s overall performance and the subjective
217
evaluation of each NEO’s organizational and individual performance. The MPC Compensation Committee
reviews market data provided by its compensation consultant annually with respect to competitive pay levels and
annually approves specific bonus target opportunities for each of our NEOs. MPC does not guarantee minimum
bonus payments to any of our NEOs.
2018 Bonus Payments (for 2017 Performance)
In February 2018, the MPC Compensation Committee certified the results of the performance metrics for the
2017 ACB program and applied the following formula based on performance of established metrics, as well as
organizational and individual performance, to determine our NEOs’ final award for 2017 performance:
Annualized
Base Salary
(as of 12/31/17)
X
Bonus Target
(as a percent of base
salary)
X
Final Award Percent
(as a percent of
target)
=
Final
Award
Name(1)
Pamela K.M. Beall
Michael J. Hennigan
C. Corwin Bromley
Gregory S. Floerke
Donald C. Templin
Annualized
Base Salary
(as of
12/31/17)
($)(2)
525,000
429,589
465,000
450,000
405,000
Bonus Target
as a % of
Base Salary
(%)
70
100
60
70
100
Target Bonus
($)
367,500
429,589
279,000
315,000
405,000
Final Award
as a % of
Target
(%)
182.1
186.0
—
190.5
188.9
Final Award
($)(3)
670,000
800,000
—
600,000
765,000
(1) Mr. Heminger is not included as he generally devotes less than a majority of his total business time to our
general partner and us.
(2) Mr. Hennigan’s salary reflects his base pay earnings from his hire date on June 19, 2017 through
December 31, 2017. Mr. Templin’s salary reflects his year-end salary adjusted for his allocation of
90 percent to our general partner and pro-rated to reflect his tenure as MPLX President, which ended
June 20, 2017.
The final award is rounded to the nearest $5,000.
(3)
MPLX Long-Term Incentive Compensation Program
In January 2017, the board of directors of our general partner met and approved a long-term incentive (or “LTI”)
design whereby annual LTI awards granted to our NEOs were in the form of performance units (50 percent) and
phantom units (50 percent). Each form of LTI generally rewards performance over a multi-year period to the
extent service (for phantom units) or partnership performance metrics (for performance units) are achieved. The
primary purpose of LTI grants to our NEOs is to advance our long-term business objectives and strengthen the
alignment between the interests of our executive officers and our unitholders. The forms of LTI awards differ as
illustrated below:
Form of LTI Award
Form of Settlement
Compensation Realized
MPLX Performance Units
25 percent in MPLX LP common units
and 75 percent in cash
MPLX Phantom Units
MPLX LP common units
$0.00 to $2.00 per unit based on our
relative Total Unitholder Return (or
“TUR”) ranking among a group of peers,
and a DCF metric for awards granted in
2017 and 2018
Value of common units upon vesting
218
Due to the nature of LTI awards, the actual long-term compensation value realized by our NEOs will depend on
the price of the underlying unit at the time of settlement. The 2017 LTI awards were based on an intended dollar
value rather than a specific number of performance units or phantom units.
Performance Units
The board of directors of our general partner believes that performance unit awards complement our phantom unit
program. In 2017, the board of directors of our general partner, after reviewing performance programs of our peer
companies, added a second performance metric to our performance unit program to align it with contemporary
industry program design. In addition to the existing metric of TUR relative to a peer group of midstream
competitors, a DCF-per-MPLX-LP-common-unit metric was added. The DCF-per-MPLX-LP-common-unit metric
was chosen as unitholders also place significant importance on DCF to measure an MLP’s performance relative to
others within the same industry. The board of directors of our general partner believes the combination of these two
metrics will better align the pay of our NEOs with the value delivered to our unitholders. Achieving above target
payouts from our performance unit program will require at least one of these two metrics to achieve above target
performance. This second metric was added to all performance unit grants starting in 2017.
Each performance unit is dollar denominated with a target value of $1.00. The actual payout will vary from $0.00
to $2.00 (zero percent to 200 percent of target.). The board of directors of our general partner believes that
having the maximum payout capped at $2.00 per unit mitigates excessive or inappropriate risk-taking. The final
value of the 2015 and 2016 performance unit awards will continue to be determined based solely on the results of
MPLX’s TUR. The final value of the 2017 performance unit awards will be based 50 percent on the results of
MPLX’s TUR and 50 percent on the results of the DCF-per-MPLX-LP-common-unit metric. These awards settle
25 percent in MPLX LP common units and 75 percent in cash.
Total Unitholder Return
Under the MPLX program, TUR for MPLX and that of each of the peer group MLPs is measured over a
36-month performance cycle. Each performance cycle has four equally weighted measurement periods: (1) the
first 12 months, (2) the second 12 months, (3) the third 12 months and (4) the entire 36-month period. The board
of directors of our general partner believes that measuring TUR over four measurement periods in the 36-month
performance cycle is appropriate and serves the best interests of our unitholders. By having four equally
weighted measurement periods, attaining maximum payout based on TUR may be achieved only by
outperforming the TUR of the peer group for all four measurement periods.
Each peer group member’s TUR is determined by taking the sum of the unit price appreciation or reduction, plus
its cumulative cash distributions, for each measurement period and dividing that total by the peer group
member’s beginning unit price for that period, as shown below.
(Ending Unit Price – Beginning Unit Price) + Cumulative Cash Distributions
Beginning Unit Price
The beginning and ending unit prices for MPLX and each peer group member in the TUR calculation are the
average of the MLP’s respective closing unit prices for the 20 trading days immediately preceding the beginning
or ending date of the applicable measurement period. This design mitigates significant market fluctuations in the
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.
219
MPLX LP’s TUR performance percentile within the peer group is measured for each measurement period with
the related payout percentage determined using the following table. However, if MPLX LP’s TUR is negative for
a measurement period, the TUR payout percentage for that measurement period is capped at target (100 percent)
regardless of actual relative TUR performance percentile. We refer to this provision as a “negative TSR cap”.
TUR
Percentile
100th (Highest)
50th
25th
Below 25th
Payout Percentage
(% of Target)*
200%
100%
50%
0%
* Payout for performance between quartiles will be determined using linear interpolation.
Distributable Cash Flow per MPLX LP Common Unit
The DCF-per-MPLX-LP-common-unit metric used for 2017 performance unit awards measures the growth of
MPLX’s full-year DCF over the three-year performance cycle. Payout for the DCF metric will be based on
achievement of DCF in the last year of the performance cycle as compared with the threshold, target and
maximum levels, which will be calculated by applying pre-determined compounded annual growth rates
(“CAGR”) against the DCF of the year prior to the beginning of the 36-month performance cycle.
MPLX Performance Units Granted in 2015
Performance units granted in 2015 had a performance cycle of January 1, 2015, through December 31, 2017 and
use TUR as the sole performance metric. Additional information about these grants, including the peer group
used, can be found in the “Long-Term Incentive Compensation” section of our Annual Report on Form 10-K for
the year ended December 31, 2015.
In January 2018, the board of directors of our general partner approved the final TUR for the four measurement
periods of the 2015 performance unit grants, which are as follows:
Performance Period
January 1, 2015—December 31, 2015
January 1, 2016—December 31, 2016
January 1, 2017—December 31, 2017
January 1, 2015—December 31, 2017
Actual TUR
(%)
Position
Percentile Ranking*
(%)
Payout
(% of target)**
(45.3)
3.2
17.5
(34.8)
11th
9th
1st
10th
9.09
27.27
100.00
10.00
Average:
—
54.54
200.00
—
63.64
*
Sunoco Logistics Partners L.P. was removed from the peer group due to its acquisition by Energy Transfer
Partners, L.P. in April 2017.
** No payout occurs for ranking below the 25th percentile.
The resulting average of 63.64 percent of target provided for a payment equal to $0.6364 per performance unit
granted. The board of directors approved the following payout to Ms. Beall and Messrs. Heminger and Templin:
Name
Gary R. Heminger
Pamela K.M. Beall
Donald C. Templin
Target Number of
Performance Units
Compensation Committee
Approved Payout
($)
1,100,000
85,000
250,000
700,040
54,094
159,100
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The payout settled 25 percent in full value MPLX LP common units and 75 percent in cash. Mr. Hennigan,
Mr. Bromley and Mr. Floerke were not eligible for a payout as these awards were made prior to their
employment with our general partner.
MPLX Performance Units Granted in 2016
Performance units granted in 2016 have a performance cycle of January 1, 2016, through December 31, 2018 and
use TUR as the sole performance metric. They remain outstanding and are included in the “Outstanding Equity
Awards at 2017 Fiscal Year-End” table. Additional information about these grants, including the peer group used
(which has been adjusted), can be found in the “Long-Term Incentive Compensation” section of our Annual
Report on Form 10-K for the year ended December 31, 2016. ONEOK Partners L.P. and Sunoco Logistics
Partners L.P. were removed from the peer group as ONEOK Partners L.P. was acquired by ONEOK Inc. and
Sunoco Logistics Partners L.P. was acquired by Energy Transfer Partners, L.P.
MPLX Performance Units Granted in 2017
After an annual review of market practices, the board of directors of our general partner again made performance
unit grants in February 2017. TUR will be used to determine 50 percent of the performance unit payout using the
following approved peer group:
- 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
- Williams Partners L.P.
ONEOK Partners L.P. and Sunoco Logistic Partners L.P. were removed for 2017 as ONEOK Partners L.P. was
acquired by ONEOK Inc. and Sunoco Logistics Partners L.P. was acquired by Energy Transfer Partners L.P.
DCF per MPLX LP common unit in 2019 will be used to determine the remaining 50 percent of the performance
unit payout. The DCF-per-MPLX LP-common-unit metric was added by the Committee as it believes unitholders
also place significance on DCF to measure a partnership’s performance relative to others in the same industry.
Threshold, target and maximum levels are calculated using a CAGR of 8 percent, 10 percent and 12 percent,
respectively, over the full-year 2016 DCF per MPLX LP common unit. The following table will be used to
determine the DCF performance metric payout percentage for the 2017 grant:
DCF per MPLX LP common unit
$2.3465
$2.9559
$3.1232
$3.2967
Full Year 2016
Threshold (50%)*
Target (100%)* Maximum (200%)*
* Payout for performance between threshold and target, and between target and maximum will be determined
using linear interpolation.
The number of performance units granted to Ms. Beall and Messrs. Heminger, Templin, Bromley and Floerke
can be found in the Grants of Plan-Based Awards table below. Mr. Hennigan did not receive performance units
in 2017 as they were awarded prior to his hire on June 19, 2017.
Phantom Units
Grants of phantom units provide diversification of the mix of LTI awards, promote ownership of actual MPLX
LP common units and promote retention. Further, phantom unit grants also help our NEOs increase their
holdings in MPLX LP common units and achieve established unit ownership guideline levels.
The value of phantom unit awards is variable, based on the value of an underlying MPLX LP common unit, and
the awards vest in equal installments on the first, second and third anniversary of the date of grant and are settled
221
in MPLX LP common units upon vesting. Prior to vesting, recipients have no right to vote the units, and cash
distributions are accrued and paid in cash upon vesting. Upon vesting, a one-year holding period requirement is
in effect for all full-value MPLX LP common units received under the MPLX 2012 Plan. This holding period
prevents our NEOs from selling any MPLX LP common units for 12 months from the time the awards are vested.
This requirement applies to units net of taxes at the time of vesting or distribution.
The number of phantom units granted to each of our NEOs can be found in the “Grants of Plan-Based Awards”
table in this Annual Report on Form 10-K.
MPC Long-Term Incentive Compensation Program
As part of their total equity package, each of our NEOs also receives LTI from our sponsor. MPC LTI awards for
2017 were granted in the form of performance units (40 percent), stock options (40 percent) and restricted stock
(20 percent). The forms of awards differ as illustrated below:
Form of LTI Award
Form of Settlement
Compensation Realized
MPC Performance Units
25 percent in MPC common stock and
75 percent cash
MPC Stock Options
MPC common stock
MPC Restricted Stock
MPC common stock
$0.00 to $2.00 per unit based on MPC’s
relative TSR ranking among a group of
peers
Stock price appreciation from grant date
to exercise date
Full value of common stock upon vesting
Due to the nature of LTI awards, the actual long-term compensation value realized by our NEOs will depend on
the price of the underlying common stock at the time of settlement. The 2017 LTI awards were based on an
intended dollar value rather than a specific number of performance units, stock options or shares of restricted
stock.
MPC granted the 2017 LTI awards to Ms. Beall and Messrs. Bromley and Floerke on March 1, 2017. The
exercise price for stock options is equal to the closing price of a share of MPC common stock on the grant date,
or the first trading day thereafter if the grant date is not a trading day. We discuss each of the forms of LTI
awards in more detail below.
MPC Performance Units
The MPC Compensation Committee believes a performance unit program serves as a complement to the stock
option and restricted stock programs. The program benchmarks MPC’s TSR relative to a peer group of oil
industry competitors and a market index. This relative evaluation allows for the cyclicality of its business and
commodity prices (crude oil) to be recognized and prevents volatility from directly advantaging or
disadvantaging the payout of the award beyond that of its peers. The MPC Compensation Committee continues
to believe that TSR relative to a peer group is the single best metric for its performance unit program as it is
commonly used by shareholders to measure a company’s performance relative to others within the same industry.
It also aligns the compensation of its NEOs with the value delivered to its shareholders. The design of the
performance unit program ensures MPC pays above target compensation only when its TSR is above the median
of the peer group.
Under its program, 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: (1) the first 12
months, (2) the second 12 months, (3) the third 12 months, and (4) the entire 36-month period. The MPC
Compensation Committee believes that measuring TSR over four measurement periods in the 36-month
performance cycle is appropriate and serves the best interests of its shareholders. By having four equally
weighted measurement periods, attaining maximum payout based on TSR may be achieved only by
outperforming the TSR peer group for all four measurement periods.
222
Each peer group member’s TSR is determined by taking the sum of the company’s stock price appreciation or
reduction, plus its cumulative cash dividends, for each measurement period and dividing that total by the
company’s beginning stock price for that period, as illustrated below:
(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 the respective closing stock prices for the 20 trading days immediately preceding the beginning and
ending date of the applicable measurement period. The design mitigates 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 using the following table. However, if MPC’s TSR is negative for a
measurement period, the payout percentage for that measurement period is capped at target (100 percent)
regardless of actual relative TSR performance percentile. We refer to this provision as a “negative TSR cap”.
TSR
Percentile
100th (Highest)
50th
25th
Below 25th
Payout
(% of Target)*
200%
100%
50%
0%
* Payout for performance between quartiles will be determined using linear interpolation.
Each performance unit is dollar denominated with a target value of $1.00. The actual payout may vary from
$0.00 to $2.00 (zero percent to 200 percent of target). The MPC Compensation Committee also believes that
having the maximum payout capped at $2.00 per unit mitigates excessive or inappropriate risk-taking. 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 percent in MPC common stock and 75 percent in cash.
MPC Performance Units Granted in 2015
Performance units granted by MPC in 2015 had a performance cycle of January 1, 2015, through December 31,
2017. Additional information about these grants, including the peer group used, can be found in the “Long-Term
Incentive Compensation Program” section of the MPC 2016 Proxy Statement.
In January 2018, the MPC Compensation Committee certified the final TSR for the four measurement periods of
the 2015 performance unit grants, which are as follows:
Performance Period
January 1, 2015—December 31, 2015
January 1, 2016—December 31, 2016
January 1, 2017—December 31, 2017
January 1, 2015—December 31, 2017
Actual TSR
(%)
Position
Percentile Ranking
(%)
Payout
(% of target)
5th
5th
3rd
2nd
42.85
42.85
71.43
85.71
Average:
85.70
85.70
142.86
171.42
121.42
20.2
(1.8)
34.6
57.0
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The resulting average of 121.42 percent of target provided for a payment equal to $1.2142 per performance unit
granted. As a result, the MPC Compensation Committee approved the following payment to Ms. Beall:
Name
Pamela K.M. Beall
Target Number of
Performance Shares
272,000
MPC Compensation
Committee Approved Payout
($)
330,263
The results of the 2015 performance unit grant were certified by the MPC Compensation Committee and settled
25 percent in full value shares of MPC common stock and 75 percent in cash. Mr. Hennigan, Mr. Bromley and
Mr. Floerke were not eligible for a payout as these awards were made prior to their employment date.
MPC Performance Units Granted in 2016
Performance units granted by MPC in 2016 have a performance cycle of January 1, 2016, through December 31,
2018. They remain outstanding and are included for Ms. Beall in the “Outstanding Equity Awards at 2017 Fiscal
Year-End” table. Additional information about these grants, including the peer group used, can be found in the
“Long-Term Incentive Compensation Program” section of the MPC 2017 Proxy Statement.
MPC Performance Units Granted in 2017
The MPC Compensation Committee made the decision to award performance unit grants in February 2017. The
MPC Compensation Committee approved the following peer group for performance unit awards granted in 2017:
• Andeavor
• Chevron Corporation
• HollyFrontier Corporation
•
•
PBF Energy
Phillips 66
• Valero Energy Corporation
•
S&P 500 Energy Index
The number of performance units granted to Ms. Beall and Messrs. Bromley and Floerke can be found in the
“Grants of Plan-Based Awards” table.
MPC Stock Options
Stock options provide a direct but variable link between our NEOs’ long-term compensation and the long-term
value shareholders receive by investing in MPC. The MPC Compensation Committee believes stock options are
inherently performance-based as option holders only realize benefits if the value of the stock increases for all
shareholders after the grant date. The exercise price of MPC stock options is generally equal to the per-share
closing price of MPC common stock on the grant date. Stock options vest in equal installments on the first,
second and third anniversary of the date of grant and have a maximum 10-year term during which an NEO may
exercise the options. Option holders do not have voting rights or receive dividends on the underlying common
stock.
The number of options granted to Ms. Beall and Messrs. Bromley and Floerke can be found in the “Grants of
Plan-Based Awards” table.
MPC Restricted Stock
Grants of restricted stock provide diversification in the mix of LTI awards, result in ownership of actual shares of
common stock and promote NEO retention.
224
The value of restricted stock awards is also variable, and the awards vest in equal installments on the first, second
and third anniversary of the date of grant. Prior to vesting, recipients have voting rights but dividends declared
during the restricted period are accrued and paid in cash upon vesting. Upon vesting, a one-year holding period
requirement is in effect for all full-value shares received under MPC’s incentive compensation plan. This holding
period prevents our NEOs and other executive officers from selling any stock or performance units settled in
shares for 12 months from the time the awards are vested or earned. This requirement applies to shares net of
taxes at the time of vesting or distribution.
The number of restricted shares granted to Ms. Beall and Messrs. Hennigan, Bromley and Floerke can be found
in the “Grants of Plan-Based Awards” table.
OTHER POLICIES
Benefit Programs and Perquisites
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 them with perquisites. However, those types of
benefits are generally provided to our NEOs in connection with their employment by MPC or its affiliates and
are governed in all cases by the terms of the applicable plan documents. All determinations with respect to such
benefits will be made by MPC, or the plans, as the case may be, without input from us or our general partner or
its board of directors. MPC bears the full cost of any such programs for our NEOs and no portion of these
benefits is charged back to us under the provisions of the omnibus agreement. However, we have summarized the
material elements of these MPC programs below to the extent they represent a material component of our NEOs’
compensation for the services they provide to our business.
Perquisites
Our NEOs are eligible for reimbursement for certain tax, estate and financial planning services up to $15,000 per
year while actively employed by MPC or its affiliates and $3,000 in the year following retirement or death. The
MPC Compensation Committee believes this perquisite 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 due to receiving equity compensation that settle in MPLX LP common units.
Our NEOs are also eligible for enhanced annual physical health examinations to promote their health and well-
being. Under this program, our NEOs can receive a comprehensive physical (generally in the form of a one-day
appointment), with procedures similar to those available to all other employees who participate in MPC’s health
program. The incremental cost of these enhanced physicals is primarily attributable to MPC-paid facilities
charges and incremental charges incurred for not using facilities from which MPC receives discounts under the
health plan network.
The primary use of corporate aircraft is for business purposes and must be authorized by MPC’s Chairman and
CEO or another executive officer designated by MPC’s Board or MPC’s Chairman and CEO. Occasionally,
spouses or other guests will accompany our NEOs on corporate aircraft, or our NEOs may travel for personal
purposes on corporate aircraft typically in cases where space is available on business-related flights. However,
Mr. Hennigan was granted limited personal use of the aircraft when otherwise available during the first 12
months of his employment as MPLX President. 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.
Reportable values for these perquisite programs, based on the incremental costs to MPC, are included in the “All
Other Compensation” column of the 2017 Summary Compensation Table.
Neither income tax assistance nor tax gross-ups are provided on executive perquisites including tax, estate and
financial planning services or the personal use of corporate aircraft.
225
Unit Ownership Guidelines
The board of directors of our general partner has approved unit ownership guidelines for our executive officers
including our NEOs. As our executive officers earn a base salary from MPC and not from MPLX, the unit
ownership guidelines were established as a fixed number of MPLX LP common units instead of a value
representing a multiple of an executive officer’s annual salary. The guidelines are intended to align the long-term
interests of our executive officers and our unitholders. Under these guidelines, executive officers are expected to
hold a specified level of MPLX LP common units. The targeted levels are:
•
•
based on the executive’s position and responsibilities, and
expected to be reached within five years of the executive officer’s assumption of the position.
The unit ownership guidelines are as follows:
• Chairman of the Board and Chief Executive Officer—25,000 MPLX LP common units;
•
President—20,000 MPLX LP common units;
• Executive Vice President—15,000 MPLX LP common units;
•
Senior Vice President—10,000 MPLX LP common units; and
• Vice President—5,000 MPLX LP common units.
Executive officers are not permitted to sell any MPLX LP common units received under the MPLX 2012 Plan
unless their ownership guideline levels are met and are maintained after the sale. Additionally, a one-year
holding requirement prevents executive officers from selling any MPLX LP common units distributed in
settlement of phantom units or performance units for twelve months from the time they are vested. This
requirement applies to MPLX LP common units net of taxes at the time of vesting or distribution. All of our
NEOs have met their MPLX LP common unit ownership guidelines.
Prohibition on Derivatives and Hedging
In order to ensure our executive officers, including our NEOs, bear the full risk of MPLX LP common unit
ownership, we maintain a policy that prohibits hedging transactions related to our units, or pledging or creating
security interests in our units, including units in excess of a unit ownership guideline requirement.
Severance and Change in Control Arrangements
None of our NEOs have employment agreements with us, our general partner or MPC. Our NEOs are eligible to
participate in MPC’s Amended and Restated Executive Change in Control Severance Benefits Plan (the “MPC
CIC Plan”) and MPLX’s Executive Change in Control Severance Benefits Plan (the “MPLX CIC Plan”). These
plans generally provide senior executives with severance payments and benefits in the event of a qualified
termination of employment within two years of the occurrence of a change in control of MPC and/or MPLX. All
determinations with respect to such benefits would be made by the board of directors of MPC in the event of a
change in control of MPC, or the board of directors of our general partner in the event of a change in control of
MPLX.
Our NEOs do not participate in any arrangements that would result in the payment of any amounts or provision
of any benefits solely as a result of a change in control of us. However, pursuant to the MPLX CIC Plan, vesting
of all of the NEOs’ long-term incentive awards in us would be accelerated upon a qualified termination from
service with us in connection with a change in control of MPLX.
For additional information about the severance and accelerated vesting that may be provided under the MPLX
CIC Plan, please refer to the discussion below under the heading “Potential Payments Upon Termination or
Change in Control.”
226
If either Messrs. Bromley or Floerke separate from service as a result of a forced relocation of his principal place
of employment to a location more than 50 miles from his current principal place of employment, his unvested
MPLX LP phantom units and MPC restricted stock received as part of his retention grants awarded in 2015 will
vest and become payable. The amount payable assuming such termination occurred on December 31, 2017,
based on the MPLX LP common unit and MPC common stock closing prices as of that date, or the last trading
day prior to that date if not a trading day, would have been as follows: Mr. Bromley, $3,396,597; and
Mr. Floerke, $2,917,255.
Additionally, upon either of Messrs. Bromley’s or Floerke’s separation from service without cause, the separated
NEO is entitled to a portion of the grant of MPLX LP phantom units received as part of his retention grants
awarded in 2015. The amount payable assuming such separation of service occurred on December 31, 2017,
based on the MPLX LP common unit closing price as of that date, or the last trading date prior to that date if not
a trading day, would have been as follows: Mr. Bromley, $1,782,013; and Mr. Floerke, $1,293,804.
Mr. Bromley retired effective January 1, 2018.
Recoupment/Clawback Policy
In addition to any compensation recoupment policies that apply with respect to the compensation our NEOs
receive from MPC, the MPLX 2012 Plan provides that all awards granted under the MPLX 2012 Plan will be
subject to clawback or recoupment in the case of certain forfeiture events. If the Partnership is required, pursuant
to a determination made by the SEC or the audit committee of our general partner, to prepare a material
accounting restatement due to our non-compliance 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:
•
knowingly engaged in misconduct;
• was grossly negligent with respect to misconduct;
•
•
knowingly failed or was grossly negligent in failing to prevent misconduct; or
engaged in fraud, embezzlement or other similar misconduct materially detrimental to us.
Upon a determination by the audit committee of our general partner that a forfeiture event has occurred, any
grants of unvested phantom units and performance units to such executive officer would be subject to immediate
forfeiture. If a forfeiture event occurred either while the executive officer is 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 (but not in excess of) the amount paid in
settlement of the performance units.
These recoupment provisions are in addition to the requirements in Section 304 of the Sarbanes-Oxley Act of
2002, which provide that the Chief Executive Officer and Chief Financial Officer shall 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 non-compliance with financial reporting requirements as a
result of our misconduct. Additionally, all equity grants made since 2013 include provisions making them subject
to any clawback provisions required by the Dodd-Frank Act and any other “clawback” provisions as required by
law or by the applicable listing standards of the exchange on which the MPLX LP common units are listed for
trading.
Additional Compensation Components
In the future, as MPC and/or our general partner formulate and implement the compensation programs for our
executive officers, MPC and/or our general partner may provide additional or different compensation
227
components, benefits and/or perquisites to help ensure our executive officers are provided with a balanced,
comprehensive and competitive total compensation package. We, MPC and our general partner believe that it is
important to maintain flexibility to adapt compensation structures on an ongoing basis to properly attract,
motivate, retain and reward the top executive talent for which we, MPC and our general partner compete with
other companies.
COMPENSATION-BASED RISK ASSESSMENT
Annually, the 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 Committee completed this review of our 2017 programs in February 2018. As a result of this review, the
Committee 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.
RATIO OF ANNUAL COMPENSATION FOR THE CEO TO OUR MEDIAN EMPLOYEE
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 us or our
general partner. Because we do not have 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.
228
The following table summarizes the total compensation awarded to, earned by or paid to our NEOs for the
services each provided to our business:
Summary Compensation Table
Name and Principal
Position(1)
Year
Salary(2)
($)
Bonus(3)
Gary R. Heminger
Chairman of the Board
and Chief Executive
Officer
2017 1,310,000
2016 1,220,000
2015 1,220,000
Stock
Awards(4)(5)
($)
Option
Awards(4)
($)
2,282,185
1,797,853
2,239,071
—
—
—
Change in
Pension Value
and
Nonqualified
Deferred
Compensation
Earnings(7)
($)
Non-Equity
Incentive Plan
Compensation(6)
($)
All Other
Compensation(8)
($)
Total
($)
—
—
—
—
—
—
— 3,592,185
— 3,017,853
— 3,459,071
Pamela K.M. Beall
Executive Vice
President and Chief
Financial Officer
Michael J. Hennigan
President
C. Corwin Bromley
Executive Vice
President and
General Counsel
Gregory S. Floerke
Executive Vice
President,
MarkWest
Operations
Donald C. Templin
Former President,
MPLX
2017
2016
2015
525,000
499,667
234,375
743,215 68,010
529,759 170,008
—
173,033
670,000
550,000
262,500
245,643
226,408
56,514
88,828 2,340,696
86,067 2,061,909
765,704
39,282
2017
429,589 1,000,000 5,000,052
—
2017
2016
2015
465,000
461,250
34,615
2017
2016
2015
442,500
415,000
30,769
655,807 60,007
—
—
—
3,525,011
699,511 64,009
—
—
—
3,092,492
800,000
—
450,000
—
600,000
425,000
—
126,322
157,086 7,513,049
104,446
90,486
—
78,750
62,847
—
67,884 1,353,144
61,251 1,062,987
— 3,559,626
67,633 1,952,403
958,026
55,179
— 3,123,261
2017
2016
2015
365,625
720,000
515,000
2,282,185
1,225,803
508,906
—
—
—
765,000
1,170,000
—
128,453
217,355
—
76,702 3,617,965
134,794 3,467,952
— 1,023,906
(1)
(2)
(3)
(4)
Except where indicated, amounts shown reflect only compensation amounts allocable to MPLX LP and do not include
compensation amounts for other services that are not allocable to MPLX LP. For 2017, compensation amounts were
allocated based on the relative percentage each NEO’s business time was dedicated to MPLX LP’s business. For 2017,
percentage allocations for each NEO were as follows: Mr. Templin-90 percent; Ms. Beall and Messrs. Bromley, Floerke
and Hennigan-100 percent.
The amounts shown in this column reflect the annualized fixed fee for Mr. Heminger for 2017, 2016, and 2015 and for
Mr. Templin for 2015. The amount shown for Mr. Floerke for 2017 reflects three months at his January 1, 2017
annualized base salary and nine months at his April 1, 2017 annualized base salary, respectively. The amount shown for
Mr. Hennigan is a pro-rated amount of his annualized base salary since his hire date on June 19, 2017. The amount
shown for Mr. Templin reflects three months at his January 1, 2017 annualized base salary and three months at his
April 1, 2017 annualized base salary, respectively, to reflect his tenure as President, MPLX, which ended on June 20,
2017. Ms. Beall’s and Mr. Bromley’s amounts reflect their annualized base pay as of December 31, 2017 as they did not
receive a base pay adjustment in 2017.
The amount in this column for Mr. Hennigan reflects a cash sign-on bonus.
The amounts shown in this column reflect the aggregate grant date fair value in accordance with provisions of the
Financial Accounting Standards Board Accounting Standards Codification 718, Compensation-Stock Compensation
(FASB ASC Topic 718.) See Item 8. Financial Statements and Supplementary Data-Note 20 for assumptions used in the
calculation of the amounts related to MPLX LP equity for the year ended December 31, 2017, Note 20 to financial
statements as reported on our Annual Report on Form 10-K for assumptions used in the calculation of the amounts
related to MPLX LP equity for the year ended December 31, 2016, and Note 19 to financial statements as reported on
our Annual Report on Form 10-K for assumptions used in the calculation of the amounts related to MPLX LP equity for
the year ended December 31, 2015; and Note 23 to MPC’s financial statements as reported on its Annual Reports on
229
Form 10-K for the years ended December 31, 2017, and December 31, 2016, for amounts related to MPC equity.
Amounts in this column for 2016 performance unit grants were previously overstated and have been decreased to reflect
the correction of an error in the Monte Carlo valuation model used to determine the grant date fair value of the units.
The maximum value of the performance units reported in this column for those who received 2015 performance unit
grants assuming the highest level of performance is achieved, for each NEO, is as follows: Mr. Heminger, MPLX—
$2,200,000; Ms. Beall, MPLX—$170,000 and MPC—$544,000; and Mr. Templin, MPLX—$500,000. The maximum
value of the performance units reported in this column for those who received 2016 performance unit grants assuming
the highest level of performance is achieved, for each NEO, is as follows: Mr. Heminger, MPLX—$2,200,000;
Ms. Beall, MPLX—$425,000 and MPC—$340,000; and Mr. Templin, MPLX—$1,500,000. The maximum value of the
performance units reported in this column for those receiving 2017 performance unit grants, assuming the highest level
of performance is achieved, for each NEO, is as follows: Mr. Heminger, MPLX—$2,400,000; Ms. Beall, MPLX—
$680,000 and MPC—$136,000; Mr. Templin, MPLX—$2,400,000; Mr. Bromley, MPLX—$600,000 and MPC—
$120,000; and Mr. Floerke, MPLX—$640,000 and MPC—$128,000.
The amounts shown in this column reflect the total value of ACB awards earned in the year indicated, which were paid in
the following year.
The amounts shown in this column reflect the annual change in actuarial present value of accumulated benefits under the
Marathon Petroleum retirement plans. See “Post-Employment Benefits for 2017” and “Marathon Petroleum Retirement
Plans” sections of the “Compensation Discussion and Analysis” for more information regarding the defined benefit plans
and the assumptions used in the calculation of these amounts. There are no deferred compensation earnings reported in
this column as the non-qualified deferred compensation plans do not provide above-market or preferential earnings.
In connection with their employment with MPC, our NEOs are eligible for limited perquisites which, together with
contributions to defined contribution plans, comprise the amounts reported in the All Other Compensation column. The
amounts shown in this column are summarized below:
(5)
(6)
(7)
(8)
Personal
Use of
Company
Aircraft(a)
($)
—
—
55,155
—
—
—
Company
Physicals(b)
($)
Tax &
Financial
Planning(c)
($)
Security
($)
Miscellaneous
Perks & Tax
Allowance
Gross-ups
($)
Company
Contributions to
Defined
Contribution
Plans(d)
($)
—
3,651
3,651
3,651
3,651
3,651
—
12,385
—
—
3,165
5,229
—
—
—
—
—
—
—
—
—
—
—
—
—
72,792
98,280
64,233
60,817
67,822
Total All Other
Compensation
($)
—
88,828
157,086
67,884
67,633
76,702
Name
Gary R. Heminger
Pamela K.M. Beall
Michael J. Hennigan
C. Corwin Bromley
Gregory S. Floerke
Donald C. Templin
(a)
The primary use of corporate aircraft is for business purposes and must be authorized by MPC’s Chairman
and CEO or another executive officer designated by MPC’s Board or MPC’s Chairman and CEO.
Occasionally, spouses or other guests will accompany our NEOs on corporate aircraft, or our NEOs may
travel for personal purposes on corporate aircraft typically in cases where space is available on business-
related flights. However Mr. Hennigan was granted limited personal use of the aircraft when otherwise
available during the first 12 months of his employment as MPLX President. The amounts shown in this
column reflect the aggregate incremental cost of personal use of corporate aircraft by our NEOs for the
period from January 1, 2017, through December 31, 2017. These amounts reflect our incremental cost of
travel on corporate aircraft for our NEOs, their spouses or other guests for personal travel. We have
estimated our aggregate incremental cost using a methodology that reflects 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 our incremental cost. However,
use of this method 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 us. No income tax assistance or gross-ups are provided for personal use of
corporate aircraft.
230
(b) All MPC employees, including our NEOs, are eligible to receive an annual physical. Executives may
receive an enhanced physical under the executive physical program. The amounts shown in this column
reflect the average incremental cost of the executive physical program in excess of the average incremental
cost of the employee physical program. Due to privacy concerns and Health Insurance Portability and
Accountability Act confidentiality requirements, we do not disclose actual usage or cost of this program by
individual NEOs.
The amounts shown in this column reflect reimbursement for the costs of professional advice related to tax,
estate and financial planning up to a specified maximum not to exceed $15,000 per calendar year. For
information on this program refer to the “Perquisites” section of the “Compensation Discussion and
Analysis.”
The amounts shown in this column reflect amounts contributed by MPC under the tax-qualified Marathon
Petroleum Thrift Plan for Ms. Beall and Messrs. Bromley, Floerke, Hennigan and Templin, as well as under
related non-qualified deferred compensation plans. See “Post-Employment Benefits for 2017” and
“Marathon Petroleum Retirement Plans” sections of the “Compensation Discussion and Analysis” for more
information.
(c)
(d)
231
Grants of Plan-Based Awards in 2017
The following table provides information regarding all plan-based awards, including cash-based incentive awards
and equity-based awards (specifically stock options, restricted stock, phantom units and performance units)
granted to each of our NEOs in 2017 for the services each provided to our business:
Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards (2)
Estimated Future Payouts
Under Equity Incentive Plan
Awards (3)
Type of
Award
Grant
Date
Approval
Date(1)
Threshold
($)
Target
($)
Maximum
($)
Threshold
($)
Target
($)
Maximum
($)
All
Other
Shares
of
Stock
or
Units
(#)
All Other
Option
Awards:
Underlying
Options
(#)
Exercise
or Base
Price of
Option
Awards
($)
Grant
Date And
Option
Awards(4)
($)
MPLX LP
Phantom
Units
MPLX LP
Performance
Units
3/1/2017 2/21/2017
31,563
1,200,025
3/1/2017 2/21/2017
150,000 1,200,000 2,400,000
1,082,160
Name
Gary R.
Heminger
Pamela K.M.
Beall
MPC Stock
Options
3/1/2017 2/21/2017
4,776
50.99
68,010
MPC
Restricted
Stock
MPC
Performance
Units
MPC
Annual
Cash Bonus
MPLX LP
Phantom
Units
MPLX LP
Performance
Units
MPC
Restricted
Stock
MPC
Annual
Cash Bonus
MPLX LP
Phantom
Units
Michael J.
Hennigan
3/1/2017 2/21/2017
3/1/2017 2/21/2017
8,500
68,000
136,000
N/A
367,500 735,000
3/1/2017 2/21/2017
667
8,943
3/1/2017 2/21/2017
42,500
340,000
680,000
34,010
62,580
340,013
306,612
7/1/2017 5/30/2017
18,833
1,000,032
N/A
429,589 859,178
7/1/2017 5/30/2017
116,823
4,000,020
C. Corwin
Bromley
MPC Stock
Options
3/1/2017 2/21/2017
4,214
50.99
60,007
MPC
Restricted
Stock
MPC
Performance
Units
MPC
Annual
Cash Bonus
MPLX LP
Phantom
Units
MPLX LP
Performance
Units
3/1/2017 2/21/2017
3/1/2017 2/21/2017
7,500
60,000
120,000
N/A
279,000 558,000
3/1/2017 2/21/2017
3/1/2017 2/21/2017
37,500
300,000
600,000
232
589
7,891
30,033
55,218
300,016
270,540
Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards (2)
Estimated Future Payouts
Under Equity Incentive Plan
Awards (3)
Type of
Award
Grant
Date
Approval
Date(1)
Threshold
($)
Target
($)
Maximum
($)
Threshold
($)
Target
($)
Maximum
($)
3/1/2017 2/21/2017
3/1/2017 2/21/2017
3/1/2017 2/21/2017
8,000
64,000
128,000
N/A
315,000 630,000
3/1/2017 2/21/2017
8,417
3/1/2017 2/21/2017
40,000
320,000
640,000
N/A
405,000 810,000
All
Other
Shares
of
Stock
or
Units
(#)
628
All Other
Option
Awards:
Underlying
Options
(#)
Exercise
or Base
Price of
Option
Awards
($)
Grant
Date And
Option
Awards(4)
($)
4,495
50.99
64,009
32,022
58,899
320,014
288,576
Name
Gregory S.
Floerke
Donald C.
Templin
MPC Stock
Options
MPC
Restricted
Stock
MPC
Performance
Units
MPC
Annual
Cash Bonus
MPLX LP
Phantom
Units
MPLX LP
Performance
Units
MPC
Annual
Cash Bonus
MPLX LP
Phantom
Units
MPLX LP
Performance
Units
3/1/2017 2/21/2017
31,563
1,200,025
3/1/2017 2/21/2017
150,000 1,200,000 2,400,000
1,082,160
(1)
(2)
(3)
(4)
The MPC Compensation Committee and our Board approved the awards reported in the table above for
Ms. Beall and Messrs. Heminger, Bromley, Floerke and Templin on February 21, 2017, with a grant date of
March 1, 2017. The MPC Compensation Committee and our Board approved the awards reported in the
table above for Mr. Hennigan on May 30, 2017, with a grant date of July 1, 2017.
The target amounts shown in this column reflect the target annual incentive opportunity. No threshold
amount is disclosed as the MPC Compensation Committee has discretion to not award an annual incentive
under the ACB program. Each NEO may generally earn a maximum of 200 percent of the target.
The target amounts shown in this column reflect the number of performance units granted to Ms. Beall and
Messrs. Heminger, Bromley, Floerke and Templin. 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 percent. The threshold
is achieved when the payout percentage is 50 percent for one performance period and zero percent for the
other three performance periods, thus an average payout percentage of 12.5 percent for the performance
cycle. The maximum payout for this award is 200 percent of target.
The amounts shown in this column reflect the total grant date fair value of MPC stock options, MPC
restricted stock, MPLX LP phantom units and MPC/MPLX LP performance units granted in 2017 in
accordance with provisions of the Financial Accounting Standards Board Accounting Standards
Codification 718, Compensation-Stock Compensation (“FASB ASC Topic 718”). The Black-Scholes value
used for the stock options was $14.24 per share. The restricted stock value was based on the MPC closing
stock price on the grant date listed, or the next business day if the grant date was not a business day. The
price used for the March 1, 2017, grants of MPC restricted stock awards was $50.99 per share. The price
used for the July 1, 2017, grants of MPC restricted stock awards was the closing price on July 3, 2017, of
$53.10 per share. MPC performance units are designed to settle 25 percent in MPC common stock and
75 percent in cash. The MPC performance units have a grant date fair value of $0.9203 per unit as
calculated using a Monte Carlo valuation model. Assumptions used in the calculation of these amounts are
233
included in Note 23 to MPC’s financial statements as reported on its Annual Report on Form 10-K for the
year ended December 31, 2017. The phantom unit value was based on the MPLX LP common unit closing
price on the grant date listed, or the next business day if the grant date was not a business day. The price
used for the March 1, 2017, grants of MPLX LP phantom unit awards was $38.02 per unit. The price used
for the July 1, 2017, grants of MPLX LP phantom unit awards was the closing price on July 3, 2017, of
$34.24 per unit. MPLX LP performance units are designed to settle 25 percent in MPLX LP common units
and 75 percent in cash. The MPLX LP performance units have a weighted grant date fair value of $0.9018
per unit, which is calculated using a Monte Carlo valuation model of $0.8036 for the TUR portion (50%)
and target value of $1.00 for the DCF portion (50%). See Item 8. Financial Statements and Supplementary
Data-Note 20 for assumptions used in the calculation of these amounts.
MPC Stock Options (Option Awards)
The MPC Compensation Committee granted stock options to Ms. Beall and Messrs. Bromley and Floerke with a
grant date of March 1, 2017. All options vest in one-third increments on the first, second and third anniversaries
of the date of grant and expire 10 years following the date of grant. No dividends are paid and there are no voting
rights associated with stock options. In the event of the death or retirement (whether mandatory or not) of an
NEO, unvested options granted to such NEO as an officer immediately vest and remain exercisable until the
earlier of five years following the date of death or retirement or the original expiration date. Unvested options
granted to an NEO as a non-officer immediately vest and remain exercisable until the earlier of three years
following the date of death or retirement or the original expiration date. In the event of a change in control of
MPC and a Qualified Termination, unvested options immediately vest and remain exercisable for the original
term of the option. Upon voluntary or involuntary termination of an NEO, unvested options are forfeited. Upon
voluntary or involuntary termination of an NEO for cause, vested options are cancelled. Upon involuntary
termination of an NEO without cause, vested options are exercisable for 90 days following the date of
termination.
MPC Restricted Stock (Stock Awards)
The MPC Compensation Committee granted annual restricted stock awards to Ms. Beall and Messrs. Bromley
and Floerke with a grant date of March 1, 2017, and to Mr. Hennigan with a grant date of July 1, 2017, which
vest in one-third increments on the first, second and third anniversaries of the grant date. The MPC
Compensation Committee also granted Mr. Hennigan restricted stock on July 1, 2017, which fully vests on the
third anniversary of the grant date. Dividends accrue on the restricted stock awards and are paid upon vesting.
There are voting rights associated with unvested restricted stock awards. If an NEO retires under MPC’s
mandatory retirement policy, unvested restricted stock vests and accrued dividends are paid upon the mandatory
retirement date (the first day of the month coincident with or following the officer’s 65th birthday). In the event
of the death of an NEO or a change in control of MPC, unvested restricted stock immediately vests and accrued
dividends are paid. If an NEO retires or otherwise leaves MPC prior to the vesting date, unvested restricted stock
and accrued but unpaid dividends are forfeited.
MPC Performance Units (Equity Incentive Plan Awards)
The MPC Compensation Committee granted annual performance units to Ms. Beall and Messrs. Bromley and
Floerke with a grant date of March 1, 2017. Each performance unit has a target value of $1.00 and is designed to
settle 25 percent in MPC common stock and 75 percent in cash. Payout of these units could vary from $0.00 to
$2.00 per unit and is tied to MPC’s TSR over a 36-month period as compared to the TSR of those in its peer
group for the January 1, 2017, through December 31, 2019, performance period. No dividends are paid and there
are no voting rights associated with unvested performance units. If an NEO retires following the completion of
nine months of the performance period, the NEO will be eligible to receive, at the MPC Compensation
Committee’s discretion, a prorated payout based on the actual results of the entire performance period. If an NEO
retires under MPC’s mandatory retirement policy, outstanding performance units will fully vest, however payout
234
will occur at the end of the full 36-month performance cycle based on the certified results of the performance
cycle. In the event of the death of an NEO, all unvested performance units immediately vest at target levels. In
the event of a change in control of MPC and a Qualified Termination (as defined following the “Potential
Payments upon Termination or Termination in the Event of a Change in Control” table), unvested performance
units will vest and be paid out based on MPC’s actual TSR performance amongst its specified peer group for the
period from the date of grant to the date of the change in control, and target TSR performance for the period from
the date of the change in control to the end of the performance cycle. If an NEO terminates employment under
any other circumstance, unvested performance units are forfeited.
MPC Annual Cash Bonus (Non-Equity Incentive Plan Awards)
The MPC Compensation Committee established the ACB program as a variable incentive program intended to
motivate and reward NEOs for achieving short-term (annual) business objectives that drive overall MPC
shareholder and MPLX LP unitholder value while encouraging responsible risk-taking and accountability.
Bonuses are determined at the discretion of the MPC Compensation Committee and the achievement of
pre-established goals. If an NEO retires on or after July 1 of the performance year, eligibility for a bonus is at the
MPC Compensation Committee’s discretion. In the event of the death of an NEO during the performance period,
unless otherwise determined by the MPC Compensation Committee, a target bonus will be paid. In the event of
change in control of MPC, a cash severance is paid in lieu of a bonus. If an NEO terminates employment under
any other circumstance, the NEO will be ineligible for a bonus payment.
MPLX LP Phantom Units (Other Unit Awards)
The MPLX Board granted annual phantom unit awards to Ms. Beall and Messrs. Heminger, Bromley, Floerke
and Templin with a grant date of March 1, 2017, and to Mr. Hennigan with a grant date of July 1, 2017. The
phantom unit awards vest in one-third increments on the first, second and third anniversaries of the grant date.
The MPLX Board also granted annual phantom unit awards to Mr. Hennigan on July 1, 2017, which fully vest on
the third anniversary of the grant date. Distribution equivalents accrue on the phantom unit awards and are paid
upon vesting. There are no voting rights associated with unvested phantom units. If an NEO retires under MPC’s
mandatory retirement policy, unvested phantom units vest and accrued distribution equivalents are paid upon the
mandatory retirement date (the first day of the month coincident with or following the officer’s 65th birthday.) In
the event of the death of an NEO or a change in control of MPLX LP, unvested phantom units immediately vest
and accrued distribution equivalents are paid. If an NEO retires or otherwise leaves MPLX prior to the vesting
date, unvested phantom units and unpaid distribution equivalents are forfeited.
MPLX LP Performance Units (Equity Incentive Plan Awards)
The MPLX Board granted annual performance units to Ms. Beall and Messrs. Heminger, Bromley, Floerke and
Templin with a grant date of March 1, 2017. Each performance unit has a target value of $1.00 and is designed to
settle 25 percent in MPLX LP common units and 75 percent in cash. Payout of these units could vary from $0.00
to $2.00 per unit and is tied to MPLX LP’s TUR over a 36-month period as compared to the TUR of those in a
peer group for the January 1, 2017 through December 31, 2019 performance period and a DCF goal for the
calendar year 2019. No cash distributions are paid and there are no voting rights associated with unvested
performance units. If an NEO retires following the completion of nine months of the performance period, the
NEO will be eligible to receive, at the discretion of the MPLX Board, a prorated payout based on the actual
results of the entire performance period. 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 approved results of the performance cycle. In the event of the death of an NEO,
all unvested performance units immediately vest at target levels. In the event of a change in control of MPLX LP,
unvested performance units will vest and be paid out based on 1) the TUR portion of the unvested performance
units will be calculated using actual TUR performance amongst its specified peer group for the period from the
date of grant to the date of the change in control, and target TUR performance for the period from the date of the
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change in control to the end of the performance cycle and 2) the DCF-per-MPLX-LP-common-unit portion will
be calculated at target. If an NEO terminates employment under any other circumstance, unvested performance
units are forfeited.
Outstanding Equity Awards at 2017 Fiscal Year-End
The following table provides information regarding unvested MPLX LP phantom units, unvested MPLX LP
performance units, unvested MPC restricted stock, exercisable and unexercisable MPC stock options and
unvested MPC performance units held by each of our NEOs as of December 31, 2017:
Number of
Securities
Underlying
Unexercised
Options
Exercisable
Number of
Securities
Underlying
Unexercised
Options
Unexercisable
(#)
Option
Exercise
Price
($)
Option
Expiration
Date
Name
Gary R. Heminger
Pamela K.M. Beall
Grant
Date
MPLX
LP
MPLX
LP
Number of
Shares or
Units of
Stock
That Have
Not Vested
(3)
(#)
Market
Value of
Shares or
Units of
Stock
That
Have Not
Vested (4)
($)
Equity
Incentive
Plan Awards:
Number of
Unearned
Shares, Units
or Other
Rights that
Have Not
Vested (5)
(#)
Equity
Incentive
Plan Awards:
Market or
Payout Value
of Unearned
Shares, Units
or Other
Rights that
Have Not
Vested (6)
($)
63,665 2,258,198
2,300,000
3,500,000
14,628
518,855
552,500
892,500
3/1/2016 MPC
5,684
11,368(1)
34.63 3/1/2026
2,304
152,018
238,000
359,434
3/1/2017 MPC
4,776(2)
50.99 3/1/2027
Michael J. Hennigan
C. Corwin Bromley
MPLX
LP
MPC
MPLX
LP
116,823 4,143,712
18,833 1,242,601
66,706 2,366,062
300,000
600,000
3/1/2017 MPC
4,214(2) 50.99 3/1/2027
20,450 1,349,291
60,000
102,858
Gregory S. Floerke
MPLX
LP
53,718 1,905,377
320,000
640,000
3/1/2017 MPC
4,495(2)
50.99 3/1/2027
20,489 1,351,864
64,000
109,715
Donald C. Templin
MPLX
LP
51,424 1,824,009
1,950,000
3,150,000
(1)
(2)
(3)
This stock option grant is scheduled to become exercisable in one-third increments on the first, second and
third anniversaries of the date of grant. This remaining unvested portion of the grant will become
exercisable in one-half increments on March 1, 2018 and March 1, 2019.
This stock option is scheduled to become exercisable in one-third increments on the first, second and third
anniversaries of the grant date—March 1, 2018, March 1, 2019 and March 1, 2020.
The amounts shown in this column reflect the number of unvested MPLX LP phantom units and MPC
restricted stock held by each of our NEOs on December 31, 2017. Phantom unit and restricted stock grants
generally are scheduled to vest in one-third increments on the first, second and third anniversaries of the
grant date. The amounts shown in this column also include unvested shares of MPC restricted stock granted
to Messrs. Bromley and Floerke as part of their retention grants that occurred at the time of the MarkWest
Merger. These MPC restricted stock grants are scheduled to vest in full on the third anniversary of the grant
date.
236
Name
Grant Date
Number of Unvested Units
Vesting Dates
MPLX LP Phantom Units
Gary R. Heminger
Pamela K.M. Beall
Michael J. Hennigan
C. Corwin Bromley
Gregory S. Floerke
Donald C. Templin
3/1/2015
3/1/2016
3/1/2017
3/1/2015
3/1/2016
3/1/2017
7/1/2017
7/1/2017
12/18/2015
12/18/2015
3/1/2017
12/18/2015
12/18/2015
3/1/2017
3/1/2015
3/1/2016
3/1/2017
4,460
27,642
31,563
63,665
345
5,340
8,943
14,628
46,729
70,094
116,823
50,240
8,575
7,891
66,706
36,476
8,825
8,417
53,718
1,014
18,847
31,563
51,424
3/1/2018
3/1/2018, 3/1/2019
3/1/2018, 3/1/2019, 3/1/2020
3/1/2018
3/1/2018, 3/1/2019
3/1/2018, 3/1/2019, 3/1/2020
7/1/2018, 7/1/2019, 7/1/2020
7/1/2020
Upon termination without cause
12/18/2018
3/1/2018, 3/1/2019, 3/1/2020
Upon termination without cause
12/18/2018
3/1/2018, 3/1/2019, 3/1/2020
3/1/2018
3/1/2018, 3/1/2019
3/1/2018, 3/1/2019, 3/1/2020
Name
Grant Date
Number of Unvested Shares
Vesting Dates
MPC Restricted Stock
Pamela K.M. Beall
Michael J. Hennigan
C. Corwin Bromley
Gregory S. Floerke
3/1/2016
3/1/2017
7/1/2017
7/1/2017
12/18/2015
3/1/2017
12/18/2015
3/1/2017
1,637
667
2,304
7,533
11,300
18,833
19,861
589
20,450
19,861
628
20,489
3/1/2018, 3/1/2019
3/1/2018, 3/1/2019, 3/1/2020
7/1/2018, 7/1/2019, 7/1/2020
7/1/2020
12/18/2018
3/1/2018, 3/1/2019, 3/1/2020
12/18/2018
3/1/2018, 3/1/2019, 3/1/2020
(4)
The amounts shown in this column reflect the aggregate value of all unvested MPLX LP phantom units and
MPC restricted stock held by each of our NEOs on December 31, 2017, using the December 29, 2017,
MPLX LP common unit closing price of $35.47 per unit and MPC closing price of $65.98 per share. It also
includes the value of unvested shares of MPC restricted stock granted to Messrs. Bromley and Floerke as
part of their retention grants as discussed in the “Retention Agreements with Former MarkWest Executives”
237
(5)
section of our Annual Report on Form10-K for the year ended December 31, 2015. These are valued using
the MPC closing price on December 29, 2017, of $65.98 per share.
The amounts shown in this column reflect the number of unvested performance units held by each of our
NEOs on December 31, 2017. Performance unit grants have a 36-month performance cycle and are designed
to settle 25 percent in MPLX LP common units/MPC common stock and 75 percent in cash. Each of these
performance unit grants has a target value of $1.00 and payout may vary from $0.00 to $2.00 per unit.
Payout for MPC performance unit awards made in 2016 and 2017 and MPLX performance unit awards
made in 2016 is tied to our TUR/TSR as compared to specified peer groups. MPLX performance unit
awards made in 2017 is tied to our TUR as compared to specified peer groups and a specified
DCF-per-MPLX-LP-common-unit goal. Mr. Hennigan, who was not an employee on the dates these grants
were made, does not have any unvested performance units.
MPLX LP Performance Units
Name
Grant Date
Number of Unvested Units
Gary R. Heminger
Pamela K.M. Beall
3/1/2016
3/1/2017
3/1/2016
3/1/2017
C. Corwin Bromley
3/1/2017
Gregory S. Floerke
3/1/2017
Donald C. Templin
3/1/2016
3/1/2017
1,100,000
1,200,000
2,300,000
212,500
340,000
552,500
300,000
300,000
320,000
320,000
750,000
1,200,000
1,950,000
MPC Performance Units
Name
Grant Date
Number of Unvested Units
Pamela K.M. Beall
3/1/2016
3/1/2017
C. Corwin Bromley
3/1/2017
Gregory S. Floerke
3/1/2017
170,000
68,000
238,000
60,000
60,000
64,000
64,000
Performance Period
Ending Date
12/31/2018
12/31/2019
12/31/2018
12/31/2019
12/31/2019
12/31/2019
12/31/2018
12/31/2019
Performance Period
Ending Date
12/31/2018
12/31/2019
12/31/2019
12/31/2019
(6)
The amount shown in this column for MPC reflects the aggregate value of all performance units held by
Ms. Beall and Messrs. Floerke and Bromley on December 31, 2017, assuming a payout of $1.4286 per unit
for the March 1, 2016, grant and $1.7143 per unit for the March 1, 2017, grant, which is the next higher
performance achievement that exceeds the performance for these grants’ performance period that ended
December 31, 2017. The amounts shown in this column for MPLX LP reflect the aggregate value of all
performance units held by Ms. Beall and Messrs. Heminger, Floerke, Bromley and Templin on
December 31, 2017, assuming a payout of $1.0000 per unit for the March 1, 2016, grant and $2.0000 per
238
unit for the March 1, 2017, grant, which is the next higher performance achievement that exceeds the
performance for these grants’ performance period that ended December 31, 2017. Mr. Hennigan, who was
not an employee on the dates these grants were made, does not have any unvested performance units.
Option Exercises and Units Vested in 2017
The following table provides information regarding phantom units and MPC restricted stock that vested in 2017:
Name
Gary R. Heminger
Pamela K.M. Beall
C. Corwin Bromley
Gregory S. Floerke
Donald C. Templin
Stock Awards
Number of Units/Shares
Acquired on Vesting (#)
Value Realized on Vesting(1)
($)
MPLX LP
MPLX LP
MPC
MPLX LP
MPLX LP
MPLX LP
25,121
3,597
2,798
8,574
8,825
11,942
951,332
136,218
141,971
311,579
320,701
452,244
(1)
This column reflects the actual pre-tax gain realized upon vesting of phantom units and restricted stock,
which is the fair market value of the units or stock on the date of vesting.
Post-Employment Benefits for 2017
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 and other employees who are “highly compensated” as defined by
Section 414(q) of the Internal Revenue Code (annual compensation of $120,000 or more in 2017).
2017 Pension Benefits Table
Name
Pamela K.M. Beall
Michael J. Hennigan
C. Corwin Bromley
Gregory S. Floerke
Donald C. Templin
Plan Name
Marathon Petroleum Retirement Plan
Marathon Petroleum Excess Benefit Plan
Marathon Petroleum Retirement Plan
Marathon Petroleum Excess Benefit Plan
Marathon Petroleum Retirement Plan
Marathon Petroleum Excess Benefit Plan
Marathon Petroleum Retirement Plan
Marathon Petroleum Excess Benefit Plan
Marathon Petroleum Retirement Plan
Marathon Petroleum Excess Benefit Plan
Number of Years of
Credited Service (1)
Present Value of
Accumulated
Benefit(2) ($)
Payments
During Last
Fiscal Year ($)
15.67 years
791,415
15.67 years 1,519,789
23,826
0.58 years
102,496
0.58 years
59,249
2.0 years
135,683
2.0 years
46,827
2.0 years
94,770
2.0 years
74,709
6.5 years
474,653
6.5 years
—
—
—
—
—
—
—
—
—
—
(1)
(2)
The number of years of credited service shown in this column represents the number of years the NEO has
participated in the plan. However, plan participation service 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 3.55 percent, the RP2000 mortality table for lump sums, a 96 percent lump sum
239
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 is
0.75 percent for all anticipated years of retirement.
The 2017 Pension Benefits Table below reflects the actuarial present value of accumulated benefits payable to
each of our NEOs under the Marathon Petroleum Retirement Plan and the defined benefit portion of the excess
plans as of December 31, 2017. These values have been determined using actuarial assumptions consistent with
those used in MPC’s financial statements.
Marathon Petroleum Retirement Plans
Marathon Petroleum Retirement Plan
In general, our NEOs are immediately eligible to participate in the Marathon Petroleum Retirement Plan. The
Marathon Petroleum Retirement Plan 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% ×
Final
Average Pay
×
Years of
Participation ] — [ 1.33% ×
Estimated
Primary
Social Security
Benefit
×
Years of
Participation]
This formula is referred to 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 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 seven percent pay credit;
Participants with at least 50 but less than 70 points receive a nine percent pay credit; and
Participants with 70 or more points receive an 11 percent 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.
240
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 in accordance with the table below:
Age at
Retirement
Early Retirement
Factor
Age at
Retirement
Early Retirement
Factor
62
61
60
59
58
57
56
100%
97%
94%
91%
87%
83%
79%
55
54
53
52
51
50
75%
71%
67%
63%
59%
55%
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 has accrued a benefit under the Marathon legacy benefit formula.
Ms. Beall is 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
2017, Ms. Beall and Mr. Bromley received pay credits equal to 11 percent of compensation, which is the highest
level of pay credit available under the plan. Messrs. Hennigan, Floerke and Templin received pay credits equal to
nine percent of compensation. Additionally, under the terms of his employment offer entered into with MPC’s
former parent company Marathon Oil Company, Mr. Templin receives additional contributions to the
non-qualified plan to ensure that the aggregate contributions from the qualified and non-qualified retirement
plans equal 11 percent of his applicable compensation. Based on the age and service calculation specified in the
Marathon Petroleum Retirement Plan, Mr. Templin will receive a supplemental non-qualified contribution set at
2 percent of eligible compensation in the Marathon Petroleum Excess Benefit Plan. This supplemental
contribution will be eliminated when Mr. Templin becomes eligible for the full 11 percent contribution under the
qualified plan in 2022.
Marathon Petroleum Excess Benefit Plan (Defined Benefit)
Marathon Petroleum Company LP (or MPC LP) sponsors the Marathon Petroleum Excess Benefit Plan, an
unfunded, non-qualified retirement plan, for the benefit of a select group of management and highly compensated
employees. The Marathon Petroleum Excess Benefit 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 the Marathon Petroleum Excess
Benefit 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. The Marathon Petroleum Excess Benefit 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. However, as Messrs. Hennigan, Bromley and
Floerke have not accrued a benefit under the Marathon legacy benefit formula, they are not eligible for this
enhancement.
Marathon Petroleum Thrift Plan
MPC LP sponsors the Marathon Petroleum Thrift Plan, a tax-qualified employee savings plan. In general, all of
MPC’s employees, including our NEOs, are immediately eligible to participate in the Marathon Petroleum Thrift
Plan. The purpose of the Marathon Petroleum Thrift Plan is to assist employees in maintaining a steady program
of savings to supplement their retirement income and to meet other financial needs.
241
The Marathon Petroleum Thrift Plan allows contributions for NEOs on a pre-tax or Roth basis. Employees may
elect to make any combination of pre-tax or Roth contributions from one percent to a maximum of 75 percent of
gross pay. The participating employer will match participant contributions at a rate of 117 percent up to a
maximum of six percent of gross pay. All matching contributions made are fully vested.
Marathon Petroleum Excess Benefit Plan (Defined Contribution)
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, comprise those eligible to receive
defined contribution accruals under the Marathon Petroleum Excess Benefit Plan. The defined contribution
formula in the Marathon Petroleum Excess Benefit Plan is designed to allow 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” option of the Marathon Petroleum Thrift Plan. The annual rate of
return on this option for the year ended December 31, 2017, was 1.71 percent. All distributions from the plan are
paid in the form of a lump sum following the participant’s separation from service.
As noted, our NEOs no longer participate in the defined contribution formula of the Marathon Petroleum Excess
Benefit Plan; all non-qualified employer matching contributions for our NEOs now accrue under the Marathon
Petroleum Amended and Restated Deferred Compensation Plan.
Other Non-Qualified Deferred Compensation
The Non-Qualified Deferred Compensation table below provides information regarding the non-qualified savings
and deferred compensation plans sponsored by MPC or its subsidiaries:
2017 Non-Qualified Deferred Compensation
Name
Pamela K.M. Beall
Executive
contributions
in last fiscal
year
($)
Registrant
contributions
in last fiscal
year(1)
($)
Aggregate
earnings in
last fiscal
year
($)
Aggregate
withdrawals/
distributions
($)
Aggregate
balance at
last fiscal
year-end
($)
Marathon Petroleum Excess Benefit Plan
Marathon Petroleum Deferred Compensation Plan
—
—
—
53,838
2,880
121,391
Michael J. Hennigan
Marathon Petroleum Deferred Compensation Plan
280,000
79,326
34,667
C. Corwin Bromley
Marathon Petroleum Deferred Compensation Plan
9,300
45,279
11,758
Gregory S. Floerke
Marathon Petroleum Deferred Compensation Plan
Donald C. Templin
Marathon Petroleum Deferred Compensation Plan
—
—
41,864
14,270
59,293
48,440
—
—
—
—
—
—
135,932
901,206
393,993
108,503
91,488
380,728
(1)
The amounts shown in this column are also included in the “All Other Compensation” column of the 2017
Summary Compensation Table.
Marathon Petroleum Deferred Compensation Plan
MPC LP sponsors the Marathon Petroleum Amended and Restated Deferred Compensation Plan (which we refer
to as the Marathon Petroleum Deferred Compensation Plan). The Marathon Petroleum Deferred Compensation
242
Plan is an unfunded, non-qualified plan in which our NEOs may participate. This plan is designed to provide
participants the opportunity to supplement their retirement savings by deferring income in a tax-effective
manner. Participants may defer up to 20 percent of their salary and bonus each year. Deferral elections are made
in December of each year for amounts to be earned in the following year and are irrevocable. The Marathon
Petroleum Deferred Compensation Plan provides for a match on any participant’s salary and bonus deferral equal
to the percentage provided by the Marathon Petroleum Thrift Plan, which is currently 117 percent of
contributions up to six percent of gross pay. Participants are fully vested in their deferrals under the plan.
In addition, the Marathon Petroleum Deferred Compensation Plan provides benefits for participants equal to the
employer matching contributions they would have otherwise received under the tax-qualified Marathon
Petroleum Thrift Plan were it not for Internal Revenue Code limitations. All matching contributions made on or
after January 1, 2016, are fully vested.
The investment options available under the Marathon Petroleum Deferred Compensation Plan generally mirror
the investment options offered to participants under the Marathon Petroleum Thrift Plan with the exception of
MPC common stock and BrokerageLink, which are not investment options under the Marathon Petroleum
Deferred Compensation Plan. The Marathon Petroleum Deferred Compensation Plan provides that all
participants will receive their benefits as a lump sum following separation from service.
Section 409A Compliance
All of MPC’s non-qualified 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.
Potential Payments Upon a Termination or Change In Control
We have adopted the MPLX LP Executive Change in Control Severance Benefits Plan (the “MPLX CIC Plan”),
which provides certain benefits upon a change in control of MPLX and a Qualified Termination and is designed
to ensure continuity of management through a change-in-control transaction. For purposes of the MPLX CIC
Plan, a Qualified Termination is one where an NEO separates from service in connection with or within two
years after the date of a change in control of MPLX unless such separation from service is:
•
•
•
•
due to death or disability;
for cause;
effected by the employee other than for good reason, being 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 employee attains age 65.
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.
In the event of a Qualified Termination, our NEOs and other executives officers are 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;
243
•
•
a cash payment equal to the actuarial equivalent of the difference between amounts receivable by the
NEO under the final average pay formula in MPC’s pension plans and those which would be payable
if: the NEO had an additional three years of participation service credit; the NEO’s final average pay
would be the higher of their salary at the time of the change-in-control event or termination plus their
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 credit and
three additional years of age; and the NEO’s pension had been fully vested; and
a cash payment equal to the difference between amounts receivable under MPC’s defined contribution
plans and amounts which would have been received if the NEO’s defined contribution plan account
had been fully vested.
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. With respect to outstanding MPLX performance units, the portion of the
award attributable to the pre-change in control period would vest based on actual performance during such period
and the portion attributable to the post-change in control period would vest at the target level. In addition, if an
NEO incurs a Qualified termination in connection with a change in control of MPLX or separates from service
with MPC as a result of the change in control transaction (i.e., where the NEO commences employment with the
acquirer or successor entity in the transaction and terminates employment with MPC), 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 regularly scheduled performance period.
The table below reflects the amount of compensation payable to each of our NEOs if a termination occurred on
December 31, 2017. The table reflects only those termination scenarios for each NEO that would trigger a
separation payment, including a change in control and a Qualified Termination. The table uses our closing
common unit price on December 29, 2017, the last day of trading of the year.
Mr. Bromley retired effective January 1, 2018.
244
Potential Payments upon Termination or Termination in the Event of a Change in Control
Name
Gary R. Heminger
Scenario
Severance(1)
($)
Additional
Pension
Benefits(2)
($)
Accelerated
Options(3)
($)
Accelerated
Restricted
Stock(4)
($)
Accelerated
Performance
Units(5)
($)
Other
Benefits(6)
($)
Total
($)
Change in Control
(With Qualified
Termination)
4,201,389 32,520,813 12,732,756 7,738,959 9,660,000
50,595 66,904,512
Pamela K. M. Beall Change in Control
(With Qualified
Termination)(7)
Voluntary
Retirement
3,225,000
2,053,085
529,354
729,727
790,500
41,442
7,369,108
—
—
529,354
—
—
—
529,354
Michael J. Hennigan Change in Control
(With Qualified
Termination)(7)
2,400,000
C. Corwin Bromley Change in Control
(With Qualified
Termination)(7)
Voluntary
Retirement
Involuntary
Termination by
Company Without
Cause or Good
Reason(8)
Separation from
Service Without
Cause(9)
2,745,000
—
—
—
—
—
—
—
—
— 5,386,313
— 53,655
7,839,968
63,168 3,715,353
360,000
50,930
6,934,451
63,168
—
—
—
63,168
— 3,396,597
— 1,782,013
—
—
— 3,396,597
— 1,782,013
2,625,000
—
67,380 3,257,241
384,000
50,808
6,384,429
Gregory S. Floerke Change in Control
(With Qualified
Termination)(7)
Involuntary
Termination by
Company Without
Cause or Good
Reason(8)
Separation from
Service Without
Cause(9)
Donald C. Templin Change in Control
(With Qualified
Termination)(7)
6,600,000
—
—
—
—
—
— 2,917,255
— 1,293,804
—
—
— 2,917,255
— 1,293,804
— 1,824,009 1,950,000
54,469 10,428,478
(1)
(2)
(3)
The payment of cash severance upon a change in control requires both (a) the occurrence of a change in control and (b) a
qualified termination as specified in the MPLX’s Executive Change in Control Severance Benefits Plan. If the Qualified
Termination occurs within three years of the date the officer reaches age 65, the officer’s benefit will be limited to a pro
rata portion of the benefit. The officer’s benefit is calculated using a fraction equal to the number of full and partial
months existing between the Qualifying Termination and the officer’s 65th birthday divided by 36 months.
Mr. Heminger’s benefit has been reduced as he is within three years of reaching age 65.
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 percent male and 25 percent female;
a discount rate of 1.00 percent for NEOs who are retirement eligible (taking into account the additional three years of age
and service credit) and 1.00 percent 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.
The vesting of stock options is accelerated upon retirement or a change in control with a qualified termination. The
amounts shown in this column reflect the value that would be realized if accelerated stock options were exercised on
245
December 31, 2017, taking into account the spread (if any) between the options’ exercise prices and the closing price of
MPC common stock on December 29, 2017.
The vesting of restricted stock is accelerated upon a change in control with a qualified termination. The amounts shown
in this column reflect the value that would be realized if accelerated MPC restricted stock and MPLX phantom unit
awards vested on December 31, 2017, taking into account the closing price of MPC common stock and MPLX LP
common units on December 29, 2017.
The amounts shown in this column 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.
(4)
(5)
(6) Other benefits include 36 months of continued health, dental and life insurance coverage in the event of a change in
(7)
(8)
(9)
control.
The additional pension benefits due to a change in control and subsequent Qualified Termination is attributable solely to
the final average pay formula in the Executive Change in Control Severance Benefits Plan. Given the date of hire for
Messrs. Hennigan, Bromley, Floerke and Templin, they are not eligible for any benefit under this formula.
If either of Messrs. Bromley or Floerke separate from service as a result of a forced relocation of his principal place of
employment to a location more than 50 miles from his current principal place of employment, his unvested MPLX LP
phantom units and MPC restricted stock received as part of his retention grants awarded in 2015 will vest and become
payable.
If either of Messrs. Bromley or Floerke separate from service without cause, the separated NEO is entitled to a portion of
the grant of MPLX LP phantom units received as part of his retention grants awarded in 2015.
COMPENSATION OF OUR DIRECTORS
The officers or employees of our general partner or of MPC who also serve as directors of our general partner do
not receive additional compensation for their service as a director of our general partner. Directors of our general
partner who are not officers or employees of our general partner or of MPC receive compensation as
“non-management directors.”
In October 2016, the board of directors of our general partner approved an increase to the non-management
director compensation package. Effective January 1, 2017, each of our non-management directors receives a
compensation package having an annual value equal to $175,000, instead of the prior $150,000, and payable as
follows:
•
•
50 percent in the form of a cash retainer, payable in equal quarterly installments of $21,875 (at the
commencement of each calendar quarter); and
50 percent in the form of a phantom unit award (granted at the commencement of each calendar
quarter) representing a number of units having a value (based on the closing price of our common units
on the date of grant) equal to $21,875. The phantom unit awards are not subject to any risk of forfeiture
once granted and are automatically deferred until and settled in common units at the time the
non-management director separates from service on the board or upon his or her death, if earlier.
In addition, the chair of each standing committee of the board and our lead director, who also serves on the
executive committee of the board, each receive an additional annual retainer. These additional annual retainers
are payable in cash (in equal quarterly installments at the commencement of each calendar quarter) as follows:
• Audit Committee Chair—$15,000;
• Conflicts Committee Chair—$15,000;
• Lead Director & Executive Committee Member—$15,000; and
• Other Committee Chair—$7,500.
Members of the conflicts committee will also receive a meeting fee in the amount of $1,500 per meeting for each
conflicts committee meeting such member attends in a calendar year in excess of six meetings.
Further, each director is indemnified for his or her actions associated with being a director to the fullest extent
permitted under Delaware law and is reimbursed for all expenses incurred in attending to his or her duties as a
director.
246
2017 Director Compensation Table
Amounts reflected in the table below represent compensation earned by or paid to our general partner’s
non-employee directors for the year ended December 31, 2017:
Fees
Earned or
Paid in
Cash (1)
($)
159,500
87,500
174,500
100,042
167,000
87,500
87,500
164,750
Unit
Awards(2)
($)
Option
Awards
($)
Non-Equity
Incentive Plan
Compensation
($)
87,500 —
87,500 —
87,500 —
87,500 —
87,500 —
87,500 —
87,500 —
87,500 —
—
—
—
—
—
—
—
—
Change in
Pension Value
and Non-
Qualified
Deferred
Compensation
Earnings
($)
—
—
—
—
—
—
—
—
All Other
Compensation(3)
($)
—
—
10,000
1,000
5,000
—
—
—
Total
($)
247,000
175,000
272,000
188,542
259,500
175,000
175,000
252,250
Name
Michael L. Beatty
David A. Daberko
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
Frank M. Semple
John P. Surma
C. Richard Wilson(4)
(1)
(2)
(3)
The amounts shown in this column reflect the director cash retainers, conflicts committee meeting fees and
committee chair and lead director fees earned or paid for service from January 1, 2017, through
December 31, 2017. The amounts shown for Messrs. Peiffer and Wilson reflect a prorated audit committee
chair fee.
The amounts shown in this column reflect the aggregate grant date fair value, as computed in accordance
with provisions of Financial Accounting Standards Board Accounting Standards Codification 718,
Compensation—Stock Compensation (“FASB ASC Topic 718”), for phantom unit awards granted to the
non-management directors in 2017. All phantom unit awards are deferred until departure from the board and
distribution equivalents in the form of additional phantom unit awards are credited to non-management
director deferred accounts as and when distributions are paid on our common units. The aggregate number
of MPLX LP phantom unit awards credited for board service and outstanding as of December 31, 2017, for
each non-employee director is as follows: Messrs. Daberko, Helms, Sandman, Surma, and Wilson, 10,617;
Mr. Peiffer, 7,982; Mr. Beatty, 5,307; and Mr. Semple, 2,970.
The amounts shown in this column reflect contributions made on behalf of Messrs. Helms, Peiffer and
Sandman to educational institutions under our matching gifts program.
(4) Mr. Wilson retired from the board of directors of our general partner pursuant to our mandatory retirement
policy effective December 31, 2017.
247
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 from filings made with the SEC as to each person or group who, as of
December 31, 2017 (unless otherwise noted), beneficially owned more than five percent of our outstanding units
or more than five percent of any class of our outstanding units:
Name and Address
of Beneficial Owner
Number of
Common
Units
Representing
Limited
Partner
Interests
Percent of
Common
Units
Representing
Limited
Partner
Interests
Number
of
General
Partner
Units
Percent of
General
Partner
Units
Percent of
Units
Representing
Total
Partnership
Interests
Marathon Petroleum Corporation(1)
118,090,823
29.0% 8,308,773
100%
30.4%
539 S. Main Street
Findlay, Ohio 45840
Tortoise Capital Advisors, L.L.C.(2)
11550 Ash Street, Suite 300
Leawood, Kansas 66211
ALPS Advisors, Inc.(3)
1290 Broadway, Suite 1100
Denver, Colorado 80203
Alerian MLP ETF(3)
1290 Broadway, Suite 1100
Denver, Colorado 80203
24,236,080(2)
5.6%(2)
—
—
5.8%
23,994,554(3)
5.9%(3)
—
—
5.8%
23,771,609(3)
5.8%(3)
—
—
5.7%
(1)
The 118,090,823 common units representing limited partner interests (“MPLX LP common units”) are
directly held by MPLX Logistics Holdings LLC, MPLX Holdings Inc. and MPLX GP LLC. The 8,308,773
general partner units are directly held by MPLX GP LLC and represent its two percent general partner
interest in MPLX LP. Marathon Petroleum Corporation is the ultimate parent company of MPLX GP LLC,
MPLX Logistics Holdings LLC and MPLX Holdings Inc. and may be deemed to beneficially own the
MPLX LP common units directly held by MPLX GP LLC, MPLX Logistics Holdings LLC and MPLX
Holdings Inc., and the general partner units directly held by MPLX GP LLC. MPC Investment LLC owns
all of the membership interests in or shares of MPLX GP LLC, MPLX Logistics Holdings LLC and MPLX
Holdings Inc., and MPC owns all of the membership interests in MPC Investment LLC.
(2) According to a Schedule 13G/A filed with the SEC on February 13, 2018, by Tortoise Capital Advisors,
L.L.C. (“TCA”). According to such Schedule 13G/A, TCA acts as an investment adviser to certain
investment companies registered under the Investment Company Act of 1940. TCA, by virtue of investment
advisory agreements with these investment companies, has all investment and voting power over securities
owned of record by these investment companies. However, despite their delegation of investment and voting
power to TCA, these investment companies may be deemed to be the beneficial owners under Rule 13d-3 of
the Act, of the securities they own of record because they have the right to acquire investment and voting
power through termination of their investment advisory agreement with TCA. Thus, TCA has reported that
it shares voting power and dispositive power over the securities owned of record by these investment
companies. TCA also acts as an investment adviser to certain managed accounts. Under contractual
agreements with these managed account clients, TCA, with respect to the securities held in these client
accounts, has investment and voting power with respect to certain of these client accounts, and has
investment power but no voting power with respect to certain other of these client accounts. TCA has
reported that it shares voting and/or investment power over the securities held by these client managed
accounts despite a delegation of voting and/or investment power to TCA because the clients have the right
248
to acquire investment and voting power through termination of their agreements with TCA. TCA may be
deemed the beneficial owner of the securities covered by this statement under Rule 13d-3 of the Act that are
held by its clients. Subject to the above, TCA reported that it has beneficial ownership of 24,236,080 MPLX
LP common units or 5.6 percent of the MPLX LP common units outstanding, sole voting power over
559,771 of our MPLX LP common units, shared voting power over 20,579,794 of our MPLX LP common
units, sole dispositive power over 559,771 of our MPLX LP common units and shared dispositive power
over 23,676,309 of our MPLX LP common units.
(3) According to a Schedule 13G/A filed with the SEC on February 6, 2018, by ALPS Advisors, Inc. (“AAI”)
and Alerian MLP ETF. According to such Schedule 13G/A, AAI, an investment adviser registered under
Section 203 of the Investment Advisors Act of 1940, furnishes investment advice to investment companies
registered under the Investment Company Act of 1940 (collectively referred to as the “Funds”). In its role as
investment advisor, AAI has voting and/or investment power over the securities of the Issuer that are owned
by the Funds, and may be deemed to be the beneficial owner of the shares of the Issuer held by the Funds.
However, all securities reported in this schedule are owned by the Funds. AAI disclaims beneficial
ownership of such securities. In addition, the filing of this Schedule 13G/A shall not be construed as an
admission that the reporting person or any of its affiliates is the beneficial owner of any securities covered
by this Schedule 13G/A for any other purposes than Section 13(d) of the Securities Exchange Act of 1934.
Alerian MLP ETF is an investment company registered under the Investment Company Act of 1940 and is
one of the Funds to which AAI provides investment advice. Subject to the above, AAI reported that it has
beneficial ownership of 23,994,554 MPLX LP common units or 5.90 percent of the MPLX LP common
units outstanding, sole voting power over none of our MPLX LP common units, shared voting power over
23,994,554 of our MPLX LP common units, sole dispositive power over none of our MPLX LP common
units and shared dispositive power over 23,994,554 of our MPLX LP common units. Subject to the above,
and according to the Schedule 13G/A, Alerian MLP ETF reported that it has beneficial ownership of
23,771,609 MPLX LP common units or 5.84 percent of the MPLX LP common units outstanding, sole
voting power over none of our MPLX LP common units, shared voting power over 23,771,609 of our
MPLX LP common units, sole dispositive power over none of our MPLX LP common units and shared
dispositive power over 23,771,609 of our MPLX LP common units.
249
Security Ownership of Directors and Executive Officers
The following table sets forth the number of MPLX LP common units beneficially owned as of January 31, 2018,
except as otherwise noted, by each director of our general partner, by each named executive officer of our
general partner and by all directors and executive officers of our general partner as a group. The address for each
person named below is c/o MPLX LP, 200 East Hardin Street, Findlay, Ohio 45840.
Name of Beneficial Owner
Directors / Named Executive Officers
Gary R. Heminger
Pamela K.M. Beall
Michael L. Beatty
C. Corwin Bromley
David A. Daberko
Gregory S. Floerke
Timothy T. Griffith
Christopher A. Helms
Michael J. Hennigan
Garry L. Peiffer
Dan D. Sandman
Frank M. Semple
John P. Surma
Donald C. Templin
All Directors and Executive Officers as a group (17
reporting persons)
Amount and Nature of
Beneficial Ownership (1)
Percent of
Total
Outstanding
206,186(2)(5)(6)(7)
29,410(2)(5)(7)
33,284(2)(4)
56,072(2)(5)
23,433(2)(3)(4)
74,774(2)(5)
23,752(2)(5)(7)
22,223(2)(4)
116,823(5)
40,286(4)(6)
55,223(2)(4)
580,495(2)(3)(4)(6)
20,933(2)(3)(4)
84,154(2)(5)(7)
1,396,119(2)(3)(4)(5)(6)(7)
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
(3)
(4)
(1) None of the common units reported in this column are pledged as security.
Includes common units directly or indirectly held in beneficial form.
(2)
Includes phantom unit awards granted pursuant to the MPLX LP 2012 Incentive Compensation Plan and
credited within a deferred account pursuant to the Marathon Petroleum Corporation Deferred Compensation
Plan for Non-Employee Directors. The aggregate number of phantom unit awards credited as of January 31,
2018, for each of Messrs. Daberko and Surma is 2,210; and Mr. Semple 624.
Includes phantom unit awards granted pursuant to the MPLX LP 2012 Incentive Compensation Plan and
credited within a deferred account pursuant to the MPLX GP LLC Amended and Restated
Non-Management Director Compensation Policy and Director Equity Award Terms. The aggregate number
of phantom unit awards credited as of January 31, 2018, for the non-management directors of our general
partner is as follows: Messrs. Daberko, Helms, Sandman and Surma, 11,223 each; Mr. Beatty, 5,914;
Mr. Peiffer, 8,589; and Mr. Semple, 3,577.
Includes phantom unit awards granted pursuant to the MPLX LP 2012 Incentive Compensation Plan, which
may be forfeited under certain conditions.
Includes common units indirectly beneficially owned in trust. The number of common units held in trust as
of January 31, 2018, by each applicable director or named executive officer of our general partner is as
follows: Mr. Heminger, 35,750; Mr. Peiffer, 31,697; and Mr. Semple, 527,517.
Includes common units issued in settlement of performance units within sixty days of January 31, 2018.
The percentage of common units beneficially owned by each director or each executive officer of our
general partner does not exceed one percent of the common units outstanding, and the percentage of
common units beneficially owned by all directors and executive officers of our general partner as a group
does not exceed one percent of the common units outstanding.
*
(5)
(6)
(7)
The following table sets forth the number of shares of MPC common stock beneficially owned as of January 31,
2018, except as otherwise noted, by each director of our general partner, by each named executive officer of our
250
general partner and by all directors and executive officers of our general partner as a group. The address for each
person named below is c/o MPLX LP, 200 East Hardin Street, Findlay, Ohio 45840.
Name of Beneficial Owner
Directors/Named Executive Officers
Gary R. Heminger
Pamela K.M. Beall
Michael L. Beatty
C. Corwin Bromley
David A. Daberko
Gregory S. Floerke
Timothy T. Griffith
Christopher A. Helms
Michael J. Hennigan
Garry L. Peiffer
Dan D. Sandman
Frank M. Semple
John P. Surma
Donald C. Templin
All Directors and Executive Officers as a group
(17 reporting persons)
Amount and Nature of
Beneficial Ownership(1)
Percent of
Total
Outstanding
2,859,765(2)(4)(5)(7)(8)(9)
113,539(2)(4)(8)(9)
—
16,922(2)(8)
151,356(2)(3)
22,151(4)(5)(8)
221,662(2)(4)(8)(9)
—
18,833(4)
63,394(7)
—
3,646(3)
40,578(3)(7)
528,677(2)(4)(8)(9)
4,342,006(2)(3)(4)(5)(6)(7)(8)(9)
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
(1) None of the shares of common stock reported in this column are pledged as security.
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
*
Includes shares of common stock directly or indirectly held in registered or beneficial form.
Includes restricted stock unit awards granted pursuant to the Second Amended and Restated Marathon
Petroleum Corporation 2011 Incentive Compensation Plan and/or the Marathon Petroleum Corporation
2012 Incentive Compensation Plan, and credited within a deferred account pursuant to the Marathon
Petroleum Corporation Deferred Compensation Plan for Non-Employee Directors. The aggregate number of
restricted stock unit awards credited as of January 31, 2018, is as follows: Mr. Daberko, 147,356;
Mr. Semple, 3,646; and Mr. Surma, 30,578.
Includes shares of restricted stock issued pursuant to the Marathon Petroleum Corporation 2012 Incentive
Compensation Plan, which are subject to limits on sale and transfer, and may be forfeited under certain
conditions.
Includes shares of common stock held within the Marathon Petroleum Thrift Plan.
Includes shares of common stock held within the Marathon Petroleum Corporation Dividend Reinvestment
and Direct Stock Purchase Plan.
Includes shares of common stock indirectly beneficially owned in trust. The number of shares held in trust
as of January 31, 2018, by each applicable director or named executive officer of our general partner is as
follows: Mr. Heminger, 21,228; Mr. Peiffer, 63,394; and Mr. Surma, 10,000.
Includes stock options exercisable within sixty days of January 31, 2018.
Includes shares of common stock issued in settlement of performance units within sixty days of January 31,
2018.
The percentage of shares beneficially owned by each director or each executive officer of our general
partner does not exceed one percent of the MPC common shares outstanding, and the percentage of shares
beneficially owned by all directors and executive officers of our general partner as a group does not exceed
one percent of the MPC common shares outstanding.
251
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 2017, with respect to common units that may be
issued under the MPLX LP 2012 Incentive Compensation Plan:
Plan category
Equity compensation plans approved by security holders
Equity compensation plans not approved by security holders
Total
Number of
securities to
be issued
upon
exercise of
outstanding
options,
warrants
and rights(1)
1,494,551
—
1,494,551
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(3)
586,637
—
586,637
(1)
Includes the following:
(a)
(b)
1,351,523 phantom unit awards granted pursuant to the MPLX 2012 Plan for common units unissued
and not forfeited, cancelled or expired as of December 31, 2017.
143,028 units as the maximum potential number of common units that could be issued in settlement of
performance units outstanding as of December 31, 2017, pursuant to the MPLX 2012 Plan based on the
closing price of our common units on December 29, 2017, of $35.47 per unit. The number of units
reported for this award vehicle may overstate dilution. See Item 8. Financial Statements and
Supplementary Data—Note 20 for more information on performance unit awards granted under the
MPLX 2012 Plan.
(2)
There is no exercise price associated with phantom unit awards.
(3) Reflects the common units available for issuance pursuant to the MPLX 2012 Plan. The number of units
reported in this column assumes 143,028 as the maximum potential number of common units that could be
issued in settlement of performance units outstanding as of December 31, 2017, pursuant to the MPLX 2012
Plan based on the closing price of our common units on December 29, 2017, of $35.47 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 2012 Plan. See Item 8. Financial Statements and Supplementary Data—Note 20 for
more information on performance unit awards issued pursuant to the MPLX 2012 Plan.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Certain Relationships and Related Party Transactions
Our general partner is an affiliate of MPC. On March 1, 2017, we acquired certain pipeline, storage and terminal
assets from MPC for $1.5 billion in cash and a fixed number of common units and general partner units of
13.0 million and 0.3 million, respectively. The general partner units maintained MPC’s two percent general
partner economic interest. As of the acquisition date, the assets consisted of 174 miles of crude oil pipelines and
430 miles of refined products pipelines, nine butane and propane storage caverns located in Michigan with
approximately 1.8 million barrels of NGL storage capacity, 59 terminals for the receipt, storage, blending,
additization, handling and redelivery of refined petroleum products, along with one leased terminal and partial
ownership interest in two terminals. Collectively, the 62 terminals had a combined total shell capacity of
approximately 23.6 million barrels. The terminal facilities are located primarily in the Midwest, Gulf Coast and
Southeast regions of the United States. MPC waived two-thirds of the first quarter 2017 distributions on MPLX
LP common units issued in connection with this transaction. See Item 8. Financial Statements and
Supplementary Data—Note 4 for more information on this transaction.
On September 1, 2017, we acquired joint-interest ownerships in certain pipelines and storage facilities from MPC
for $420 million in cash and a fixed number of common units and general partner units of 18.5 million and
252
0.4 million, respectively. The general partner units maintained MPC’s two percent general partner economic
interest. The acquired ownership interests included a 35 percent ownership interest in Illinois Extension, a
40.7 percent ownership interest in LOOP, a 58.52 percent ownership interest in LOCAP, and a 24.51 percent
ownership interest in Explorer (collectively, the “Joint-Interest Acquisition”). As of the acquisition date, the
assets held by these entities include a 1,830-mile refined products pipeline, storage facilities, pump stations, and
a deepwater oil port, located offshore of Louisiana. The infrastructure serves primarily the Midwest and Gulf
Coast regions of the United States. MPC waived approximately two-thirds of the third quarter 2017 distributions
on MPLX LP common units issued in connection with this transaction. See Item 8. Financial Statements and
Supplementary Data—Note 4 for more information on this transaction.
On November 13, 2017, we entered into a Membership Interests Contribution Agreement (the “November 2017
Contribution Agreement”) with MPLX GP, MPLX Logistics, MPLX Holdings and MPC Investment, related to
the acquisition of ownership interests in MPLX Fuels Distribution LLC and MPLX Refining Logistics LLC,
entities indirectly held by MPC. Pursuant to the November Contribution Agreement, the consideration consisted
of $4.1 billion in cash and a fixed number of MPLX LP common units and MPLX LP general partner units of
111.6 million and 2.3 million, respectively. The general partner units maintained MPC’s two percent general
partner interest in the Partnership. The acquisition closed on February 1, 2018. MPC waived the fourth quarter
2017 distributions on the MPLX LP common units issued in connection with this transaction.
On December 15, 2017, we entered into a Partnership Interests Restructuring Agreement with MPLX GP (the
“Partnership Interests Restructuring Agreement”), pursuant to which MPLX LP incentive distribution rights
(“IDRs”) held by MPLX GP would be eliminated and the two percent general partner interest in the Partnership
held by MPLX GP would be converted into a non-economic general partner interest in MPLX LP in exchange for
275 million MPLX LP common units. Pursuant to the Partnership Interests Restructuring Agreement, the third
amended and restated agreement of limited partnership would be amended to reflect the restructuring. The
acquisition closed on February 1, 2018. The fourth amended and restated agreement of limited partnership was
adopted on February 1, 2018. MPC agreed to cap fourth quarter 2017 distributions on the MPLX LP common
units issued in connection with this transaction at the amount that would have been payable with respect to
MPC’s economic general partner interests as they existed immediately prior to the closing of this transaction.
As of February 16, 2018, MPC owned 504,701,934 common units. Our general partner manages our operations
and activities through its officers and directors. In addition, Mr. Heminger, serves as an executive officer of our
general partner and MPC. Accordingly, we view transactions between us and MPC as related party transactions.
Distributions by the Partnership
Pursuant to our third amended and restated agreement of limited partnership, which was in effect during 2017,
we made cash distributions to our unitholders, including MPC as the direct and indirect holder of common units,
as well as a two percent general partner interest and all of our outstanding IDRs. As distributions exceeded the
minimum quarterly distribution and target distribution levels, the general partner was entitled to receive
increasing percentages of our distributions, up to 48 percent of our distributions above the highest target
distribution level, on the IDRs. In 2017, we paid MPC $212 million in cash distributions with respect to its
common units, and $286 million in cash distributions with respect to its two percent general partner interest and
the IDRs. As of February 1, 2018, the IDRs were eliminated and the economic general partner interest was
converted into a non-economic general partner interest. In addition, our agreement of limited partnership has
been amended and restated. The fourth amended and restated agreement of limited partnership, which was
adopted on February 1, 2018, provides for distributions of available cash, after payment of distributions on the
Preferred units, to common unitholders pro rata.
Reimbursements paid to MPC
Pursuant to our third amended and restated agreement of limited partnership, which was in effect during 2017,
we are required to reimburse our general partner and its affiliates, including MPC, for all costs and expenses that
253
our general partner and its affiliates, including MPC, incur on our behalf for managing and controlling our
business and operations. Except to the extent specified under the omnibus agreement (described below), our
general partner determines the amount of these expenses and such determinations are required to be made in
good faith in accordance with the terms of our third amended and restated agreement of limited partnership. In
2017, we reimbursed our general partner $4 million for costs and expenses incurred on our behalf. Our fourth
amended and restated agreement of limited partnership, which was adopted on February 1, 2018, contains similar
provisions regarding reimbursements.
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 Transportation, Terminal, and Storage Services Agreements with MPC” and
“Operating and Management Services Agreements with MPC” in Item 1 and Note 6—Related Party Agreements
and Transactions in the Notes to Consolidated Financial Statements, for information regarding material related
party activities with MPC.
Procedures for Review, Approval and Ratification of Related Person Transactions
The board of directors of our general partner has adopted a formal written related person transactions policy.
Under the policy, a “related person” includes any director, nominee for director, executive officer, or a known
beneficial holder of more than five percent of any class of the Partnership’s voting securities (other than MPC or
its affiliates) or any immediate family member of a director, nominee for director, executive officer or more than
five percent owner. This procedure applies to any transaction, arrangement or relationship and any series of
similar transactions, arrangements or relationships in which we are a participant and the amount involved
exceeds $120,000 and in which a related person has a direct or indirect material interest; provided that the
following transactions, arrangements or relationships will be deemed to have standing pre-approval of the board
of directors:
•
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 the Partnership or any of its subsidiaries, 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 approved
by the board of directors of our general partner prior to its consummation. If the related person transaction is
identified after it commences, it will be promptly submitted to the board of directors of our general partner or the
chairman for ratification, amendment or rescission. If the transaction has been completed, the board of directors
of our general partner 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 of directors of our general
partner or the chairman will consider all relevant facts and circumstances, including but not limited to:
•
•
the benefits to the Partnership, including the business justification;
the impact on a director’s independence in the event the related person is a director or an immediate
family member of a director;
254
•
•
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 of directors
of our general partner.
Director Independence
The information appearing under Item 10. Directors, Executive Officers and Corporate Governance—Director
Independence, is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services
Aggregate fees for professional services rendered for the Partnership by PricewaterhouseCoopers LLP for the
years ended December 31, 2017, and December 31, 2016, are presented in the following table:
Fees(1)
(In thousands)
Audit
Audit-Related
Tax
All Other
Total
2017
2016(2)
$3,806
469
1,081
2
$3,915
—
1,329
4
$5,358
$5,248
(1)
(2)
The Partnership’s Pre-Approval of Audit, Audit-Related, Tax and Permissible Non-Audit Services Policy is
summarized in this Annual Report on Form 10-K. See “Audit Committee Policy for Pre-Approval of Audit,
Audit-Related, Tax and Permissible Non-Audit Services.” In 2017 and 2016, all of these services were
pre-approved by the Audit Committee of our general partner in accordance with its pre-approval policy. Our
Audit Committee did not utilize the Policy’s de minimis exception in 2017 or 2016.
These amounts were previously reported in millions as follows: Audit, $4 million; Audit Related,
$0 million; Tax, $1 million; and All Other, $0 million.
The Audit fees for the years ended December 31, 2017, and December 31, 2016, 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.
The Audit-Related fees for the year ended December 31, 2017, were for professional services rendered in relation
to updating accounting processes and procedures in order to comply with new accounting pronouncements.
The Tax fees for the years ended December 31, 2017, and December 31, 2016, 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, 2017, and December 31, 2016, were for subscriptions to online
accounting resources provided by PricewaterhouseCoopers LLP.
The Audit Committee of MPLX GP LLC has considered whether PricewaterhouseCoopers LLP is independent
for purposes of providing external audit services to the Partnership and has determined that it is.
255
Audit Committee Policy for Pre-Approval of Audit, Audit-Related, Tax and Permissible Non-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.
256
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.
257
Exhibits:
Exhibit
Number
2.1
2.2
2.3 †
2.4
2.5
2.6
2.7
2.8
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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
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
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
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
258
Exhibit
Number
2.9
3.1
3.2
3.3
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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)
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
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
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
259
Exhibit
Number
4.9
4.10
4.11
4.12
4.13
4.14
10.1*
10.2
10.3
10.4
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Seventh Supplemental Indenture, dated as
of February 10, 2017, between the Issuer
and The Bank of New York Mellon Trust
Company, N.A., as Trustee
Eighth Supplemental Indenture, dated as of
February 8, 2018, between the Issuer and
The Bank of New York Mellon Trust
Company, N.A., as Trustee
Ninth Supplemental Indenture, dated as of
February 8, 2018, between the Issuer and
The Bank of New York Mellon Trust
Company, N.A., as Trustee
Tenth Supplemental Indenture, dated as of
February 8, 2018, between the Issuer and
The Bank of New York Mellon Trust
Company, N.A., as Trustee
Eleventh Supplemental Indenture, dated as
of February 8, 2018, between the Issuer
and The Bank of New York Mellon Trust
Company, N.A., as Trustee
Twelfth Supplemental Indenture, dated as
of February 8, 2018, between the Issuer
and The Bank of New York Mellon Trust
Company, N.A., as Trustee
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
4.2
2/10/2017
001-35714
8-K
4.1
2/8/2018
001-35714
8-K
4.2
2/8/2018
001-35714
8-K
4.3
2/8/2018
001-35714
8-K
4.4
2/8/2018
001-35714
8-K
4.5
2/8/2018
001-35714
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
260
Exhibit
Number
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Employee Services Agreement, dated
effective as of October 1, 2012, by and
among 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)
Transportation Services Agreement (Patoka
to Lima Crude System), dated as of
October 31, 2012, between Marathon
Petroleum Company LP and Marathon Pipe
Line LLC
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
8-K 10.4
11/6/2012
001-35714
261
Exhibit
Number
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23*
10.24*
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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
MPC Non-Employee Director Phantom
Unit Award Policy
MPLX GP LLC Amended and Restated
Non-Management Director Compensation
Policy and Equity Award Terms
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
10-K 10.26
3/25/2013
001-35714
10-K 10.30
2/24/2017
001-35714
262
Exhibit
Number
10.25
10.26
10.27
10.28
10.29
10.30*
10.31*
10.32*
10.33
10.34*
10.35+
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
First Amendment to Amended and
Restated Operating Agreement, dated as of
January 1, 2015, between Marathon
Petroleum Company LP and Marathon Pipe
Line LLC
Operating Agreement, dated as of
January 1, 2015, between Hardin Street
Transportation LLC and Marathon Pipe
Line LLC
Transportation Services Agreement
(Cornerstone Pipeline System and Utica
Build-Out Projects), effective as of
June 11, 2015, by and between Marathon
Petroleum Company LP and Marathon Pipe
Line LLC
First Amendment to Storage Services
Agreement, dated as of September 17,
2015, by and between Marathon Petroleum
Company LP and Marathon Pipe Line LLC
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
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
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
8-K 10.1
9/11/2007
001-31239
10-K 10.48
2/26/2016
001-35714
263
Exhibit
Number
10.36
10.37
10.38
10.39
10.40*
10.41*
10.42*
10.43*
10.44
10.45
10.46
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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
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
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
8-K 10.1
9/6/2016
001-35714
10-Q 10.2 10/31/2016
001-35714
264
Exhibit
Number
10.47
10.48
10.49
10.50
10.51
10.52
10.53
10.54
10.55
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
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
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
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
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
265
Exhibit
Number
10.56
10.57
10.58*
10.59
10.60*
10.61*
10.62
10.63
10.64
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Third Amended and Restated Terminal
Services Agreement, dated March 1, 2017,
between MPLX Terminals LLC and
Marathon Petroleum Company LP
Third Amended and Restated Employee
Services Agreement, effective
December 21, 2015, between MPLX
Terminals LLC and Marathon Petroleum
Logistics Services LLC
Form of MPLX LP Phantom Unit Award
Agreement—Officer, Cliff Vesting
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.
Amended Restricted Stock Award
Agreement
MPLX LP Executive Change in Control
Severance Benefits Plan
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
8-K 10.6
3/2/2017
001-35714
8-K 10.7
3/2/2017
001-35714
10-Q 10.1
8/3/2017
001-35714
8-K 10.1
7/27/2017
001-35714
10-Q 10.2 10/30/2017
001-35714
10-Q 10.3 10/30/2017
001-35714
8-K 10.1
11/7/2017
001-35714
8-K 10.2
11/7/2017
001-35714
8-K 10.1 12/19/2017
001-35714
266
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Exhibit
Number
10.65
12.1
14.1
21.1
23.1
24.1
31.1
31.2
32.1
32.2
8-K 10.1
1/4/2018
001-35714
10-K 14.1
2/24/2017
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
Computation of Ratio of Earnings to Fixed
Charges
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
101.INS XBRL Instance Document
101.SCH XBRL Taxonomy Extension Schema
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
267
X
X
X
X
X
X
X
X
X
X
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.
268
Item 16. Form 10-K Summary
Not applicable.
269
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, 2018
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)
270
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on February 28, 2018 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
*
David A. Daberko
*
Timothy T. Griffith
*
Christopher A. Helms
*
Garry L. Peiffer
*
Dan D. Sandman
*
Frank M. Semple
*
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)
* 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, 2018
271
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
Lisa Wilson, Director, Investor Relations
(419) 421-2071
Doug Wendt, Manager, Investor Relations
(419) 421-2423
Denice Myers, Manager, Investor Relations
(419) 421-2965
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
Computershare
Shareholder 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 2017 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
(800) 232-0011
COMPARISON OF CUMULATIVE TOTAL RETURN
Among MPLX LP, the S&P 500 Index, the Alerian MLP Index and Peer Group Index
MPLX
Standard & Poor’s 500 Index
Peer Group Index
Alerian MLP Index
$300
$250
$200
$150
$100
$50
$0
12/12
12/13
12/14
12/15
12/16
12/17
This graph compares the cumulative total return,
assuming the reinvestment of distributions, of
a $100 investment in our common units from
Dec. 31, 2012, to Dec. 31, 2017, compared to the
cumulative total return of an investment in the
S&P 500 Index, the Alerian MLP Index and an index
of peer companies (selected by us) for the same
period. Our peer group consists of the following
companies: Andeavor Logistics LP (Tesoro Logistics
LP prior to Aug. 1, 2017); Buckeye Partners LP;
Enbridge Energy Partners LP; Energy Transfer
Partners LP; Enterprise Products Partners LP;
Magellan Midstream Partners LP; Phillips 66 Part-
ners LP; Plains All American Pipeline LP; Valero
Energy Partners LP; Western Gas Partners LP; and
Williams Partners LP.
The performance graph (left) is not “soliciting
material” and will not be deemed to be fi led with the
Securities and Exchange Commission (SEC) or incor-
porated by reference into any of MPLX’s fi lings with
the SEC, except to the extent that we specifi cally
incorporate it by reference into any such fi lings.
58281.indd 13
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®
MPLX LP
200 EAST HARDIN ST.
FINDLAY, OH 45840
Non-GAAP Financial Measures
Adjusted earnings before interest, taxes, depreciation and amortization (EBITDA), distributable cash flow (DCF) and distribution coverage ratio
are non-GAAP financial measures provided in this annual report. Adjusted EBITDA and DCF reconciliations to the nearest GAAP financial measure
are included on Page 9 and in the MPLX Annual Report on Form 10-K for the year ended Dec. 31, 2017, 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. Adjusted EBITDA, DCF and distribution
coverage ratio are not defined by GAAP and should not be considered in isolation of or as an alternative to net income attributable to MPLX, net
cash provided by (used in) operating activities or other financial measures prepared in accordance with GAAP. Certain EBITDA forecasts were
determined on an EBITDA-only basis. Accordingly, information related to the elements of net income, including tax and interest, are not available
and, therefore, reconciliations of these non-GAAP financial measures to the nearest GAAP financial measures have not been provided.
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, 2017, 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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