a clear vision
®
2016
ANNUAL REPORT
54418.indd 1
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$1,140
2016
for future growth
$399
2015
Distributable cash fl ow in millions attributable to MPLX.
Non-GAAP measure including MarkWest from Oct. 1, 2016. See reconciliation on Page 13.
MarkWest’s gas processing
and fractionation complex in
Cadiz, Ohio
54418.indd 2
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OPERATIONAL OVERVIEW
MPLX is a diversifi ed, growth-oriented master limit-
ed partnership formed in 2012 by Marathon Petro-
leum Corporation to own, operate, develop and ac-
quire midstream energy infrastructure assets. We are
engaged in the gathering, processing and transpor-
tation of natural gas; the gathering, transportation,
fractionation, storage and marketing of NGLs; and the
transportation and storage of crude oil and refi ned
petroleum products. Headquartered in Findlay, Ohio,
MPLX’s assets consist of a network of common car-
rier crude oil and products pipeline assets located
in the Midwest and Gulf Coast regions of the United
States; an inland marine business; a butane storage
cavern located in West Virginia with approximately
one million barrels of storage capacity; crude oil and
product storage facilities (tank farms) with
approximately 4.5 million barrels of available
storage capacity; a barge dock facility with approx-
imately 78,000 barrels per day of crude oil and
product throughput capacity; and gathering and
processing assets that include more than 5,600
miles of gas gathering and NGL pipelines,
54 gas processing plants, 14 NGL fractionation
facilities and two condensate stabilization facilities.
54418.indd 3
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Table of Contents
Operational Overview
Inside cover
Chairman and CEO Letter
Logistics and Storage
Gathering and Processing
Growth
Board of Directors
Company Offi cers
Financial and Operational Highlights
1
5
7
9
10
11
12
Crude Oil and Product Pipelines
Glossary of Terms
Barge Dock
Tank Farm
Butane Cavern
MarkWest Complex
Marine Repair Terminal
Shaded areas represent
hydrocarbon-producing shale plays
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
54418.indd 4
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MPLX I 2016 ANNUAL REPORT I 1
FROM THE CHAIRMAN AND CEO
Fellow unitholders,
Over the course of 2016, we executed on our plan to deliver strong operational and fi nancial results.
We achieved our targeted distribution growth rate and reduced our fi nancial leverage while maintaining
strong distribution coverage. We accomplished this by optimizing capital investments through organic
growth projects and acquisitions from our sponsor Marathon Petroleum Corporation (MPC), managing
costs, and continuing our sharp focus on customer service. We are excited about our future growth
profi le and the bold course of strategic actions over the next 12 to 18 months that we expect will
approximately double the size of the partnership and lower our cost of capital.
2016 Success by the Numbers
In millions, except per unit and ratio data
Net income attributable to MPLX (b)
Adjusted EBITDA attributable to MPLX (c)
Net cash provided by operating activities
Distributable cash fl ow (DCF) (c)
Distribution per common unit (d)
Distribution coverage ratio (e)
Growth capital expenditures (f)
2016
2015 (a)
$ 233
$ 156
1,419
1,288
1,140
2.05
1.23x
1,201
498
340
399
1.82
1.27x
271
(a) MarkWest operations excluded from results and measures provided prior to the Dec. 4, 2015, merger.
(b) 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.
(c) Non-GAAP measure calculated before the distribution to preferred units and excluding impairment
charges. See description in Non-GAAP fi nancial measures on back cover.
(d) Distributions declared by the board of directors of our general partner.
(e) Non-GAAP measure. See description in Non-GAAP fi nancial measures on back cover.
(f) Includes capital expenditures for inland marine business (“Predecessor”), acquired on March 31, 2016.
Excludes capital expenditures for MarkWest acquisition. See description on Page 14.
MPLX signifi cantly transformed its
fi nancial profi le in 2016, our fi rst full
year with MarkWest Energy Partners.
Our adjusted earnings before interest,
taxes, depreciation and amortization
(EBITDA) nearly tripled over the prior
year, to more than $1.4 billion, from
$498 million in 2015. Net income rose
49 percent over the full-year 2015 to
$233 million for 2016. Additionally,
full-year distributable cash fl ow
exceeded $1.1 billion. We also
acquired MPC’s marine business and
invested $1.2 billion in an attractive
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MPLX I 2016 ANNUAL REPORT I 2
FROM THE CHAIRMAN AND CEO
set of organic projects that will continue to grow distributable cash fl ow and position MPLX as an
industry leader.
Since our IPO in 2012, we have achieved 16 consecutive quarters of growing distributions for our
unitholders. In 2016, we delivered a distribution growth rate of 13 percent, leading the industry
among large-cap, diversifi ed master limited partnerships (MLPs).
We remain committed to maintaining a strong balance sheet and an investment-grade credit profi le.
industry-leading growth
54418.indd 6
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MPLX I 2016 ANNUAL REPORT I 3
The partnership ended the year in solid fi nancial position with $2.7 billion of liquidity and a
debt–to-pro forma adjusted EBITDA leverage ratio of 3.4 times. We also reported a robust full-year
distribution coverage ratio of 1.23 times.
On Jan. 3, 2017, we set forth a new course of strategic actions intended to lower our cost of capital
and provide increased visibility to our distribution growth. The partnership expects to acquire from
MPC assets with approximately $1.4 billion in EBITDA in 2017. We expect to fi nance these proposed
acquisitions through approximately equal portions of debt and equity, with the equity fi nancing to be
Page 2: MarkWest’s
Hidalgo complex in
Orla, Texas
Above: An employee
funded through common units issued to our sponsor, MPC, limiting our reliance on the public-equity
market for fi nancing.
As part of the strategic actions, an acquisition representing approximately $250 million of annual
at MarkWest’s
EBITDA closed in the fi rst quarter of 2017.
Sherwood facility in
West Virginia, and the
Keystone complex
in Evans City,
Upon completion of the acquisitions, our size and scale would be among the largest in the industry
with nearly equal contributions from our Logistics and Storage and Gathering and Processing segments
Pennsylvania
and a pro forma expected EBITDA profi le double what it is today.
Additionally, in conjunction with the acquisitions from our sponsor, we expect to exchange new MPLX
common units for MPC’s economic interest in the general partner, including incentive distribution rights.
competitively positioned
54418.indd 7
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MPLX I 2016 ANNUAL REPORT I 4
FROM THE CHAIRMAN AND CEO
These actions are expected to lower our cost of capital and position us for attractive growth in the long
term. All of these transactions are subject to requisite approvals, market and other conditions, including
tax and regulatory clearances.
With an investment-grade credit profi le, an attractive portfolio of organic growth projects and potential
for an improved cost of capital, we expect to deliver an attractive distribution growth rate, maintain a
strong distribution coverage ratio and remain competitively positioned to generate long-term value for
our unitholders.
Sincerely,
Gary R. Heminger
Chairman and Chief Executive Offi cer
Above left: MarkWest’s
Majorsville complex near
Dallas, West Virginia
Above right: MarkWest’s
Keystone complex in
Evans City,
Pennsylvania
Page 5: The 50-mile
Cornerstone Pipeline
was completed
in the fall of 2016
long-term value
54418.indd 8
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LOGISTICS AND STORAGE
MPLX I 2016 ANNUAL REPORT I 5
In 2016, MPLX’s Logistics and Storage segment, which generates stable cash fl ows with its fee-based
revenues and minimal direct commodity exposure, successfully commenced operations of the
Cornerstone Pipeline, to transport liquids production from the Marcellus and Utica shales of Eastern
Ohio to a tank farm in East Sparta, Ohio, and on to MPC’s refi nery in Canton, Ohio, providing improved
industry connectivity to the region.
Cornerstone is the fi rst step of MPLX’s long-term pipeline investment program, an industry solution
to transport condensate, natural gasoline, butane and diluent out of the Northeast.
industry innovator
54418.indd 9
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MPLX I 2016 ANNUAL REPORT I 6
LOGISTICS AND STORAGE
As part of that long-term plan, we also completed the construction of the Hopedale connection to the
Cornerstone Pipeline to transport natural gasoline from the Marcellus and Utica shales to Midwest refi ners,
including MPC. MPLX is now in the process of expanding the capacity of existing pipelines, as well
as constructing additional new pipelines as part of a larger build-out of the Utica Shale infrastructure,
which is targeted for completion in mid-2017. With this mix of new and existing pipelines, MPLX is seizing
a unique opportunity to support producer customer growth by connecting natural gas liquids (NGLs) to
downstream markets in the Midwest and Canada through its extensive and growing distribution network.
A marine tow along
the Ohio River near
Cincinnati, Ohio
MarkWest’s Ohio
Condensate facility in
Additionally, in 2016, MPLX acquired MPC’s inland marine business for $600 million, by issuing
new units to MPC. As of Dec. 31, 2016, the inland marine business comprised 18 towboats,
204 barges and 18 leased barges. The business transports light products, heavy oils, crude oil,
renewable fuels, chemicals and feedstocks in the Midwest and U.S. Gulf Coast regions, and accounts
Cadiz, Ohio
for nearly 60 percent of the total volume MPC ships by inland marine vessels. The addition of these
assets, under a fee-for-capacity contract with MPC, adds approximately $120 million of annual
EBITDA to the partnership.
MPLX also is expanding its network of butane caverns and tank farms to support MPC.
extensive distribution network
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GATHERING AND PROCESSING
MPLX I 2016 ANNUAL REPORT I 7
MPLX’s Gathering and Processing segment delivered strong volume growth in 2016 and continues to
provide exceptional organic growth opportunities to the partnership.
The addition of the MarkWest Gathering and Processing segment transformed the profi le of our
partnership to one of the largest natural gas processors in the United States and the largest processor
and fractionator in the prolifi c Marcellus and Utica shales. Over the course of 2016, the partnership
reported year-over-year increases of 11 percent in gathering, 13 percent in natural gas processing and
25 percent in natural gas liquids fractionation volumes.
exceptional growth opportunities
MarkWest’s
The partnership continues to pursue and execute exceptional growth opportunities, supporting a
Houston complex in
Washington County,
Pennsylvania
diverse set of over 160 producer customers in some of the nation’s most prolifi c shale plays.
Included among its plans for continued growth, the partnership has secured new agreements with
two of its largest producer customers in the Northeast region, to support the continued long-term
development of substantial rich-gas acreage in the Marcellus and Utica shales.
Among the new plans are extended and amended agreements with Range Resources Corporation
for which MPLX expects to construct an additional processing facility at its Houston complex in
Pennsylvania in early 2018, and to commission the Harmon Creek complex, in Pennsylvania, by
mid- to late 2018.
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MPLX I 2016 ANNUAL REPORT I 8
GATHERING AND PROCESSING
Additionally, the partnership announced that its wholly owned subsidiary, MarkWest Energy Partners, L.P.,
and Antero Midstream Partners LP have formed a strategic joint venture to support the development of
Antero Resources Corporation’s extensive Marcellus Shale acreage in the prolifi c rich-gas corridor of
West Virginia. The joint venture is expected to commence new dedicated facilities beginning in 2017
and continuing into the future.
Ongoing joint venture development includes three new gas processing facilities, totaling 600 million
cubic feet per day of incremental capacity, as well as future development by the joint venture of up to
Gas processing
another eight processing facilities, which would be located at both the Sherwood complex and at a new
facilities of MarkWest’s
Sherwood complex
location in West Virginia. Additionally, the joint venture has invested in 20,000 barrels per day of existing
in West Virginia
fractionation capacity at the Hopedale complex in Ohio, and has an option to invest in additional
fractionation infrastructure to support future liquids production from its processing facilities.
MPLX is also growing its diversifi ed footprint across established resource plays in Texas and Oklahoma.
Specifi cally in the Delaware Basin of West Texas, the partnership completed the Hidalgo I plant in
May 2016 and experienced strong volume increases from ongoing producer activity in the area,
quickly ramping up to near-full utilization of the facility. In addition to West Texas, the partnership is
actively growing its position in the STACK (Sooner Trend of the Anadarko Basin Canadian and Kingfi sher
counties) resource of Oklahoma’s Cana-Woodford Shale.
54418.indd 12
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GROWTH
MPLX I 2016 ANNUAL REPORT I 9
MPLX looks forward to signifi cant growth in 2017 and beyond as we enter a period of expansion driven
by a recovery of commodity prices, increasing rig counts and growing customer exploration and
development activity.
Through cost management, optimized capital investments and a continued relentless focus on customer
service, we anticipate continued increases in gathered, processed and fractionated volumes in 2017.
The forecast for organic growth capital expenditures in 2017 is $1.4 billion to $1.7 billion and maintenance
capital is forecast at approximately $100 million. Approximately $1 billion to $1.3 billion of these
growth investments are expected to support producer customers in the Gathering and Processing
Welding Cornerstone
segment. During 2017, the partnership expects to complete 400 million cubic feet per day of additional
Pipeline near
Cadiz, Ohio
natural gas processing capacity and 120,000 barrels per day of additional fractionation capacity,
primarily in the Marcellus Shale.
The remaining $400 million is planned for the Logistics and Storage segment for the development of
various crude oil and refi ned petroleum products infrastructure projects, including a build-out of Utica
Shale infrastructure in connection with the recently completed Cornerstone Pipeline, a butane cavern
in Robinson, Illinois, and a tank farm expansion in Texas City, Texas.
The partnership expects a distribution growth rate of 12 to 15 percent for 2017 and a double-digit rate for
2018. Looking forward, we also are energized by the transformative opportunity inherent in the strategic
actions we announced on Jan. 3, 2017. The acquisition of assets generating approximately $1.4 billion
in EBITDA, and the exchange of new MPLX common units for MPC’s economic interests in the general
partner will contribute to a reduced cost of capital and enhance the partnership’s ability to deliver an
attractive distribution growth rate for the long term.
With a simplifi ed structure, full alignment with our sponsor MPC, and enhanced visibility to an attractive
distribution growth rate, MPLX remains confi dent about its compelling long-term value proposition
for investors.
54418.indd 13
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MPLX I 2016 ANNUAL REPORT I 10
BOARD OF DIRECTORS
Standing
Garry L. Peiffer
Retired President,
MPLX GP LLC, and
Executive Vice President,
Corporate Planning
and Investor and
Government Relations,
MPC. Mr. Peiffer joined
MPC’s predecessor,
Marathon Oil Company,
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.
Christopher A. Helms
President and
CEO, U.S. Shale
Management
Company. Mr. Helms
previously served in
various leadership
positions at NiSource
Inc. and NiSource Gas
Transmission and
Storage. Mr. Helms
was responsible
for leading the
company’s interstate
gas transmission and
storage business.
John P. Surma
Retired Chairman and
CEO, United States
Steel Corporation.
Prior to USS, Mr.
Surma held various
leadership positions
at Marathon Oil
Company, including
senior vice president
of Finance and
Accounting, president
of Speedway
SuperAmerica LLC,
and president of
Marathon Ashland
Petroleum LLC.
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.
Pamela K.M. Beall
Executive Vice
President and Chief
Financial Offi cer,
MPLX GP LLC. Ms.
Beall began her
career with Marathon
Oil Company and
transferred to USX
Corporation. After
rejoining Marathon in
2002, she held various
leadership positions,
most recently
executive vice
president, Corporate
Planning and Strategy,
MPLX GP LLC.
Frank M. Semple
Retired Chairman,
President and CEO,
MarkWest Energy
Partners, L.P.
Mr. Semple joined
MarkWest Energy
Partners, L.P. in
2003 as president
and CEO, and was
elected chairman in
2008. He completed
a 22-year career
with The Williams
Companies and WilTel
Communications prior
to MarkWest.
Timothy T. Griffi th
Senior Vice President
and Chief Financial
Offi cer, MPC. Prior to
MPC, Mr. Griffi th was
vice president and
treasurer of Smurfi t-
Stone Container
Corp., vice president
and treasurer of
Cooper-Standard
Automotive and
assistant treasurer
of Lear Corp. He also
held positions at
Comerica Inc. and
Citicorp Securities.
Seated
David A. Daberko
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, MPLX GP LLC and
Executive Vice 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. Prior
to joining MPC in 2011, Mr.
Templin was managing partner
of PricewaterhouseCoopers
LLP’s audit practice in Georgia,
Alabama and Tennessee.
Gary R. Heminger
Chairman and CEO, MPLX GP
LLC, and Chairman, President
and CEO, MPC. Mr. Heminger
joined MPC’s predecessor,
Marathon Oil Company, 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 Corporation in 2011,
and chairman in 2016.
Dan D. Sandman
Adjunct Professor, The Ohio State
University Moritz College of Law.
Mr. Sandman began his career at
Marathon Oil Company in 1973
and served in various positions
as an attorney before being
appointed general counsel and
secretary in 1986. He retired from
United States Steel Corporation
in 2007 as vice chairman of
the board and chief legal and
administrative offi cer.
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 various
capacities at Buckeye and
its general partner, including
as president, chief operating
offi cer, director and vice
chairman.
54418.indd 14
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COMPANY OFFICERS
MPLX I 2016 ANNUAL REPORT I 11
Standing
Seated
Paula L. Rosson
Senior Vice President and Chief Accounting Offi cer
Molly R. Benson
Vice President, Corporate Secretary and Chief Compliance Offi cer
John S. Swearingen
Vice President, Crude Oil and Refi ned Products Pipelines
Gregory S. Floerke
Executive Vice President and Chief Operating Offi cer, MarkWest Operations
C. Corwin Bromley
Executive Vice President and General Counsel (Chief Legal Offi cer)
Timothy J. Aydt
Vice President, Operations (Marathon Pipeline Assets)
Frank A. Quintana
Vice President, Tax
Randy S. Nickerson
Executive Vice President and Chief Commercial Offi cer,
MarkWest Assets
Donald C. Templin
President
Gary R. Heminger
Chairman and Chief Executive Offi cer
Pamela K.M. Beall
Executive Vice President and Chief Financial Offi cer
54418.indd 15
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MPLX I 2016 ANNUAL REPORT I 12
FINANCIAL AND OPERATIONAL HIGHLIGHTS
(In millions, except per-unit, throughput and average tariff data)
2016
2015(5)
2014(5)
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)(2)
Distributable cash fl ow (DCF)(1)(2)
$ 2,590
$ 961
$ 793
233
1
1,419
1,140
156
99
498
399
121
115
166
137
Net income per limited partner unit:
Common units – basic
Common units – diluted
Subordinated units – basic and diluted
Weighted average limited partner units outstanding:
Common units – basic
Common units – diluted
Subordinated units – basic and diluted
Cash and cash equivalents
Total assets
Total debt
Total equity
Capital expenditures:
Maintenance
Growth (3)
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 (4)
$ 0
$ 1.23
$ 1.55
1.55
1.50
37
37
37
$ 27
1,544
644
784
30
124
1,041
878
1,919
0.64
0.61
0.63
0
0
331
338
0
1.22
0.11
79
80
18
$ 234
$ 43
16,646
4,423
10,319
16,104
5,264
9,667
68
1,118
1,088
908
1,996
0.67
0.69
0.68
5,761
335
3,275
33
282
1,061
914
1,975
0.66
0.65
0.65
5,468
307
3,075
(1)
Financial measure not in accordance with U.S. generally accepted accounting principles (GAAP). See Results of Operations in the
Management’s Discussion and Analysis of Financial Conditions and Results of Operations section of the Form 10-K document for
reconciliation to most directly comparable measures as reported in accordance with GAAP.
(2) Results for 2015 include MarkWest pre-merger EBITDA and undistributed distributable cash fl ow related to MarkWest’s EBITDA and
distributable cash fl ow from Oct. 1, 2015, to Dec. 3, 2015.
See Reconciliation Data on Page 14.
(3)
(4) Throughputs for 2016 are for the full year and for 2015 are for the period Dec. 4, 2015, through Dec. 31, 2015. All throughputs are weighted
averages for days in operation.
(5) Financial information has been retrospectively adjusted to include the results of the inland marine business prior to the March 31, 2016,
acquisition from MPC, since MPLX and this business are under common control. The net income of the Predecessor is excluded from
net income attributable to MPLX LP.
54418.indd 16
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MPLX I 2016 ANNUAL REPORT I 13
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
(Benefi t) provision for income taxes
Amortization of deferred fi nancing costs
Non-cash equity-based compensation
Impairment expense
Net interest and other fi nancial costs
Loss (income) from equity investments
Distributions from unconsolidated subsidiaries
Unrealized derivative losses (gains) (a)
Acquisitions costs
Adjusted EBITDA
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to Predecessor (b)
MarkWest’s pre-merger EBITDA (c)
Adjusted EBITDA attributable to MPLX LP
Deferred revenue impacts
Net interest and other fi nancial costs
Maintenance capital expenditures
Other
DCF pre-MarkWest undistributed
MarkWest undistributed DCF (c)
DCF
Preferred unit distributions
DCF attributable to GP and LP unitholders
2016
$ 258
546
(12)
46
10
130
215
74
150
36
(1)
1,452
(3)
(30)
–
1,419
8
(215)
(68)
(4)
1,140
–
1,140
(41)
$ 1,099
2015
$ 249
116
1
5
4
–
43
(3)
15
(4)
30
456
(1)
(119)
162
498
6
(36)
(31)
(6)
431
(32)
399
–
$ 399
(a) The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative con-
tract is outstanding, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or
is settled, we reverse the previously recorded unrealized gain or loss and record the realized gain or loss of the contract.
(b) The adjusted EBITDA adjustments related to the Predecessor are excluded from adjusted EBITDA attributable to MPLX LP and DCF prior to
the March 31, 2016, acquisition.
(c) MarkWest pre-merger EBITDA and undistributed DCF relates to MarkWest’s EBITDA and DCF from Oct. 1, 2015, through Dec. 3, 2015.
Reconciliation of adjusted EBITDA attributable to MPLX LP, and DCF attributable to GP and LP unitholders
from net cash provided by operating activities (unaudited)
Year Ended Dec. 31
(In millions)
Net cash provided by operating activities
Changes in working capital items
All other, net
Non-cash equity-based compensation
Net gain on disposal of assets
Current income taxes
Net interest and other fi nancial costs
Asset retirement expenditures
Unrealized derivative losses (gains) (a)
Acquisition costs
Other
Adjusted EBITDA
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to Predecessor (b)
MarkWest’s pre-merger EBITDA (c)
Adjusted EBITDA attributable to MPLX LP
Deferred revenue impacts
Net interest and other fi nancial costs
Maintenance capital expenditures
Other
DCF pre-MarkWest undistributed
MarkWest’s undistributed DCF (c)
DCF
Preferred unit distributions
DCF attributable to GP and LP unitholders
2016
$ 1,288
(89)
(20)
10
1
5
215
5
36
(1)
2
1,452
(3)
(30)
–
1,419
8
(215)
(68)
(4)
1,140
–
1,140
(41)
$ 1,099
2015
$ 340
54
(12)
4
–
–
43
1
(4)
30
–
456
(1)
(119)
162
498
6
(36)
(31)
(6)
431
(32)
399
–
$ 399
(a) The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative
contract is outstanding, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures
or is settled, we reverse the previously recorded unrealized gain or loss and record the realized gain or loss of the contract.
(b) The adjusted EBITDA adjustments related to the Predecessor are excluded from adjusted EBITDA attributable to MPLX LP and DCF prior to the
March 31, 2016, acquisition.
(c) MarkWest pre-merger EBITDA and undistributed DCF relates to MarkWest’s EBITDA and DCF from Oct. 1, 2015, through Dec. 3, 2015.
Reconciliation Data continued on next page.
54418.indd 17
3/3/17 1:20 PM
MPLX I 2016 ANNUAL REPORT I 14
RECONCILIATION DATA
Reconciliation of Capital Expenditures (unaudited)
Year Ended Dec. 31
(In millions)
Capital Expenditures (a):
Maintenance
Growth
Total capital expenditures
Less:
(Decrease) increase in capital accruals
Asset retirement expenditures
Additions to property, plant and equipment
Capital expenditures of unconsolidated subsidiaries (b)
Total gross capital expenditures
Less:
Joint venture partner contributions
Total capital expenditures, net
Less: Maintenance capital
Total growth capital expenditures
Acquisition, net of cash acquired
Total growth capital and acquisition
2016
$ 68
1,118
1,186
(25)
5
1,206
131
1,337
64
1,273
72
1,201
–
2015
$ 33
282
315
26
1
288
24
312
8
304
33
271
1,218
$ 1,201
$ 1,489
(a) Includes capital expenditures of the Predecessor for all periods presented.
(b) Capital expenditures includes amounts related to unconsolidated, partnership operated subsidiaries.
54418.indd 18
3/3/17 1:20 PM
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, 2016
‘ 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 or a
smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting
company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer È
Non-accelerated filer ‘
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, 2016 was approximately $8.4 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 357,257,661 common units, 3,990,878 Class B units and 7,372,419 general partner units outstanding at
February 13, 2017.
‘
Accelerated filer
Smaller reporting company ‘
DOCUMENTS INCORPORATED BY REFERENCE:
None
MPLX LP
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”), MPLX Pipe Line Holdings
LLC (“Pipe Line Holdings”), Marathon Pipe Line LLC (“MPL”), Ohio River Pipe Line LLC (“ORPL”) and
Hardin Street Marine LLC (“HSM”). We have partial ownership interests in a number of joint venture legal
entities, including MarkWest Pioneer, L.L.C. (“MarkWest Pioneer”), 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”) and MarkWest EMG Jefferson
Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”). References to “MPC” refer collectively to Marathon
Petroleum Corporation and its subsidiaries, other than the Partnership. References to “Predecessor” refer
collectively to HSM’s related assets, liabilities and results of operations.
Table of Contents
PART I
Business
Item 1.
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Item 3.
Item 4. Mine Safety Disclosures
Properties
Legal Proceedings
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
Selected Financial Data
Item 6.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Item 8.
Item 9.
Item 9A. Controls and Procedures
Item 9B. Other Information
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accountant Fees and Services
PART IV
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
SIGNATURES
Page
4
45
75
76
84
86
87
90
94
132
137
204
204
204
205
217
247
251
255
257
267
268
The abbreviations, acronyms and industry technology used in this report are defined as follows.
Glossary of Terms
ARO
ASC
ATM Program
Bbl
bcf/d
Btu
Condensate
DCF (a non-GAAP financial measure)
DOT
Dth/d
EBITDA (a non-GAAP financial measure)
EIA
EPA
ERCOT
FASB
FERC
GAAP
Gal
Gal/d
IDR
Initial Offering
IRS
LIBOR
mbbls
mbpd
mcf
MMBtu
mmcf/d
Net operating margin (a non-GAAP
financial measure)
NGL
NYSE
OTC
Realized derivative gain/loss
PADD
PHMSA
PPI
SEC
SMR
Unrealized derivative gain/loss
USCG
VIE
WTI
Asset retirement obligation
Accounting Standards Codification
A continuous offering, or at-the-market program, by which the
Partnership may offer up to an aggregate of $1.2 billion of common
units, in amounts, at prices and on terms to be determined by market
conditions and other factors at the time of any offerings, as defined
by the prospectus supplement filed with the SEC on August 4, 2016
Barrels
Billion cubic feet per day
One British thermal unit, an energy measurement
A natural gas liquid with a low vapor pressure mainly composed of
propane, butane, pentane and heavier hydrocarbon fractions
Distributable Cash Flow
United States Department of Transportation
Dekatherms per day
Earnings Before Interest, Taxes, Depreciation and Amortization
United States Energy Information Administration
United States Environmental Protection Agency
Electric Reliability Council of Texas
Financial Accounting Standards Board
Federal Energy Regulatory Commission
Accounting principles generally accepted in the United States of
America
Gallon
Gallons per day
Incentive distribution rights
Initial public offering on October 12, 2012
Internal Revenue Service
London Interbank Offered Rate
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 revenue, less segment purchased product costs, less realized
derivative gain (loss)
Natural gas liquids, such as ethane, propane, butanes and natural
gasoline
New York Stock Exchange
Over-the-Counter
The gain or loss recognized when a derivative matures or is settled
Petroleum Administration for Defense District
Pipeline and Hazardous Materials Safety Administration
Producer Price Index
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
[THIS PAGE INTENTIONALLY LEFT BLANK]
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:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
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 the MarkWest Merger (as defined below), joint venture arrangements and other
acquisitions, including the dropdowns proposed 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:
•
•
•
•
•
•
•
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;
•
•
•
•
•
•
•
•
•
•
•
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 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;
the time, costs and ability to obtain regulatory and other approvals, waivers or consents required to
consummate the strategic initiatives proposed by MPC, such as the proposed accelerated dropdown of
assets to MPLX LP;
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;
2
•
•
•
•
•
•
•
•
•
•
•
unusual weather conditions and natural disasters;
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 a persistence or 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 and
changes affecting the credit markets generally; 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.
Our assets include infrastructure to support MPC including approximately 2,900 miles of crude oil and refined
product pipelines across nine states. We own a barge dock facility with approximately 78 mbpd of crude oil and
refined product throughput capacity, as well as crude oil and product storage facilities (tank farms) with
approximately 4,533 mbbls of available storage capacity. We also own a butane cavern with approximately
1,000 mbbls of available storage capacity. Effective March 31, 2016, the Partnership acquired MPC’s inland
marine business, comprised of 18 tow boats and 205 tank barges. This business is operated through HSM and the
related assets, liabilities and results of operations are collectively referred to as the “Predecessor.” On
December 4, 2015, we completed the merger with MarkWest (the “MarkWest Merger”), which is 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. These assets include gathering and processing infrastructure of more than 5,600 miles of
gas and NGL pipelines, 54 gas processing plants, 14 NGL fractionation facilities and two condensate
stabilization facilities.
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. Furthermore, 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, Woodford Shale, Granite Wash formation and the Permian Basin.
As of February 13, 2017, MPC owned our general partner, MPLX GP LLC (“MPLX GP”), and the associated
incentive distribution rights, in addition to an approximate 23.5 percent limited partner interest (including the
Class B units on an as-converted basis) in us. Given MPC’s significant interest in us, and its stated intent to grow
its midstream business, MPC has recently announced plans to offer its MLP-qualifying assets estimated to
generate $1.4 billion of annual EBITDA from its portfolio of midstream assets. MPC expects to offer us these
assets as soon as practicable in 2017, subject to market conditions, requisite approvals and regulatory clearances,
including tax. In conjunction with the completion of the announced dropdowns, MPC also expects to exchange
its economic interests in MPLX GP for newly issued MPLX LP units in order to optimize the Partnership’s cost
of capital. We also have significant organic growth opportunities to expand midstream services throughout major
shale plays in the United States. Furthermore, we may pursue third-party midstream acquisitions independently
or with MPC to complement our existing geographic footprint or expand our activities into new areas. MPC is
under no obligation, however, to offer to sell us additional assets or to pursue acquisitions cooperatively with us,
and we are under no obligation to acquire any such additional assets or pursue any such cooperative acquisitions.
Finally, we have an investment grade credit profile that provides the Partnership strong financial flexibility in
order to fund growth projects and execute its 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:
5
The following table summarizes the operating performance for each segment for the year ended December 31,
2016. 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 interest
and Predecessor
Segment portion attributable to noncontrolling interest and Predecessor
Segment operating income attributable to MPLX LP
2016
G&P
Total
$2,185
1
$2,972
69
2,186
3,041
L&S
$787
68
855
368
907
1,275
487
34
1,279
147
1,766
181
$453
$1,132
$1,585
RECENT DEVELOPMENTS
On March 14, 2016, the Partnership entered into a Membership Interests Contribution Agreement (the
“Contribution Agreement”) with MPLX GP, MPLX Logistics Holdings LLC and MPC Investment LLC (“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. The general partner units maintained
MPC’s two percent general partner interest in the Partnership. The acquisition closed on March 31, 2016. MPC
waived distributions in the first quarter of 2016 on MPLX LP common units issued in connection with this
transaction.
The inland marine business, which transports light products, heavy oils, crude oil, renewable fuels, chemicals and
feedstocks in the Midwest and U.S. Gulf Coast regions, 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 as a reporting
unit of the L&S segment. See Item 8. Financial Statements and Supplementary Data—Note 4 for more
information on this transaction.
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. 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 receive as a distribution the greater
of $0.528125 per unit or the amount of per unit distributions paid to common units. See Item 8. Financial
Statements and Supplementary Data—Note 9 for more information on this transaction.
On August 4, 2016, MPLX LP entered into a Second Amended and Restated Distribution Agreement (the
“Distribution Agreement”) providing for the continuous issuance of MPLX LP common units, in amounts, at
prices and on terms to be determined by market conditions and other factors at the time of any offerings (such
continuous offering program, or at-the-market program, referred to as the “ATM Program”). MPLX LP expects
to use the net proceeds from sales under the ATM Program for general partnership purposes including repayment
of debt and funding for acquisitions, working capital requirements and capital expenditures.
6
During the year ended December 31, 2016, the Partnership issued an aggregate of 26 million common units
under the ATM Program generating net proceeds of approximately $776 million. As of December 31, 2016,
$717 million of common units remains available for issuance through the ATM Program under the Distribution
Agreement.
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 (MarkWest Hydrocarbon, Inc. prior to the
Class A Reorganization), were either distributed to or purchased by MPC in exchange for $84 million in cash and
a fixed number of MPLX LP common units and MPLX LP general partner units. Following these preparatory
transactions, all of the MPLX LP Class A units were exchanged on a one-for-one basis for newly issued common
units representing limited partner interests in MPLX LP. MPC also contributed $141 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. See Item 8. Financial Statements and Supplementary Data—Note 8 for more
information on this transaction.
On October 11, 2016, the Cornerstone Pipeline became fully operational and in December 2016, the Hopedale
pipeline connection was completed. This project is reported within our L&S segment. This pipeline is designed
to transport condensate and natural gasoline from origination facilities in Harrison County, OH, to a tank farm in
East Sparta, OH, where the condensate and natural gasoline can then continue on to MPC’s refinery in Canton,
OH. The completion of this key organic growth project has created transportation and marketing options for
Utica and Marcellus shale production. Additional pipelines are currently under construction and will provide
further distribution to the Midwest and Canada.
On January 3, 2017, MPC announced its plans to offer the Partnership the opportunity to acquire assets
contributing an estimated $1.4 billion of annual EBITDA in 2017. These planned dropdowns are subject to
market conditions, requisite approvals and regulatory clearances, including tax clearance.
On December 5, 2016, MPC offered up to 100 percent of MPLX Terminals LLC (“MPLX Terminals”), Hardin
Street Transportation LLC (“Hardin Street Transportation”) and Woodhaven Cavern LLC (“Woodhaven
Cavern”) to MPLX. MPLX Terminals owns and operates light products terminals. Hardin Street Transportation
owns and operates various private crude oil and refined product pipeline systems and associated storage tanks.
Woodhaven Cavern owns and operates butane and propane storage caverns. The transaction is expected to close
in the first quarter of 2017, pending requisite approvals.
The Partnership’s plans for funding these dropdowns would likely include debt and equity in approximately
equal proportions, with the equity financing to be funded through transactions with MPC. In February 2017, we
issued an additional $2.25 billion aggregate principal amount of senior notes, as described below. In addition to
the expected dropdowns, MPC announced its intentions to offer to exchange its IDRs for MPLX LP units in
conjunction with the completion of the dropdowns in order to reduce the Partnership’s cost of capital.
On January 25, 2017, we announced the board of directors of our general partner had declared a distribution of
$0.5200 per unit that was paid on February 14, 2017 to unitholders of record on February 6, 2017.
On February 6, 2017, the Partnership and Antero Midstream Partners LP (“Antero Midstream”) formed a
strategic joint venture to support Antero Resources Corporation (“Antero Resources”) in the Marcellus Shale.
Antero Midstream Partners released to the joint venture its dedication from Antero Resources of approximately
195,000 gross operated acres located in Tyler, Wetzel and Ritchie counties of West Virginia. The joint venture
7
will support the ongoing development of incremental gas processing required by Antero Resources in the
Marcellus Shale. The joint venture is also investing in fractionation capacity at MarkWest’s Hopedale Complex
in Ohio 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 24 for additional information.
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” and,
collectively with the 2027 Senior Notes, the “New 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
Partnership intends to use the net proceeds from this offering for general partnership purposes, which may
include, from time to time, acquisitions (including the previously announced planned dropdown of assets from
MPC, the acquisition of the Ozark pipeline, and the acquisition of a partial, indirect equity interest in the Bakken
Pipeline system) and capital expenditures. See Item 8. Financial Statements and Supplementary Data—Note 24
for additional information.
On February 13, 2017, the Partnership announced that it has entered into an asset purchase agreement with
Enbridge Pipelines (Ozark) LLC (“Enbridge Ozark”), under which an affiliate of Pipe Line Holdings has agreed
to purchase the Ozark pipeline for approximately $220 million from Enbridge Ozark. 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 230,000 barrels per day. This purchase transaction is expected to close in
the first quarter of 2017. See Item 8. Financial Statements and Supplementary Data—Note 24 for additional
information.
On February 15, 2017, the Partnership closed on its previously announced intent to participate in a joint venture
with Enbridge Energy Partners L.P. (“Enbridge Energy Partners”) to acquire a 9.1875 percent indirect interest in
the Dakota Access Pipeline (“DAPL”) and Energy Transfer Crude Oil Company Pipeline (“ETCOP”) projects,
collectively referred to as the Bakken Pipeline system, from Energy Transfer Partners, L.P. (“ETP”) and Sunoco
Logistics Partners, L.P. (“SXL”) for $500 million. Furthermore, MPC expects to become a committed shipper on
the Bakken Pipeline system under terms of an on-going open season. The Bakken Pipeline system is currently
expected to deliver in excess of 470,000 barrels per day 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. ETP and SXL
collectively own a 75 percent interest in each of the two joint ventures that are developing the Bakken Pipeline
system. MPLX LP and Enbridge Energy Partners intend to form a new joint venture to acquire 49 percent of ETP
and SXL’s 75 percent indirect interest in the Bakken Pipeline system. MPLX LP will own 25 percent of this new
joint venture with Enbridge, which results in its 9.1875 percent indirect ownership interest in the Bakken Pipeline
system. The Partnership expects to account for its investment using the equity method of accounting. See Item 8.
Financial Statements and Supplementary Data—Note 24 for additional information.
BUSINESS STRATEGIES
Our primary business objectives are to enhance unitholder returns through the generation of stable cash flows.
We intend to accomplish these objectives by executing the following strategies:
Maintain 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.
8
Grow through Acquisitions. In addition to the MarkWest Merger and HSM acquisition, we plan to continue
pursuing acquisitions of complementary assets from MPC as well as third parties, such as the Ozark pipeline
acquisition and the acquisition of the joint venture interest in the Bakken Pipeline system. As discussed above,
we announced that we expect to acquire assets from MPC with an estimated $1.4 billion of annual EBITDA as
soon as practicable, subject to requisite approvals, and regulatory clearance, including tax. We may also pursue
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 continuing to grow in our primary areas of operation to meet anticipated demand for additional
midstream services. In addition, 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 by providing fee-based
midstream services to our customers. For the full year ending December 31, 2017, 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).
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 16 consecutive quarters, which represents
a compound annual growth rate of 18.6 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 future
growth, and eliminating IDR distributions to MPC. On January 3, 2017, we announced that we expect to
exchange MPLX LP units for MPC’s economic interests in MPLX GP, including IDR’s, in conjunction with the
completion of the MPC asset acquisitions described above. 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:
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 comprise approximately 81 percent of total
United States crude distillation capacity and approximately 81 percent of total United States finished
products demand for the year ended December 31, 2016, according to the EIA. These assets are
integral to the success of MPC’s operations, which include seven refineries in the Midwest and Gulf
Coast regions of the United States with an aggregate crude oil refining capacity of approximately
1.8 million barrels per calendar day.
9
• 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
February 13, 2017, our assets in the northeastern United States have combined processing capacity
of approximately 6.1 bcf/d and combined fractionation capacity of approximately 518 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 significant 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.
Leading Midstream Positions Drive Investment Opportunities. Our organic growth capital plan range for 2017 is
$1.4 billion to $1.7 billion, which does not include the anticipated dropdowns or acquisitions previously
discussed or their respective subsequent capital spending. The G&P segment capital plan includes investments
that are expected to support producer customers. During 2017, we expect to complete 400 mmcf/d of additional
natural gas processing capacity and 120 mbpd of additional fractionation capacity (of which 60 mbpd of
fractionation capacity has already been completed), primarily in the Marcellus Shale. The L&S segment capital
plan includes the development of various crude oil and refined petroleum products infrastructure projects,
including a build out of Utica Shale infrastructure in connection with the recently completed Cornerstone
Pipeline, a butane cavern and a tank farm expansion. 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 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. We believe MPC to be the largest crude oil refiner in the Midwest and
the third-largest in the United States based on crude oil refining capacity. MPC is well-capitalized, with investment
grade credit ratings, and owns our general partner, an approximate 23.5 percent limited partner interest (including
the Class B units on an as-converted basis) as of February 13, 2017 and all of our incentive distribution rights. We
expect to acquire a portfolio of midstream assets from MPC, as recently announced in its plan to dropdown an
estimated $1.4 billion of EBITDA in 2017, subject to regulatory and tax clearance. In conjunction with the
completion of the announced dropdowns, MPC also expects to exchange its economic interest in MPLX GP for
newly issued MPLX LP units in order to optimize the Partnership’s cost of capital. We believe that our relationship
with MPC will provide us with significant growth opportunities, as well as a base of stable cash flows.
High-Quality, Well-Maintained Asset Base. 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, 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.
Stable and Predictable Cash Flows. We generate a substantial majority of our revenue through long-term,
fee-based agreements. 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. The table below provides long-term contract
details by segment as of December 31, 2016:
L&S segment
G&P segment
Remaining contract term
% of volumes
6 years
4 to 19 years
72%
85%
10
Financial Flexibility. As of December 31, 2016, we had $234 million of cash and $2.5 billion available on our
revolving credit facilities. We believe that we will have the financial flexibility to execute our growth strategy
through excess cash reserves, borrowing capacity under our revolving credit facilities and access to the debt and
equity capital markets. See Item 8. Financial Statements and Supplementary Data—Note 17 and Note 8 for
additional information regarding our recent transactions related to debt and common unit 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 our investment in the Ozark pipeline, the Bakken Pipeline system, the Cornerstone Pipeline, the
joint venture with Antero Midstream Partners, LP, the strategic initiatives announced by MPC, our plans for
funding the dropdowns, the ATM Program, our business strategies, competitive strengths and the Partnership’s
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 a persistence or increase of the current yield on common units, which is higher than
historical yields, adversely affecting the Partnership’s ability to meet its distribution growth guidance; the time,
costs and ability to obtain regulatory or other approvals and consents and otherwise consummate the strategic
initiatives discussed herein and other proposed transactions; the satisfaction or waiver of conditions in the
agreements governing the strategic initiatives discussed herein and other proposed transactions; our ability to
achieve the strategic and other objectives related to the strategic initiatives discussed herein, including the
dropdowns proposed by MPC and other proposed transactions; adverse changes in laws including with respect to
tax and regulatory matters; inability to agree with respect to the timing of and value attributed to assets identified
for dropdown; the adequacy of the Partnership’s capital resources and liquidity, including, but not limited to,
availability of sufficient cash flow to pay distributions, and the ability to successfully execute its business plans
and growth strategy; continued/further volatility in and/or degradation of market and industry conditions;
changes to the expected construction costs and timing of projects; completion of midstream infrastructure by
competitors; disruptions due to equipment interruption or failure, including electrical shortages and power grid
failures; the suspension, reduction or termination of MPC’s obligations under the Partnership’s commercial
agreements; modifications to earnings and distribution growth objectives; the level of support from MPC,
including dropdowns, alternative financing arrangements, taking equity units, and other methods of sponsor
support, as a result of the capital allocation needs of the enterprise as a whole and its ability to provide support on
commercially reasonable terms; compliance with federal and state environmental, economic, health and safety,
energy and other policies and regulations and/or enforcement actions initiated thereunder; changes to the
Partnership’s capital budget; prices of and demand for natural gas, NGLs, crude oil and refined products, delays
in obtaining necessary third-party approvals and governmental permits, changes in labor, material and equipment
costs and availability, planned and unplanned outages, the delay of, cancellation of or failure to implement
planned capital projects, project overruns, disruptions or interruptions of our operations due to the shortage of
skilled labor 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.
11
ORGANIZATIONAL STRUCTURE
The following diagram depicts our organizational structure and MPC’s ownership interests in us as of
February 13, 2017.
Marathon Petroleum Corporation
(NYSE: MPC)
and Affiliates
86,619,313 Common Units
100% ownership interest
MPLX GP LLC
(our General Partner)
7,372,419 General Partner Units
Incentive Distribution Rights
23.5% limited
partner interest
Public Unitholders
270,638,348
Common Units
73.3% limited
partner interest
Series A Preferred
Unitholders
30,769,232
Preferred Units
2.0% general
partner interest
MPLX LP
(NYSE: MPLX)
(the Partnership)
1.2% limited
partner interest
M&R MWE
Liberty LLC
3,990,878*
Class B Units
MPLX Operations LLC
MarkWest Energy Partners, L.P.
MPLX Pipe Line
Holdings Operating
Subsidiaries
Hardin Street
Marine LLC
MPLX Terminal and
Storage LLC
(Neal, WV butane cavern)
MarkWest
Operating
Subsidiaries
We are an MLP with outstanding common units, Preferred units, and Class B 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 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
12
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 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 in 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.
• All of the Class B units were issued to and are held by M&R MWE Liberty LLC and certain of its
affiliates (“M&R”), an affiliate of The Energy & Minerals Group (“EMG”). 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. Each Class B unit of MPLX LP will
convert into 1.09 common units of MPLX LP and the right to receive $6.20 in cash, and the conversion
of the Class B units will occur in equal installments, the first of which occurred on July 1, 2016 and the
second of which will occur on July 1, 2017. Class B units (i) share in our taxable income and losses,
(ii) are not entitled to participate in any distributions of available cash prior to their conversion and
(iii) do not have the right to vote on, approve or disapprove, or otherwise consent to or not consent to
any matter (including mergers, unit exchanges and similar statutory authorizations) other than those
matters that disproportionately and adversely affect the rights and preferences of the Class B units.
Upon conversion of the Class B units, the right of M&R and certain of its affiliates to vote as a
common unitholder of the Partnership will be limited to a maximum of five percent of the Partnership’s
outstanding common units. Upon the conversion of each tranche of Class B units, M&R will have 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. In addition, M&R may freely transfer
such converted units, and M&R will have the right to demand that we conduct up to three underwritten
offerings beginning in 2017, but restricted to no more than one offering in any twelve-month period.
M&R is not permitted to transfer its Class B units without the prior written consent of our general
partner’s board of directors.
INDUSTRY OVERVIEW
We provide diversified services in the midstream sector 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, 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.
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 cavern. Storage facilities provide flexibility and logistics optionality, which
enhances MPC’s ability to maximize returns for refined products.
13
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, and the components of this value chain are
graphically depicted and further described below:
• Gathering. The natural gas production process begins with the drilling of wells into gas-bearing rock
formations. At the initial stages of the midstream value chain, a network of pipelines known as
gathering systems directly connect to wellheads in the production area. These gathering systems
transport raw, or untreated, natural gas to a central location for treating and processing. A large
gathering system may involve thousands of miles of gathering lines connected to thousands of wells.
Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at
different pressures and scalable to allow gathering of additional production without significant
incremental capital expenditures.
• Compression. Natural gas compression is a mechanical process in which a volume of natural gas
at a given pressure is compressed to a desired higher pressure, which allows the natural gas to be
gathered more efficiently and delivered into a higher pressure system, processing plant or
pipeline. Field compression is typically used to allow a gathering system to operate at a lower
pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure
system. Since wells produce at progressively lower field pressures as they deplete, field
compression is needed to maintain throughput across the gathering system.
•
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
14
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 system 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.
Historically, the majority of the domestic on-shore natural gas supply has been produced from conventional
reservoirs that are characterized by large pockets of natural gas that are accessed using vertical drilling
techniques. In the past decade, the supply of natural gas production from the conventional sources has declined as
these reservoirs are being depleted. 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.
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. 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 common carrier crude oil and refined product pipeline systems and associated storage assets and an inland
marine business. We believe our network of petroleum pipelines is one of the largest in the United States, based
15
on total annual volumes delivered. We also own a butane cavern in Neal, West Virginia with approximately
1,000 mbbls of liquefied petroleum gas storage capacity. 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. We have
completed the Cornerstone pipeline project, which is the building block for other projects that we expect to
become 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. We are also constructing a butane
cavern in Robinson, Illinois, which will be a 1,400-mbbl hard rock mined storage cavern. 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
December 31, 2016, 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.
The following is a summary of the significant assets owned by the L&S segment:
Crude Oil Pipeline System Name
Patoka to Lima crude system
Catlettsburg and Robinson crude
system
Detroit crude system
Wood River to Patoka crude system
Total crude oil pipelines
Product Pipeline System Name
Cornerstone products system
Garyville products system
Texas City products system
ORPL products system
Robinson products system
Louisville airport products system
Total product pipelines
Capacity
(mbpd)
Associated MPC refineries
267
Detroit, MI; Canton, OH
515
197
314
1,293
Capacity
(mbpd)
238
389
215
244
513
29
1,628
Robinson, IL; Catlettsburg, KY
Detroit, MI
All Midwest refineries
Associated MPC refineries
Canton, OH
Garyville, LA
Texas City, TX; Galveston Bay, TX
Catlettsburg, KY; Canton, OH
Robinson, IL
Robinson, IL
Other L&S Assets
Wood River barge dock
Neal butane cavern
Tank farms
Marine Repair Facility
Capacity(1)
Associated MPC refineries
78 mbpd
1,000 mbbls
4,533 mbbls
N/A
Garyville, LA
Catlettsburg, KY
All Midwest refineries
Catlettsburg, KY
(1) All capacity shown is for 100 percent of the available storage capacity of our butane cavern and tank farms
and 100 percent of the barge dock’s average capacity.
16
As of December 31, 2016, our marine transportation operations included 18 owned towboats as well as 204
owned and 18 leased barges that transport refined products and crude oil on the Ohio, Mississippi and Illinois
rivers and their tributaries and inter-coastal waterways. The following table sets forth additional details about
MPLX LP’s barges and towboats.
Number at
December 31,
2016
Capacity
(thousand
barrels)
Associated MPC refineries
Catlettsburg, KY; Garyville, LA
963
4,631
5,594
64
158
222
2
16
18
Catlettsburg, KY; Garyville, LA
Marine Vessels
Inland tank barges:(1)
Less than 25,000 barrels
25,000 barrels and over
Total
Inland towboats:
Less than 2,000 horsepower
2,000 horsepower and over
Total
(1) All of our barges are double-hulled.
G&P:
Natural Gas Gathering
We operate several natural gas gathering systems that have a combined 5,439 mmcf/d throughput capacity in six
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 Keystone Complex located in Butler County, Pennsylvania (the “Keystone Complex”). 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 EMG, 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”). We also
operate a C3+ fractionation complex at the Hopedale Complex located in Harrison County, Ohio (the “Hopedale
Complex”). Ohio Condensate, our joint venture with Summit, operates one condensate stabilization facility with
23 mbpd of capacity.
17
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 four 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”);
processing at the Hidalgo Complex located in Culberson County, Texas (the “Hidalgo Complex”); and treating,
processing and C2+ fractionation at the Javelina Complex located in Corpus Christi, Texas (the “Javelina
Complex”). We also own a non-operating interest in the Centrahoma processing complex.
The following table summarizes our current and planned processing assets:
Plant
Keystone 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
Javelina Complex
Existing
capacity
(mmcf/d)
Expansion
capacity under
construction
(mmcf/d)
Expected in-
service of
expansion
capacity
410
—
555
1,070
920
1,200
525
800
160
70
65
325
600
425
200
142
— N/A
200 2018
200 Q1 2018
200 2018
— N/A
600 Q2 2017, Q4
2017 and Q1
2018
200 2018
— N/A
— N/A
— N/A
— N/A
— N/A
— N/A
— N/A
— N/A
— 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
Total
7,467
1,400
(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.
18
The following table summarizes our key producer customers and attributes for each geographic region as of
December 31, 2016:
Marcellus Operations
Utica Operations
Key Producer Customers
Volume Protection
Area Dedications
Range Resources,
Antero(1), EQT(1),
CNX, Noble(1),
Southwestern(1),
Rex and others
65% of 2016
capacity contains
minimum volume
commitments
4 million acres
Antero(1),
Gulfport, Ascent,
Rice, Rex, PDC
and others
Southern Appalachian
Operations
Chesapeake(1)(2),
EQT(1) and
NiSource(1)
Southwest Operations
Anadarko,
Newfield, BP,
PetroQuest and
others
27% of 2016
capacity contains
minimum volume
commitments
3.9 million acres
24% of 2016
capacity contains
minimum volume
commitments
None
15% of 2016
capacity contains
minimum volume
commitments
1.5 million acres
(1) We do not provide gathering services for these producer customers.
(2)
In the fourth quarter of 2016, Chesapeake executed a purchase and sale agreement to sell the majority of its
upstream and midstream assets in the Devonian Shale located in West Virginia and Kentucky. The new
owner continues to utilize our processing facilities in the Southern Appalachian Operations.
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. We operate several NGL gathering pipelines for these
mixed NGL streams that have a combined 818 mbpd throughput capacity in five states.
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 Keystone Complexes
for fractionation.
19
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
Keystone Complex
Hopedale Complex(1)
Houston Complex
Siloam Complex
Javelina Complex
Total
Existing propane
and heavier
NGLs + capacity
(mbpd)
Market outlets
Geographic Region
47 Railcar and truck loading
180 Key interstate pipeline access
Railcar and truck loading
Marine vessels
60 Key interstate pipeline access
Railcar and truck loading
Marine vessels
24 Railcar and truck loading
Marine vessels
11 Key interstate pipeline access
322
Marcellus Operations
Marcellus and Utica
Operations
Marcellus Operations
Southern Appalachian
Operations
Southwest Operations
(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 subsidiary of MarkWest Liberty
Midstream & Resources, L.L.C (“MarkWest Liberty Midstream”). MarkWest Liberty Midstream and
MarkWest Utica EMG are entities that operate in the Marcellus and Utica regions, respectively. We account
for MarkWest Utica EMG as an equity method investment. See discussion in Item 8. Financial Statements
and Supplementary Data—Note 5.
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 have begun recovering 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
Keystone 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
20 Q3 2017
2018
20
— N/A
40 Q4 2017
— N/A
— N/A
— N/A
— N/A
80
14
—
40
40
10
40
40
18
202
20
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 and the Sherwood Complex to the Houston
Complex on a FERC pipeline. Beginning in April 2016, purity ethane produced at the Mobley Complex
began being transported on this same FERC pipeline to the Houston Complex.
• We deliver purity ethane to Sunoco Logistics Partners L.P.’s (“Sunoco”) Mariner West pipeline (“Mariner
West”) from the Houston Complex and from the Keystone Complex.
• We deliver purity ethane to Enterprise Products Partners L.P.’s Appalachia-to-Texas Express (“ATEX”)
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. Beginning 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. Beginning in May 2016, Mariner East began transporting purity
ethane in addition to propane to the Marcus Hook Facility.
Sunoco has 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 late 2017.
A significant portion of our business comes from a limited number of key customers. For the year ended
December 31, 2016, revenues earned from one customer are significant to the segment, accounting for 17 percent
of G&P segment revenue and 12 percent of consolidated revenue and other income. Additionally, revenues
earned from a second customer are significant to the segment, accounting for 15 percent of G&P segment
revenue and 10 percent of consolidated revenue and other income.
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.
Equity Investment in Unconsolidated Affiliates—MarkWest Utica EMG
MarkWest Utica EMG is engaged in providing natural gas gathering, processing, and NGL fractionation,
transportation and marketing services in the Utica Shale in eastern Ohio. We own 56 percent of MarkWest Utica
EMG as of December 31, 2016.
The financial results for MarkWest Utica EMG and other unconsolidated affiliates are included in (Loss) income
from equity method investments in our Consolidated Statements of Income. For a complete discussion of the
formation of, and the accounting treatment for, MarkWest Utica EMG and other material unconsolidated
affiliates, see Item 8. Financial Statements and Supplementary Data—Note 5.
OUR TRANSPORTATION 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 and storage services agreements with MPC. Under these long-term, fee-based
agreements, we provide transportation and storage services to MPC and, other than on our marine transportation
service agreement, MPC has committed to provide us with minimum quarterly throughput volumes on crude oil
and refined products pipelines systems and minimum storage volumes of crude oil, products and butane. 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
21
agreements for our crude oil and refined products pipeline systems include a 5-15 year term with various
automatic renewal terms ranging from multiple 2-5 year terms unless terminated by either party no later than six
months prior to the end of the term. Our butane cavern storage services agreement includes a 10-year term but
does not automatically renew. 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 no later than six months prior
to the end of the term. Our marine transportation service agreement includes an initial six-year term and
automatically renews up to two additional five-year terms unless terminated by either party no later than twelve
months prior to the end of the current term.
The following table sets forth additional information regarding our transportation and storage services
agreements:
Transportation and Storage Services Agreements with MPC
Agreement
Initiation Date
Transportation Services (mbpd):
Crude systems
Product systems
Marine
Storage Services (mbbls):
Neal Butane Cavern
Tank Farms
Term
(years)
5-10
10-15
6
MPC
minimum
commitment(1)
745
900
N/A(2)
1,000
4,963
October 31, 2012
Various
January 1, 2015
October 31, 2012
Various
10
3
(1) Quarterly commitment for our transportation services agreements in thousands of barrels per day and
committed storage for our storage services agreements in thousands of barrels. Volumes shown for crude oil
transportation services agreements are adjusted for crude viscosities.
(2) MPC has committed to utilize 100 percent of our available capacity of tanks and barges.
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 system 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
pipeline system, without regard to any minimum volume commitment that may have been in place during the
term of the agreement.
MPC’s obligations under these transportation and storage services agreements will not terminate if MPC no
longer controls our general partner.
22
OPERATING AND MANAGEMENT SERVICES AGREEMENTS WITH MPC AND THIRD PARTIES
Operating Agreements
Through MPL, we operate various pipeline systems 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 pipeline systems owned by MPC. This fee is
currently $16 million and will be adjusted annually for inflation. MPC has agreed to indemnify MPL against any
and all damages arising out of the operation of MPC’s pipeline systems 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 pipeline systems. 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 Company,
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.
MPL maintains and operates four undivided joint interest pipeline systems including Capline, Centennial,
Lou-Lex and Muskegon. MPL receives an operating fee for each of these systems, which is subject to adjustment
for inflation. In addition, we are reimbursed for specific costs associated with operating each pipeline system.
The length and renewals terms for each agreement vary.
Management Services Agreements
The Partnership has two management services agreements with wholly-owned subsidiaries of MPC under which
it provides certain management services to MPC with respect to certain of MPC’s retained pipeline assets. The
Partnership received $1 million in fees under these agreements in 2016. The Partnership may adjust annually for
inflation and based on changes in the scope of management services provided.
The Partnership also receives engineering and construction and administrative management fee revenue and
other direct personnel costs for operating some joint venture entities.
The Partnership, through its wholly-owned subsidiary, HSM, has a management services agreement with MPC
under which HSM 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. The Partnership received $21 million in fees under this agreement in 2016. This agreement expires on
June 30, 2020.
OTHER AGREEMENTS WITH MPC
We have the following additional agreements with MPC:
• Omnibus Agreement. As of October 31, 2012, we entered into 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,
23
including certain environmental, title and tax matters. In addition, we will indemnify MPC for certain
matters under this agreement.
• Employee Services Agreements. We have four employee services agreements with MPC. Two of the
employee services agreements with MPC were entered into effective October 1, 2012, under which we
agreed to reimburse MPC for the provision of certain operational and management services to us in support
of our pipelines, barge dock, butane cavern and tank farms within the L&S segment. Effective
December 28, 2015, we entered into an additional employee services agreement with MPC, which requires
that we reimburse MPC for certain operational and management services to us in support of our G&P
segment and certain of our other operations. Lastly, we are party to an employee services agreement dated
January 1, 2015, pursuant to which HSM reimburses MPC for employee benefit expenses along with certain
operation and management services provided in support of HSM’s areas of operation. The agreement is
effective until December 31, 2019. Prior to January 1, 2015, this agreement did not exist.
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 third-largest in the United States based on crude oil refining capacity. MPC
owns and operates seven 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 $63 billion in
2016. Marathon Petroleum Corporation’s common stock trades on the NYSE under the symbol “MPC.”
MPC’s operations necessitate large-scale movements of crude oil and feedstocks to and among its refineries, as
well as large-scale movements of refined products from its refineries to various markets. To this end, MPC has
an extensive portfolio of midstream assets that can potentially be sold and/or contributed to us, providing us with
a competitive advantage. As of December 31, 2016, these midstream assets included investments in crude oil and
refined product pipelines, an ocean vessel joint venture, light product and asphalt terminals, a fuels distribution
business and certain refinery assets.
MPC retains a significant interest in us through its ownership of our general partner, an approximate 23.5 percent
limited partner interest (including the Class B units on an as-converted basis) in us and all of our incentive
distribution rights as of February 13, 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 use us to grow its
midstream business. This includes an expectation for MPC to offer us assets contributing an estimated
$1.4 billion of annual EBITDA by the end of 2017, subject to market and other conditions. The transactions are
expected to support increased limited and general partner distributions and provide value creation for investors.
We also may pursue acquisitions cooperatively with MPC which has the balance sheet flexibility and the ability
to incubate projects for us to purchase later. However, MPC is under no obligation to offer to sell us additional
assets or to pursue acquisitions cooperatively with us, and we are under no obligation to buy any such additional
assets or pursue any such cooperative acquisitions.
24
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, 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: transportation and storage of crude oil; gathering, processing and transmission of natural
gas; gathering, transportation, fractionation and storage of NGLs; and gathering and transportation 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
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.
• Percent-of-index arrangements—Under percent-of-index arrangements, we purchase natural gas 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 then gather and deliver
the natural gas to pipelines where we resell the natural gas at the index price or at a different percentage
discount to the index price. Revenue generated from percent-of-index 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
25
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.
The following table does not give effect to our active commodity risk management program. For further
discussion of how we manage commodity price volatility for the portion of our net operating margin that is not
fee-based, see Item 8. Financial Statements and Supplementary Data—Note 16. 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. The calculated percentages for net operating margin for percent-of-proceeds, percent-of-index and
keep-whole contracts reflect the partial offset of our natural gas positions. The calculated percentages are less
than one percent for percent-of-index due to the offset of our natural gas positions and, therefore, not meaningful
to the table below. For the year ended December 31, 2016, we calculated the following approximate percentages
of our net operating margin from the following types of contracts:
L&S(3)
G&P(3)(4)
Total
Fee-Based
Percent-of-Proceeds(1)
Keep-Whole(2)
100%
90%
93%
— %
9%
6%
— %
1%
1%
(1)
(2)
Includes condensate sales and other types of arrangements tied to NGL prices.
Includes condensate sales and other types of arrangements tied to both NGL and natural gas prices.
(3) Detail on contract types above.
(4)
Includes unconsolidated affiliates (See Item 8. Financial Statements and Supplementary Data—Note 5).
COMPETITION
Within our L&S segment, as a result of our contractual relationship with MPC under our transportation and
storage services agreements, and our connections to MPC’s refineries, we believe that our crude oil and refined
product pipelines will not face significant competition for MPC’s crude oil or products transportation
requirements.
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 only ship the minimum volumes through
our pipelines (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
26
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 15 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
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 on our pipeline systems, at our barge dock and stored at
our storage assets is directly affected by the level of supply and demand for crude oil and refined products in the
markets served directly or indirectly by our assets. Many 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.
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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 pipeline systems 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 pipeline systems. 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. Certain of our liquids pipeline systems are common carriers
subject to regulation by various federal, state and local agencies. FERC regulates interstate transportation on
liquids pipeline systems 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 publicly posted on the
company’s website. Under the ICA, interested persons may challenge new or changed rates or services. 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 complaint to an existing
rate or service could result in a petroleum pipeline paying reparations, together with interest, for the period
beginning two years prior to the date of the complaint until the just and reasonable rate or service was
established. FERC may also investigate, upon complaint or on its own motion, existing rates and related rules
and may order a pipeline to change them prospectively.
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
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pipeline systems, and the rates for certain of our products pipelines have subsequently been approved as market-
based rates. FERC may change grandfathered rates 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 indexing rate methodology which, as currently in
effect, allows petroleum pipelines to change their rates within prescribed ceiling levels that are tied to changes in
the PPI. FERC’s indexing methodology is subject to review every five years. During the five-year period
commencing July 1, 2011 and ending June 30, 2016, petroleum pipelines charging indexed rates are permitted to
adjust their indexed ceilings annually by PPI plus 2.65 percent. During the five-year period commencing July 1,
2016, petroleum pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI
plus 1.23 percent. 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 increase in costs.
However, FERC is currently evaluating when and how indexed adjustments to rates can be challenged.
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, pipelines must file to
lower their rates if those rates would otherwise be above the rate ceiling, unless the pipelines request and receive
a waiver from FERC permitting them not to apply the negative index adjustment.
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 pipeline systems.
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. Finally, FERC’s income tax policy continues to be the subject of various
appeals by shippers, before FERC and the courts. We cannot guarantee that FERC or the courts will not make
changes to the policy in the future.
Intrastate services provided by certain of our liquids pipeline systems 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
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agreements with other 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:
•
•
•
•
•
•
•
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.
Because some of our pipelines are common carrier pipelines, we may be required to accept new shippers who
wish to transport on our pipelines. It is possible that new shippers, current shippers or other interested parties
may decide to challenge our tariff rates and/or the terms of service for our pipelines, including proration rules.
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 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
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. Pursuant to FERC’s
jurisdiction, existing rates and/or other tariff provisions may be challenged (e.g., by complaint) and rate increases
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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 of up to $1 million
per day for each current violation of the NGA. 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
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
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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.
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 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
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regulations may affect the availability of natural gas for processing, such as state regulation of production rates
and maximum daily production allowables 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 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
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
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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. In response to the effects of Hurricanes Katrina and Rita, the
Secretary waived the Jones Act generally for the transportation of petroleum products from September 1 to
September 19, 2005 and from September 26, 2005 to October 24, 2005. In June 2011, the Secretary waived the
Jones Act for the transportation of petroleum released from the Strategic Petroleum Reserve and in November
2012 waived the Jones Act for the transportation of refined petroleum products in the Northeast following
Hurricane Sandy. 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 (also known as “stub lines”) 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, including
the obligation to file a FERC tariff. In the event that FERC were to determine that the pipeline interconnections
did not qualify for such waivers, we would likely be required to file a tariff with FERC for the pipeline
interconnections, provide a cost justification for their transportation rates and provide service to all potential
shippers without undue discrimination. In such event, we may experience increased operating costs and reduced
revenues.
Security. Certain of our facilities have been preliminarily classified as subject to the Department of Homeland
Security Chemical Facility Anti-Terrorism Standards. In addition, we have several facilities that are subject to
the United States Coast Guard’s Maritime Transportation Security Act, and a number of other facilities that are
subject to the Transportation Security Administration’s Pipeline Security Guidelines and are designated as
“Critical Facilities.” The Transportation Security Administration Security Guidelines are subject to change
without formal regulatory proposal and review. We have an internal inspection program designed to monitor and
ensure compliance with all of these requirements. We believe that we are in material compliance with all
applicable laws and regulations regarding the security of our facilities.
ENVIRONMENTAL REGULATION
General
Our processing and fractionation plants, storage facilities, pipelines and associated facilities are subject to
multiple obligations and potential liabilities under a variety of federal, regional, state and local laws and
regulations relating to environmental protection. Such environmental laws and regulations may affect many
aspects of our present and future operations, including for example, requiring the acquisition of permits or other
approvals to conduct regulated activities that may impose burdensome conditions or potentially cause delays,
restricting the manner in which we handle or dispose of our wastes, limiting or prohibiting construction or other
activities in environmentally sensitive areas such as wetlands or areas inhabited by 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
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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. For instance, the EPA is currently taking a closer look
at pipeline maintenance operations, and the result of this closer review may yield modified emission calculations
and/or regulations relating to such activities. 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 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.
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
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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. While we are required to
comply with RCRA requirements relating to hazardous wastes, currently our operations generate minimal
quantities of such hazardous wastes. However, 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. We do not believe that there presently exists significant surface and subsurface contamination of
our properties by petroleum hydrocarbons or other wastes for which we are currently responsible.
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, investigatory or remedial activities with respect to the real property underlying
these facilities. These investigatory and remedial obligations arise out of a September 1994 “Administrative
Order by Consent for Removal Actions” with EPA Regions II, III, IV and V; and with respect to the Boldman
Complex, an “Agreed Order” entered into by the third-party owner/operator with the Kentucky Natural
Resources and Environmental Protection Cabinet in October 1994. 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,
any environmental liabilities associated with the EPA Administrative Order, the Kentucky Agreed Order 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 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.
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
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related to acid mine drainage (“AMD”) with respect to the real property underlying these facilities. These
investigatory and remedial obligations arise out of an arrangement entered into between the Pennsylvania
Department of Environmental Protection and the third party, which has accepted liability and responsibility for,
and indemnifies us against, any environmental liabilities associated with the AMD that are not exacerbated by us
in connection with our operations. In addition, the third party has agreed to perform all of the required response
actions at its expense in a manner that minimizes interference with our use of the property. We understand that to
date, all actions required under these agreements have been or are being performed and, accordingly, we do not
believe that the remediation obligation of these properties will have a material adverse impact on our financial
condition or results of operations.
We are also entitled to indemnification from MPC for assets we acquired from MPC in our Initial Offering, as
further described above under “General”. In addition, from time to time, we have acquired, and we may acquire
in the future, facilities from third parties 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 June 2015, the EPA and the United States Army Corps of
Engineers finalized significant changes to the definition of the term “waters of the United States” (“WOTUS”)
used in numerous programs under the Clean Water Act. This final rulemaking is referred to as the “Clean Water
Rule.” The Clean Water Rule has been challenged in multiple federal courts by many states, trade groups, and
other interested parties, and in October 2015, a United States Court of Appeals issued a nationwide stay of the
Clean Water Rule. The Clean Water Rule, as written, expands permitting, planning and reporting obligations and
may extend the timing to secure permits for pipeline and fixed asset construction and maintenance activities. The
Clean Water Rule does contain new language intended to address concerns that the proposed rule included storm
water conveyances and storage structures as WOTUS, and we continue to review how that new language will
apply under specific circumstances. Court challenges of the Clean Water Rule will continue through 2017.
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In addition, the transportation and storage of crude oil and refined products over and adjacent to water involves
risk and subjects us to the provisions of OPA-90 and related state requirements. Among other requirements,
OPA-90 requires the owner or operator of a tank vessel, a facility or a pipeline to maintain an emergency plan to
respond to releases of oil or hazardous substances. Also, in case of any such release, OPA-90 requires the
responsible company to pay resulting removal costs and damages. OPA-90 also provides for civil penalties and
imposes criminal sanctions for violations of its provisions. We operate facilities at which releases of oil and
hazardous substances could occur. We have implemented emergency oil response plans for all of our components
and facilities covered by OPA-90 and we have established SPCC plans for facilities subject to Clean Water Act
SPCC requirements.
Construction or maintenance of our plants, compressor stations, pipelines, barge dock and storage facilities may
impact wetlands, which are also regulated under the Clean Water Act by the EPA, the United States Army Corps
of Engineers and state water quality agencies. Regulatory requirements governing wetlands (including associated
mitigation projects) may result in the delay of our projects while we obtain necessary permits and may increase
the cost of new projects and maintenance activities. We believe that we are in substantial compliance with the
Clean Water Act and analogous state laws. However, there is no assurance that we will not incur material
increases in our operating costs or delays in the construction or expansion of our facilities because of future
developments, the implementation of new laws and regulations, the reinterpretation of existing laws and
regulations, or otherwise, including, for example, increased construction activities, potential inadvertent releases
arising from pursuing borings for pipelines, and earth slips due to heavy rain and/or other cause.
Hydraulic Fracturing
We do not conduct hydraulic fracturing operations, but we do provide gathering, processing and fractionation
services with respect to natural gas 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 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. The White House Council on Environmental Quality is coordinating an
administration-wide review of hydraulic fracturing practices. Most notably, in December 2016, the EPA released
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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
emissions, or aggregate two or more of our facilities into one application for permitting purposes. 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 producer customers. Compliance with these or other new regulations could, among
other things, require installation of new emission controls on some of our equipment, result in longer permitting
timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact
our business. Federal and state regulators and agencies are also currently taking a closer look at pipeline
maintenance operations and any emissions and permits that may be related to such activities. The result of this
closer review may yield modified emission calculations and/or regulations relating to such activities or
potentially enforcement actions by the agencies for unaccounted for or unpermitted emissions. EPA has finalized
revisions to regulations or interpretations of regulations regarding aggregation of facilities for permitting
purposes 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 MPC’s refineries from which we
receive significant revenues. MPC has been required in the past, and will be required in the future, to incur
significant capital expenditures to comply with new legislative and regulatory requirements relating to its
operations. To the extent these capital expenditures have a material effect on MPC, they could have a material
effect on our business and results of operations. We have been in discussions with various state agencies in the
areas in which we operate with respect to their guidance, policies, rules and regulations regarding the permitting
process, source determination, categories of applicable permits and control technology that may be required for
the construction or operation of certain of our facilities. We believe that our operations are in substantial
compliance with applicable air permitting and control technology requirements.
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. In addition, the EPA is gathering information
regarding existing facilities in various industries, including information collection requests (“ICRs”) issued in
December 2016 to various oil and gas production and midstream facilities, which may be used to support
potential future regulation of GHGs. 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
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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. The EPA has also adopted rules requiring the monitoring and annual
reporting of GHG emissions from certain petroleum and natural gas sources in the United States, including,
among others, certain onshore and offshore oil and natural gas production and onshore oil and natural gas
processing, fractionation, transmission, storage and distribution facilities, which includes certain of our
operations. In addition, in 2015, the EPA issued rules expanding the petroleum and natural gas system sources
for which annual GHG emissions reporting is required to include GHG emissions reporting beginning in the
2016 reporting year for certain onshore gathering and boosting systems consisting primarily of gathering
pipelines, compressors and process equipment used to perform natural gas compression, dehydration and acid gas
removal. 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. Additionally, in 2015 the EPA finalized rules to limit GHG emissions from new and
existing power plants, although the United States Supreme Court issued a stay of these rules in February 2016
while the rules are under review by the United States Court of Appeals for the District of Columbia Circuit. The
requirements could increase the cost of electricity and natural gas for our operations and ultimately states could
impose additional GHG emission reduction requirements. In sum, requiring reductions in GHG emissions at our
facilities could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls
at our facilities and (iii) administer and manage any GHG emissions programs, including acquiring emission
credits or allotments. These requirements may also significantly affect MPC’s refinery operations and may have
an indirect effect on our business, financial condition and results of operations.
Also, Congress has from time to time considered legislation to reduce emissions of GHGs, and while there has
not been federal climate legislation adopted in the United States in recent years, 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. If Congress were to undertake
comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which
could impose additional direct costs on operations and reduce demand for oil, natural gas, NGLs and products
derived therefrom. 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 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.
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Endangered Species Act and Migratory Bird Treaty Act Considerations
The federal Endangered Species Act (“ESA”) and analogous laws regulate activities that may affect endangered or
threatened species, including their habitats. If endangered species are located in areas where we propose to construct
new gathering or transportation pipelines or processing or fractionation facilities, 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. We also may be obligated to develop plans to avoid potential takings of protected species, 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
increase 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 March 2014, the FWS announced the listing of the lesser prairie chicken as a threatened species
under the ESA. In addition, in January 2017, FWS announced that it will list 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 a permit. If there is the potential to
adversely affect migratory birds as a result of our operations or construction activities, we may be required to
obtain necessary permits 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
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
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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 pipeline systems 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 pipeline systems,
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). In addition, on October 18, 2010, PHMSA issued an
advance notice of proposed rulemaking on a range of topics relating to the safety of natural gas, crude oil and
other hazardous liquids pipelines. On October 13, 2015, PHMSA issued a notice of proposed rulemaking which
purposes changes to 49 CFR Part 195, followed shortly by proposed changes to 49 CFR Part 192, and is currently
evaluating recommendations regarding potential changes to both Parts 192 and 195. 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 conforms to
federal standards. We accompany these assessments with a review of the data and repair anomalies, as required,
to ensure the integrity of the pipeline. We then utilize sophisticated risk algorithms and a comprehensive data
integration effort to ensure that the highest risk pipelines receive the highest priority for scheduling subsequent
integrity assessments. We use external coatings and impressed current cathodic protection systems to protect
against external corrosion. We conduct all cathodic protection work in accordance with National Association of
Corrosion Engineers standards. We continually monitor, test and record the effectiveness of these corrosion
inhibiting systems.
Pipeline Permitting
Pipeline construction and expansion is subject to government permitting and involves numerous regulatory
environmental, political and legal uncertainties, most of which are beyond our control. We believe our operations
are in substantial compliance with our permits.
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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 has 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. 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 pipeline systems 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
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 2,800 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.
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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 $4.9 billion as of December 31, 2016, and we may incur
significant additional debt obligations in the future. For example, in February 2017, we issued an additional
$2.25 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, including the dropdowns proposed by MPC, 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 sequestration, 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. Recessionary economic cycles, higher unemployment rates, higher fuel and other energy costs and
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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, and 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
fluctuation and decline in natural gas, NGL and oil prices currently occurring has adversely impacted 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.
46
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. The significant decline in oil prices that
occurred in 2015 and continued into 2016 has impacted our common unit price, as it has others in the energy
industry. Although oil prices have begun to recover late in 2016, there is no assurance that this recovery will
continue. The high and the low market price of our common units in 2016 ranged from a high of $39.46 to a low
of $16.34. Given the significant change in MLP valuations and the resultant higher distribution yield
environment the sector has experienced in 2015 and 2016, 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 distributions 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:
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•
•
•
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:
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•
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;
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•
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the cost of acquisitions, if any; and
the amount of cash reserves established by our general partner in its discretion.
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 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
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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.
Due to capacity, market and other constraints relating to the growth of our business, we may experience
difficulties in the execution of our business plan, which may increase our costs and reduce our revenues
and cash available for distribution.
The successful execution of our business strategy is impacted by a variety of factors, including our ability to
grow our business and satisfy our customers’ requirements for gathering, processing, fractionation, marketing,
transportation and storage services. Our ability to grow our business and satisfy our customers’ requirements may
be adversely affected by a variety of factors, including the following:
• more stringent permitting and other regulatory requirements;
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a limited supply of qualified fabrication and construction contractors, which could delay or increase the cost
of the construction and installation of our facilities or increase the cost of operating our existing facilities;
unexpected increases in the volume of oil, natural gas, NGLs and refined products being delivered to our
facilities, which could adversely affect our ability to expand our facilities in a manner that is consistent with
our customers’ production or delivery schedules;
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•
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changes in, or inability to meet, downstream gas, NGL, crude oil or refined product pipeline quality
specifications, which could reduce the volumes of gas, NGLs, crude oil and refined products that we
receive;
scheduled maintenance, unexpected outages or downtime at our facilities or at upstream or downstream
third-party facilities, which could reduce the volumes of oil, gas, NGLs and refined products that we
receive; and
• market and capacity constraints affecting downstream oil, natural gas, NGL and refined products facilities,
including limited gas and NGL capacity downstream of our facilities, limited railcar and NGL pipeline
facilities and reduced demand or limited markets for certain NGL or refined products, which could reduce
the volumes of oil, gas, NGLs and refined products that we receive and adversely affect the pricing received
for NGLs.
If we are unable to successfully execute our business strategy, then our operating and capital expenditures may
materially increase and our revenues and cash available for distribution may be adversely affected.
We engage in commodity derivative activities to mitigate the impact of commodity price volatility on our
cash flows, but these activities may reduce our earnings, profitability and cash flows. In addition, we may
not accurately predict future commodity price fluctuations, our risk management activities may impair
our ability to benefit from price increases, and additional regulation of commodity derivative activities
could adversely impact our ability to manage these risks.
Our operations expose us to fluctuations in commodity prices. We utilize derivative financial instruments related
to the future price of crude oil, natural gas and certain NGLs with the intent of reducing volatility in our cash
flows due to fluctuations in commodity prices.
The extent of our commodity price exposure is related largely to our contract mix and the effectiveness and scope
of our derivative activities. We have a policy to enter into derivative transactions related to only a portion of the
volume of our expected production or fuel requirements that are subject to commodity price volatility and, as a
result, we expect to continue to have some direct commodity price exposure. Our actual future production or fuel
requirements may be significantly higher or lower than we estimate at the time we enter into derivative
transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity
price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative
financial instruments, we might be forced to settle all or a portion of our derivative transactions without the
benefit of the cash flow from our sale or purchase of the underlying physical commodity, which could result in a
substantial diminution of our liquidity. Alternatively, we may seek to amend the terms of our derivative financial
instruments, including the extension of the settlement date of such instruments. Additionally, because we may
use derivative financial instruments relating to the future price of crude oil to mitigate our exposure to NGL price
risk, the volatility of our future cash flows and net income may increase if there is a change in the pricing
relationship between crude oil and NGLs. As a result of these factors, our risk management activities may not be
as effective as we intend in reducing the downside volatility of our cash flows and, in certain circumstances, may
actually increase the volatility of our cash flows. In addition, our risk management activities are subject to the
risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of
the derivative instruments are imperfect and our risk management policies and procedures are not properly
followed. For further information about our risk management policies and procedures, please read Item 8.
Financial Statements and Supplementary Data—Note 16. Derivative Financial Instruments.
To the extent that we do not manage the commodity price risk relating to a position that is subject to commodity
price risk and commodity prices move adversely, we could suffer losses. Such losses could be substantial and
could adversely affect our operations and cash flows available for distribution. In addition, managing the
commodity risk may actually reduce our opportunity to benefit from increases in the market or spot prices.
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As a result of the Dodd-Frank Act, 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
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.
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, particularly to the extent sales are denominated in foreign currencies as we do not
currently hedge against currency fluctuations;
compliance with additional governmental regulations and maritime requirements, including U.S. export
controls and foreign laws, sanctions regulations and the Foreign Corrupt Practices Act;
risks of loss resulting from non-payment or non-performance by international purchasers; and
political and economic disturbances in the countries to which NGLs are being exported.
The above factors could increase our operating costs or adversely affect the price that we and our producer
customers receive for NGLs, which in turn may have a material adverse effect on our volumes, revenues, income
and cash available for distribution.
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We depend on third parties for the oil, natural gas and refined products we gather, transport and store,
the natural gas and refinery off-gas we process, and the NGLs we fractionate and stabilize at our facilities,
and a reduction in these quantities could reduce our revenues and cash flow.
Although we obtain our supply of oil, natural gas, refinery off-gas, NGLs and refined products from numerous
third-party producers and suppliers, a significant portion comes from a limited number of key producers/
suppliers, who are usually under no obligation to deliver a specific volume to our facilities. If these key suppliers,
or a significant number of other producers, were to decrease the supply of oil, natural gas, refinery off-gas, NGLs
or refined products to our systems and facilities for any reason, we could experience difficulty in replacing those
lost volumes. In some cases, the producers or suppliers are responsible for gathering or delivering oil, natural
gas, refinery off-gas, NGLs or refined products to our facilities or we rely on other third parties to deliver
volumes to us on behalf of the producers or suppliers. If such producers, suppliers or other third parties are
unable, or otherwise fail to, deliver the volumes to our facilities, or if our agreements with any of these third
parties terminate or expire such that our facilities are no longer connected to their gathering or transportation
systems or the third parties modify the flow of natural gas, refinery off-gas or NGLs on those systems away from
our facilities, the throughput on and utilization of our facilities may be reduced, or we may be required to incur
significant capital expenditures to construct and install gathering pipelines or other facilities to be able to receive
such volumes. Because our operating costs are primarily fixed, a reduction in the volumes delivered to us would
result not only in a reduction of revenues, but also a decline in net income and cash flow.
We may not be able to retain existing customers, or acquire new customers, which would reduce our
revenues and limit our future profitability.
A significant portion of our business comes from a limited number of key customers. The renewal or replacement
of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends
on a number of factors beyond our control, including competition from other gatherers, processors, pipelines, and
fractionators, and the price of, and demand for, natural gas, NGLs, crude oil and refined products in the markets
we serve. Our competitors include large oil, natural gas, refining and petrochemical companies, some of which
have greater financial resources, more numerous or greater capacity pipelines, processing and other facilities,
greater access to natural gas, crude oil and NGL supplies than we do or other synergies with existing or new
customers that we cannot provide. Our competitors may also include our joint venture partners, who in some
cases are permitted to compete with us and may have a competitive advantage due to their familiarity with our
business arising from our joint venture arrangements, as well as third parties on whom we rely to deliver natural
gas, NGLs, crude oil and refined products to our facilities, who may have a competitive advantage due to their
ability to modify the flow of natural gas, NGLs, crude oil and refined products on their systems away from our
facilities. Additionally, our customers that gather gas through facilities that are not otherwise dedicated to us may
develop their own processing and fractionation facilities in lieu of using our services.
As a consequence of the increase in competition in the industry, and the volatility of natural gas prices, end-users
and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from
more than one natural gas company and have the ability to change providers at any time. Some of these end-users
also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the
market. Because there are numerous companies of greatly varying size and financial capacity that compete with
us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis
of price. The inability of our management to renew or replace our current contracts as they expire and to respond
appropriately to changing market conditions could affect our profitability.
The fees charged to third parties under our gathering, processing, transmission, transportation,
fractionation, stabilization and storage agreements may not escalate sufficiently to cover increases in costs,
or the agreements may not be renewed or may be suspended in some circumstances.
Our costs may increase at a rate greater than the fees we charge to third parties. Furthermore, third parties may
not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us
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may be permanently or temporarily reduced due to certain events, some of which are beyond our control,
including force majeure events wherein the supply of natural gas, NGLs, crude oil or refined products are
curtailed or cut-off due to events outside our control. 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 due to the sustained decline of natural gas, NGL and oil
prices that has occurred. 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, including the dropdowns proposed by MPC, 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, including the dropdowns proposed by MPC. Any acquisitions, including the
dropdowns proposed by MPC, involve potential risks, including, amongst others:
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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;
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.
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If we are unable to timely and successfully integrate the MarkWest Merger or our future acquisitions,
including the dropdowns proposed to MPC, 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 MarkWest Merger, the assets we may acquire in the dropdowns proposed
by MPC, or any other acquisitions into our existing operations, or that we will achieve the desired profitability
and anticipated results from such acquisitions. Failure to achieve such planned results could adversely affect our
operations and cash available for distribution.
Significant acquisitions, including the MarkWest Merger and dropdowns proposed by MPC, 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.
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
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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 and NGL pipelines, and various of our crude oil and refined product pipelines are, or
may in the future be, subject to siting, public necessity and/or service regulations by FERC and/or various state
or other regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural
gas, NGLs, crude oil and refined products in interstate commerce and FERC’s regulatory authority includes:
facilities construction, acquisition, extension or abandonment of services or facilities (for natural gas pipelines
only); rates; operations; accounts and records; and depreciation and amortization policies. FERC’s action in any
of these areas or modifications of its current regulations can adversely impact our ability to compete for business,
the costs we incur in our operations, the construction of new facilities or our ability to recover the full cost of
operating our pipelines. FERC also may conduct audits of these facilities, and if FERC determines that we are
not in compliance with our tariff or applicable regulations, we may incur additional costs, expenses or penalties.
For certain NGL product pipelines and for the crude oil and refined product common carrier pipelines, we have a
FERC tariff on file and we may have additional common carrier pipelines in the future that may be subject to
these requirements. We also own and are constructing pipelines that are carrying or are expected to carry NGLs
owned by us across state lines between our processing and fractionation facilities that we believe are either not
subject to FERC’s requirements for common carrier NGL pipelines or would otherwise meet the qualifications
for a waiver from many of FERC’s reporting and filing 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 for
common carrier pipelines and/or are otherwise not exempt from its reporting and filing 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.
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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—Rate and Other Regulation 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 the FERC. The FERC
prescribes rate methodologies for developing regulated tariff rates for these natural gas, interstate oil and
products pipelines. The FERC’s regulated tariff may not allow us to recover all of our costs of providing
services. Changes in the 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 the FERC may
investigate) the lawfulness of tariff rates. The 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
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 for land on which any of our processing
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 December 2015 and December 2016, and have indicated that additional interest rate increases may occur in
2017. As a result, interest rates on our debt could be higher than current levels, causing our financing costs to
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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 pipeline systems 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, 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.
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—
Rate and Other Regulation, Item 1. Business—Environmental Regulation, and Item 1. Business—Pipeline
Safety, 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 adopted regulations establishing PSD construction and Title V operating permit
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requirements for GHG emissions from certain large stationary sources that are potential major sources of certain
principal, or criteria, pollutant emissions. In addition, the EPA and states are gathering information on existing
facilities in various industries, which may be used to support potential future regulation of carbon emissions, and
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 EPA or states implemented more stringent permitting
requirements relating to GHG emissions without regard to non-GHG criteria pollutants, we may be required to
install “best available control technology” 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 our construction and operating costs may materially increase.
Congress has from time to time considered legislation to reduce emissions of GHGs, but, in the absence of
federal climate legislation in the United States in recent years, 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 to acquire and surrender emission allowances in return for
emitting those GHGs. If Congress were to undertake comprehensive tax reform, it is possible that such reform
may include a carbon tax, which could impose additional direct costs on operations and reduce demand for oil,
natural gas, NGLs and products derived therefrom.
These requirements or enforcement thereof, or the adoption of any new legislation or regulations that requires
additional reporting, monitoring or recordkeeping of GHGs, limits emissions of GHGs from our equipment and
operations, or imposes a carbon tax, could adversely affect our operations and materially restrict or delay our
ability to obtain air permits for new or modified facilities, could require us to incur costs to reduce emissions of
GHGs associated with our operations or could adversely affect demand for the oil and natural gas we process or
fractionate. In May 2016, EPA finalized new regulations that will set methane emission standards for new and
modified oil and gas production and natural gas processing and transmission facilities as part of the
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. Concurrently, the
Commonwealth of Pennsylvania has also proposed similar regulations that have not yet been finalized. 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. 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
Matters—Climate Change.
Finally, for a variety of reasons, natural and/or anthropogenic, some members of the scientific community
believe that climate changes could occur which could have significant physical effects, such as increased
frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to
occur, they could have an adverse effect on our assets and operations, which in turn could adversely affect our
cash available for distribution to our unitholders.
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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;
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.
In addition, the maximum civil penalty for federal pipeline safety violations has increased from $100,000 to
$200,000 per violation per day of violation and also from $1 million to $2 million for a related series of
violations. 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 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, MPC’s refining operations or in
our ability to gather, transport, or store natural gas, NGLs, crude oil or other refined products to or from these
facilities or pipelines for any reason, or to market or transport the natural gas, crude oil, NGLs or refined
products, would adversely affect our operations and cash flows available for distribution to our unitholders. In
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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 facilities or MPC’s refining operations 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.
Our operations depend on the use of information technology systems that could be the target of industrial
espionage or cyber-attack.
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. 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
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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 or damage our facilities or those of third parties, which could have a material adverse effect on our
revenues and increase our operating and capital costs, which could 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. To protect against
such attempts of unauthorized access or attack, we have implemented infrastructure protection technologies and
disaster recovery plans. There can be no guarantee such plans, to extent they are in place, will be effective.
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 2016 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, 2016, excluding revenues attributable to volumes shipped by MPC under joint
tariffs with third parties that were treated as third-party revenues for accounting purposes, MPC accounted for
approximately 30 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 pipeline systems or the
ability of MPC to utilize third-party pipeline connections to access our pipeline systems;
• 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
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.
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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 system 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 system 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 system 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, 2016, MPC had consolidated long-term
indebtedness of approximately $11 billion, of which $6 billion was a direct obligation of MPC. The covenants
contained in the agreements governing MPC’s outstanding and future indebtedness may limit its ability to
borrow additional funds for development and make certain investments and may directly or indirectly impact our
operations in a similar manner.
Furthermore, if MPC were to default under certain of its debt obligations, there is a risk that MPC’s creditors
would attempt to assert claims against our assets during the litigation of their claims against MPC. The defense
of any such claims could be costly and could materially impact our financial condition, even absent any adverse
determination. If these claims were successful, our ability to meet our obligations to our creditors, make
distributions and finance our operations could be materially and adversely affected.
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
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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 35 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.
The sale or exchange of 50 percent or more of our capital and profits interests during any twelve-month
period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated for federal income tax purposes if there is a sale or
exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. For
purposes of determining whether the 50 percent threshold has been met, multiple sales of the same interest will
be counted only once. Our technical termination would, among other things, result in the closing of our taxable
year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two
Schedules K-1) for one calendar year and could result in a significant deferral of depreciation deductions
allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a
calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income
or loss being includable in his taxable income for the year of termination. Our termination currently would not
affect our classification as a partnership for federal income tax purposes, but it would result in our being treated
as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make
new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The
IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated
requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a
single Schedule K-1 to unitholders for the tax years in which the termination occurs.
If the IRS contests the federal income tax positions we take, the market for our common units may be
adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.
The IRS has made no determination as to our status as a partnership for federal income tax purposes. The IRS
may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court
proceedings to sustain some or all the positions we take. A court may not agree with some or all of the positions
we take. Any contest with the IRS may materially and adversely impact the market for our common units and the
price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our
unitholders and our general partner because the costs will reduce our cash available for distribution.
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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
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
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approximately 16 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.
From time to time, members of Congress propose and consider substantive changes to the existing federal
income tax laws that affect publicly traded limited partnerships, including as a result of any fundamental tax
reform. 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
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taxes payable by unitholders in publicly traded partnerships. Any reductions to the U.S. federal income tax rates
applicable to individuals and corporations could cause the rate of return on investments in our common units to
be relatively less attractive as compared to investments in shares of corporations, which in turn could adversely
affect our unit price and increase our cost of capital. In addition, as to possible additional legislation, including
any fundamental tax reform, we cannot predict whether any proposals will be introduced, reintroduced or
ultimately enacted. Any such changes could affect us and negatively impact the value of an investment in our
units.
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 an approximate 23.5 percent limited partner interest (including the Class B
units on an as-converted basis) in us as of February 13, 2017. 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
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may occur under our partnership agreement without being independently reviewed by the conflicts committee.
These conflicts include, among others, the following situations:
•
neither our partnership agreement nor any other agreement requires MPC to pursue a business strategy that
favors us or utilizes our assets, which could involve decisions by MPC to increase or decrease refinery
production, shut down or reconfigure a refinery, or pursue and grow particular markets. MPC’s directors
and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of MPC;
• MPC, as a significant customer, has an economic incentive to cause us to not seek higher tariff rates, even if
such higher rates or fees would reflect rates and fees that could be obtained in arm’s-length, third-party
transactions;
• MPC may be constrained by the terms of its debt instruments from taking actions, or refraining from taking
actions, that may be in our best interests;
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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, even if the
borrowing is to allow us to pay the general partner’s incentive distribution rights;
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 in respect of the general
partner interest or the incentive distribution rights;
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;
our general partner decides whether to retain separate counsel, accountants or others to perform services for
us; and
our general partner may elect to cause us to issue common units to it in connection with a resetting of the
target distribution levels related to our general partner’s incentive distribution rights without the approval of
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the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts
committee, or our unitholders. This election may result in lower distributions to our common unitholders in
certain situations.
Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine,
does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners.
Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter
that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any
such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other
duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such
opportunity to another person or entity or does not communicate such opportunity or information to us. This may
create actual and potential conflicts of interest between us and affiliates of our general partner and result in less
than favorable treatment of us and our unitholders.
Our partnership agreement requires that we distribute all of our available cash, which could limit our
ability to grow and make acquisitions.
Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we
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 general partner has certain incentive distribution rights that reduce the amount of our cash available
for distribution to our common unitholders.
Our general partner currently holds a general partner interest in us that entitles it to receive two percent of all
distributions paid to our common unitholders and incentive distribution rights that entitle it to receive an
increasing percentage (13 percent, 23 percent and 48 percent) of the cash that we distribute to our common
unitholders from available cash after the minimum quarterly distribution and certain target distribution levels
have been achieved. The maximum distribution right for our general partner to receive 48 percent of any
distributions paid to our common unitholders does not include any distributions that our general partner or its
affiliates may receive on common or general partner units that they own. Throughout 2016, our general partner
was at the top tier of the incentive distribution rights scale. Because a higher percentage of our cash is allocated
to our general partner due to these incentive distribution rights, it will be more difficult for us to increase the
amount of distributions to our unitholders and our cost of capital will be higher, making investments, capital
expenditures and acquisitions, and therefore, future growth, by us more costly. In January 2017, MPC announced
that it expects to exchange the general partner’s incentive distribution rights for common units in conjunction
with the completion of the expected dropdowns of midstream assets. However, there is no assurance that this
transaction will occur in 2017, or at all. If such a transaction does occur, it would likely result in a substantial
increase in the number of common units outstanding. As a result, our unitholders’ proportionate ownership in us
will decrease, it may be more difficult for us to maintain or increase our distributions to unitholders and the
amount of cash available for distribution for each unit may decrease, the relative voting strength of each
previously outstanding unit may be diminished and the market price of our common units may decline.
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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:
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provides that whenever our general partner makes a determination or takes, or declines to take, any other
action in its capacity as our general partner, our general partner is required to make such determination, or
take or decline to take such other action, in good faith and will not be subject to any other or different
standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at
equity;
provides that our general partner will not have any liability to us or our unitholders for decisions made in its
capacity as a general partner so long as it acted in good faith;
provides that our general partner and its officers and directors will not be liable for monetary damages to us
or our limited partners resulting from any act or omission unless there has been a final and non-appealable
judgment entered by a court of competent jurisdiction determining that our general partner or its officers and
directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a
criminal matter, acted with knowledge that the conduct was criminal; and
provides that our general partner will not be in breach of its obligations under our partnership agreement or
its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a
conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our
partnership agreement.
In connection with a transaction with an affiliate or a conflict of interest, our partnership agreement provides that
any determination by our general partner must be made in good faith, and that our conflicts committee and the
board of directors of our general partner are entitled to a presumption that they acted in good faith. In any
proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting
such proceeding will have the burden of overcoming such presumption. By purchasing a common unit, a
unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions
discussed above.
Unitholders have very limited voting rights and, even if they are dissatisfied, they have limited ability to
remove our general partner without its consent.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters
affecting our business and, therefore, limited ability to influence management’s decisions regarding our business.
Unitholders did not elect our general partner or the board of directors of our general partner and will have no
right to elect our general partner or the board of directors of our general partner on an annual or other continuing
basis. The board of directors of our general partner is chosen by the members of our general partner, which are
wholly-owned subsidiaries of MPC. Furthermore, if the unitholders are dissatisfied with the performance of our
general partner, they will have little ability to remove our general partner. The vote of the holders of at least 66 2⁄ 3
percent of all outstanding common units voting together as a single class is required to remove our general
71
partner. As of February 13, 2017, our general partner and its affiliates owned approximately 24.2 percent of the
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.
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.
72
Our general partner interest, the control of our general partner and the incentive distribution rights of our
general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or
substantially all of its assets without the consent of the unitholders. Furthermore, 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.
Additionally, our general partner may transfer its incentive distribution rights to a third party at any time without
the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but
retains its general partner interest, our general partner may not have the same incentive to grow our partnership
and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its
incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could
reduce the likelihood of MPC selling or contributing additional midstream assets to us, as MPC would have less
of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
We may issue additional units without unitholder approval, which will dilute limited unitholder interests.
At any time, including in connection with the dropdowns proposed by MPC, 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,
Class B 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 December 31, 2016, MPC held 86,619,313 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
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.
73
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.
Our general partner, or any transferee holding incentive distribution rights, may elect to cause us to issue
common units and general partner units to it in connection with a resetting of the target distribution levels
related to its incentive distribution rights, without the approval of our conflicts committee or the holders of
our common units. This could result in lower distributions to holders of our common units.
Our general partner has the right, at any time when there are no subordinated units outstanding and it has
received distributions on its incentive distribution rights at the highest level to which it is entitled (48 percent, in
addition to distributions paid on its two percent general partner interest, each as of December 31, 2016) for each
of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on
our distributions at the time of the exercise of the reset election. Following a reset election, the minimum
quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target
distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset
minimum quarterly distribution.
74
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of
common units and general partner units. The number of common units to be issued to our general partner will be
equal to that number of common units that would have entitled their holder to an average aggregate quarterly
cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the
incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of
general partner units necessary to maintain our general partner’s interest in us at the level that existed
immediately prior to the reset election. We anticipate that our general partner would exercise this reset right to
facilitate acquisitions or internal growth projects that would not be sufficiently accretive to distributions per
common unit without such conversion. It is possible, however, that our general partner could exercise this reset
election at a time when it is experiencing, or expects to experience, declines in the distributions it receives related
to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the
right to receive distributions based on the initial target distribution levels. This risk could be elevated if our
incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our
common unitholders to experience a reduction in the amount of distributions that they would have otherwise
received had we not issued new common units and general partner units in connection with resetting the target
distribution levels. Additionally, our general partner has the right to transfer all or any portion of our incentive
distribution rights at any time, and such transferee shall have the same rights as the general partner relative to
resetting target distributions if our general partner concurs that the tests for resetting target distributions have
been fulfilled.
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
75
Item 2. Properties
LOGISTICS AND STORAGE
Crude Oil Pipeline Systems
The following table sets forth certain information regarding our crude oil pipeline systems as of December 31,
2016, each of which has an associated transportation services agreement with MPC (other than the inactive
pipelines):
System name
Patoka to Lima crude system
Patoka, IL to Lima, OH
Catlettsburg and Robinson crude system
Patoka, IL to Robinson, IL
Patoka, IL to Catlettsburg, KY
Subtotal
Detroit crude system
Samaria, MI to Detroit, MI
Romulus, MI to Detroit, MI(2)
Subtotal
Wood River to Patoka crude system
Wood River, IL to Patoka, IL
Roxanna, IL to Patoka, IL(3)
Subtotal
Inactive pipelines
Diameter
(inches)
Length
(miles)
Capacity
(mbpd)(1)
Associated MPC refineries
20”/22”
20”
24”/20”
16”
16”
22”
12”
304
78
406
484
44
17
61
57
58
115
44
267 Detroit, MI; Canton, OH
245 Robinson, IL
270 Catlettsburg, KY
515
117 Detroit, MI
80 Detroit, MI
197
215 All Midwest refineries
99 All Midwest refineries
314
N/A
Total crude oil pipelines
1,008
1,293
(1) Capacity shown is 100 percent of the capacity of these pipeline systems 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)
Our crude oil pipeline systems 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 system; Western Canada,
Wyoming and North Dakota on the Keystone, Platte, Mustang and Enbridge pipeline systems; and the Gulf Coast
on the Capline crude oil pipeline system. Our major crude oil pipeline systems are connected to these supply
hubs and transport crude oil to refineries owned by MPC and third parties.
76
Product Pipeline Systems
The following table sets forth certain information regarding our product pipeline systems as of December 31,
2016, each of which has an associated transportation services agreement with MPC (other than our Louisville
airport products system, which currently transports only third-party volumes, and the inactive pipelines):
System name
Cornerstone products system
Diameter
(inches)
Length
(miles)
Capacity
(mbpd)(1)
Associated MPC refineries
Cornerstone to East Sparta, OH
East Sparta, OH to Canton, OH
16”
8”
Subtotal
Garyville products system
50
8
58
198
40
238
Canton, OH
Canton, OH
Garyville, LA to Zachary, LA
Zachary, LA to connecting pipelines(2)
20”
36”
389
70
2 —
Garyville, LA
Garyville, LA
Subtotal
Texas City products system
Texas City, TX to Pasadena, TX
Pasadena, TX to connecting
16”
72
39
389
215
Texas City, TX; Galveston Bay, TX
pipelines(2)
Subtotal
ORPL products system
36”/30”
3 —
Texas City, TX; Galveston Bay, TX
42
215
Kenova, WV to Columbus, OH
Canton, OH to East Sparta, OH(3,4)
East Sparta, OH to Heath, OH(4)
East Sparta, OH to Midland, PA(4)
Heath, OH to Dayton, OH
Heath, OH to Findlay, OH
14”
6”
8”
8”
6”
10”/8”
Subtotal
Robinson products system
Robinson, IL to Lima, OH
Robinson, IL to Louisville, KY (5)
Robinson, IL to Mt. Vernon, IN(6)
Wood River, IL to Clermont, IN
Wabash Pipeline System:
West leg—Wood River, IL to
Champaign, IL
East leg—Robinson, IL to
Champaign, IL
Champaign, IL to Hammond,
IN(7)
Subtotal
10”
16”
10”
10”
12”
12”
150
17
81
62
108
100
518
250
129
79
317
130
86
68
73
29
32
24
18
244
51
82
77
48
71
99
85
Louisville airport products system
Louisville, KY to Louisville
International Airport
8”/6”
Inactive pipelines(8)
Total product pipelines
16”/12”
140
1,131
513
14
123
29
N/A
1,958
1,628
Catlettsburg, KY
Canton, OH
Canton, OH
Canton, OH
Catlettsburg, KY; Canton, OH
Catlettsburg, KY; Canton, OH
Robinson, IL
Robinson, IL
Robinson, IL
Robinson, IL
Robinson, IL
Robinson, IL
Robinson, IL
Robinson, IL
(1) Capacity shown is 100 percent of the capacity of these pipeline systems.
77
(2) Capacity not shown, as the pipeline is designed to meet outgoing capacity for connecting third-party
pipelines.
(3) Consists of two separate approximately 8.5-mile pipelines.
(4)
This pipeline is bi-directional.
(5) Drag-reducing agent for this pipeline is currently not active and can be reactivated at any time resulting in a
capacity increase of 10 mbpd.
This pipeline is leased from a third party.
(6)
(7) Capacity not shown for 16 miles on this system due to complexities associated with bi-directional
capability.
Includes 77 miles of pipeline leased from a third party.
(8)
Our product pipeline systems 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 pipeline systems also supply feedstocks to
MPC’s Midwest refineries. These product pipeline systems are integrated with MPC’s expansive network of
refined product marketing terminals, which support MPC’s integrated midstream business.
Marine Assets
The following table sets forth certain information regarding our marine assets as of December 31, 2016. The
marine business currently has an associated transportation service agreement with MPC.
Asset name
Quantity
Associated MPC refineries
Barges
Towboats
Marine Repair Facility
204
18
N/A
Catlettsburg, KY; Garyville, LA
Catlettsburg, KY; Garyville, LA
Catlettsburg, KY
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, 2016,
each of which currently has an associated transportation services agreement or storage services agreement with
MPC:
Asset name
Capacity(1)
Associated MPC refineries
Wood River Barge Dock
Neal Butane Cavern
Patoka Tank Farm
Wood River Tank Farm
Martinsville Tank Farm
Lebanon Tank Farm
Hartford Tank Farm(2)
78 mbpd
1,000 mbbls
2,626 mbbls
419 mbbls
738 mbbls
750 mbbls
430 mbbls
Garyville, LA
Catlettsburg, KY
All Midwest refineries
All Midwest refineries
Detroit, MI; Canton, OH
Detroit, MI; Canton, OH
All Midwest refineries
(1) All capacity shown is for 100 percent of the available storage capacity of our butane cavern and tank farms
and 100 percent of the barge dock’s average capacity.
(2) MPLX LP leases the Hartford Tank Farm from Wood River Pipe Lines LLC and Buckeye Terminals, LLC.
78
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, 2016. All throughputs and utilizations included are weighted-averages
for days in operation.
Gas Processing Complexes
Plant
Marcellus Shale:
Keystone Complex
Houston Complex(5)
Majorsville Complex
Mobley Complex
Sherwood Complex
Total Marcellus Shale
Utica Shale:
Cadiz Complex
Seneca Complex
Total Utica Shale
Southern Appalachia:
Kenova Complex(2)
Boldman Complex(2)
Cobb Complex
Kermit Complex(2)(3)
Langley Complex
Total Southern Appalachia(3)
Southwest:
Carthage Complex
Western Oklahoma Complex
Hidalgo Complex
Javelina Complex
Total Southwest(4)
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
555
1,070
920
1,200
4,155
525
800
1,325
160
70
65
32
325
620
600
425
200
142
265
446
789
690
1,020
3,210
477
595
1,072
102
30
22
N/A
99
253
493
333
105
99
1,367
7,467
1,030
5,565
65%
80%
74%
80%
85%
78%
91%
74%
81%
64%
43%
34%
N/A
30%
41%
82%
78%
81%
70%
79%
76%
(1) Natural gas throughput is a weighted average for days in operation. The utilization of design capacity has
been calculated using the weighted average design throughput capacity.
(2) A portion of the gas processed at the Boldman plant, and all of the gas processed at the Kermit plant, is
(3)
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 capacity
has been excluded from the subtotal.
(4) Centrahoma processing capacity of 300 mmcf/d and actual throughput of 196 mmcf/d, that exceeded our
capacity of 120 mmcf/d, are not included in this table as we own a non-operating interest.
(5) Approximately 35 mmcf/d of processing capacity at the Houston Complex will be decommissioned during
the first quarter of 2017 and replaced with 200 mmcf/d of processing capacity.
79
Fractionation & Condensate Stabilization Facilities
Facility
Marcellus Shale:
Keystone Complex(1)(2)
Houston Complex(1)
Total Marcellus Shale
Hopedale Complex(1)(3)
Utica Shale:
Ohio Condensate Complex(4)
Total Utica Shale
Southern Appalachia:
Siloam Complex(5)
Total Southern Appalachia
Southwest:
Javelina Complex
Total Southwest
Total C3+ Fractionation and
Condensate Stabilization
Location
Design
Throughput
Capacity
(mbpd)
NGL
Throughput
(mbpd)
Utilization of
Design
Capacity
Butler County, PA
Washington County, PA
Harrison County, OH
Harrison County, OH
South Shore, KY
Corpus Christi, TX
47
60
107
120
23
23
24
24
11
11
14
60
74
110
14
14
15
15
7
7
285
220
30%
100%
69%
92%
61%
61%
63%
63%
64%
64%
77%
(1) Our Houston, Hopedale and Keystone Complexes have above-ground NGL storage with a usable capacity
of 28 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 9 million gallons of butane storage
and 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.
(2)
(3) Our Hopedale Complex 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. We account for
MarkWest Utica EMG as an equity method investment. See discussion in Item 8. Financial Statements and
Supplementary Data—Note 5.
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.
(4)
(5) 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
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 barges up to 860,000 gallons.
80
De-ethanization Facilities
Facility
Marcellus Shale:
Keystone Complex
Houston Complex
Majorsville Complex
Mobley Complex
Sherwood Complex
Total Marcellus Shale
Utica Shale:
Cadiz Complex
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
14
40
40
10
40
144
40
40
18
18
202
11
37
42
6
18
114
4
4
11
11
129
79%
93%
105%
82%
45%
80%
10%
10%
61%
61%
64%
(1) NGL throughput is a weighted average for days in operation. The utilization of design capacity has been
calculated using the weighted average design throughput capacity.
81
Natural Gas Gathering Systems
System
Marcellus Shale:
Keystone 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
984
1,211
1,393
250
1,643
194
716
910
867
65
932
85%
74%
77%
63%
26%
58%
680
578
85%
585
1,205
45
70
2,585
5,439
364
449
31
11
1,433
3,275
62%
37%
69%
16%
55%
61%
(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 Ohio Gathering 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 consolidated 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)
82
NGL Pipelines
Pipeline
Location
Design
Throughput
Capacity
(mbpd)
NGL
Throughput
(mbpd)
Utilization of
Design
Capacity
Marcellus Shale:
Sherwood to Mobley propane and
heavier liquids pipeline
Mobley to Majorsville propane and heavier
liquids pipeline
Majorsville to Houston propane and heavier
liquids pipeline
Majorsville to Hopedale propane and heavier
liquids pipeline
Third-party processing plant to Keystone
ethane and heavier liquids pipeline
Keystone 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 Fort Beeler ethane pipeline
Fort Beeler to Majorsville ethane pipeline
Utica Shale:
Seneca to Cadiz liquids pipeline
Cadiz to Hopedale liquids pipeline
Appalachia:
Langley to Siloam liquids pipeline(3)
Southwest:
East Texas liquids pipeline
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
Marshall County, WV
Noble County, OH to
Harrison County, OH
Harrison County, OH
Langley, KY to South
Shore, KY
Panola County, TX
45
80
47
90
32
35
57
60
27
64
45
90
90
17
39
40
64
34
72
7
12
16
66
18
24
24
20
38
12
27
89%
80%
72%
80%
22%
34%
28%
110%
67%
38%
53%
22%
42%
71%
69%
(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.
(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.
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,
2016, NGL throughput on this pipeline was 9 mbpd, which was approximately 15 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,
83
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, Keystone, 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.
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.
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
84
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.
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.
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. The IEPA and the EPA may each seek
penalties in connection with this matter. The IEPA and the EPA may each seek
penalties in excess of $100,000 in connection with this matter.
On February 17, 2016, MarkWest Liberty Bluestone, L.L.C. (“MarkWest Liberty Bluestone”), received an initial
Consent Agreement and Final Order (“Initial CAFO”) from the EPA alleging violations of the Clean Air Act
resulting from an EPA compliance inspection conducted in July 2012 at our Sarsen Facility, a gas processing
facility at our Keystone Complex located in Pennsylvania. The alleged violations included the failure to comply
with monitoring, tagging, recordkeeping and repair requirements with respect to certain pumps and/or valves at
the facility and with certain emissions reduction and permit application requirements. The Initial CAFO set forth
a proposed penalty of $285,000. After subsequent negotiations, MarkWest Liberty Bluestone has agreed in
principle to a Consent Agreement and Final Order resolving these issues, pursuant to which MarkWest Liberty
Bluestone would pay a penalty of $95,000 and implement certain enhancements in connection with its existing
leak monitoring program.
MarkWest Liberty Midstream, MarkWest Ohio Fractionation Company, L.L.C. (“Ohio Fractionation”) and
MarkWest Utica EMG are in settlement discussions with the EPA relating to certain notices of violation alleging
claims regarding fugitive emissions and violations of the Clean Air Act at our Hopedale Complex, a fractionation
facility located in Ohio (issued October 7, 2015 and June 27, 2016), our Houston Complex, a gas processing
facility located in Pennsylvania (issued April 5, 2016) and our Seneca Complex, a gas processing facility located
in Ohio (issued September 9, 2016). In connection with a proposed global settlement which would cover nineteen
gas processing and fractionation sites, MarkWest Liberty Midstream, Ohio Fractionation and MarkWest Utica
EMG, together with other MarkWest affiliates, have agreed in principle to pay a penalty of approximately
$0.9 million, undertake certain monitoring and emission reduction projects at certain facilities with an estimated
cost of approximately $3.3 million, and implement certain process enhancements for its and its affiliates’ leak
detection and repair programs at the nineteen gas processing and fractionation sites.
In July 2015, representatives from the EPA and the United States Department of Justice conducted a raid on a
MarkWest Liberty Midstream pipeline launcher/receiver site utilized for pipeline maintenance operations in
Washington County, Pennsylvania pursuant to a search warrant issued by a magistrate of the United States
District Court for the Western District of Pennsylvania. As part of this initiative, the U.S. Attorney’s Office for
the Western District of Pennsylvania proceeded with an investigation of MarkWest Liberty Midstream’s
launcher/receiver, pipeline and compressor station operations. In response to the investigation, MarkWest
85
initiated independent studies which demonstrated that there was no risk to worker safety and no threat of public
harm associated with MarkWest Liberty Midstream’s launcher/receiver operations. These findings were
supported by a subsequent inspection and review by the Occupational Safety and Health Administration. After
providing these studies, and other substantial documentation related to MarkWest Liberty Midstream’s pipeline
and compressor stations, and arranging site visits and conducting several meetings with the government’s
representatives, on September 13, 2016, the U.S. Attorney’s Office for the Western District of Pennsylvania
rendered a declination decision, dropping its criminal investigation and declining to pursue charges in this matter.
MarkWest Liberty Midstream continues to discuss with the EPA and the State of Pennsylvania civil enforcement
allegations associated with permitting or other related regulatory obligations for its launcher/receiver and
compressor station facilities in the region. In connection with these discussions, MarkWest Liberty Midstream
received an initial proposal from the EPA to settle all civil claims associated with this matter for the combination
of a proposed cash penalty of approximately $2.4 million and proposed supplemental environmental projects
with an estimated cost of approximately $3.6 million. MarkWest Liberty Midstream will be submitting a
response asserting that this action involves novel issues surrounding primarily minor source emissions from
facilities that the agencies themselves considered de minimis and were not subject to regulation and consequently
that the settlement proposal is excessive. MarkWest will continue to negotiate with EPA regarding the amount
and scope of the proposed settlement.
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
86
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 13, 2017, there were 365 registered holders of 270,638,348 outstanding common units held by the
public, including 267,225,173 common units held in street name. In addition, as of February 13, 2017, MPC and
its affiliates owned 86,619,313 of our common units, and 7,372,419 of our general partner units, which together
constitutes a 25.5 percent ownership interest (including the Class B units on an as-converted basis).
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, 2016
September 30, 2016
June 30, 2016
March 31, 2016
December 31, 2015
September 30, 2015
June 30, 2015
March 31, 2015
$35.32
35.12
34.92
39.46
45.63
71.73
80.00
85.57
$30.09
30.36
26.75
16.34
26.38
35.55
70.23
65.29
February 6, 2017
February 14, 2017
$0.5200
0.5150 November 14, 2016 November 4, 2016
0.5100 August 12, 2016
0.5050 May 13, 2016
0.5000
0.4700 November 13, 2015 November 3, 2015
0.4400 August 14, 2015
0.4100 May 15, 2015
August 2, 2016
May 3, 2016
February 4, 2016
August 4, 2015
May 5, 2015
February 12, 2016
(1) Represents cash distributions attributable to the quarter and declared and paid in accordance with our
partnership agreement.
We intend to pay a minimum quarterly distribution of $0.2625 per unit. Although our partnership agreement
requires that we distribute all of our available cash each quarter, we do not have a legal obligation to distribute
any particular amount per common unit.
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. Class B unitholders do not receive cash
distributions.
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,
anticipated future debt service requirements and refunds of collected rates reasonably likely to be
refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings
under applicable law subsequent to that quarter);
comply with applicable law, any of our debt instruments or other agreements; 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 and any cumulative arrearages on such common units for the current
quarter);
87
•
plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination
of available cash for the quarter 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 and subordinated units of $0.2625 per
unit, or $1.05 per unit on an annualized basis, to the extent we have sufficient cash from our operations after the
establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to
our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our
units in any quarter. The amount of distributions paid under our policy and the decision to make any distribution
is determined by our general partner, taking into consideration the terms of our partnership agreement. See
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and
Capital Resources—Debt and Liquidity Overview, for a discussion of the restrictions included in our bank
revolving credit facility that may restrict our ability to make distributions.
General Partner Interest and Incentive Distribution Rights. Our general partner is currently entitled to
two percent of all quarterly distributions that we make prior to our liquidation. Our general partner has the right,
but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner
interest. The general partner’s two percent interest in these distributions will be reduced if we issue additional
units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain
its two percent general partner interest.
Our general partner also currently holds incentive distribution rights that entitle it to receive increasing
percentages, up to a maximum of 48 percent, of the cash we distribute from operating surplus in excess of
$0.301875 per unit per quarter. The maximum distribution of 48 percent does not include any distributions that
our general partner or its affiliates may receive on common, subordinated or general partner units that they own.
Percentage Allocations of Available Cash. The following table illustrates the percentage allocations of available
cash from operating surplus between the common unitholders and our general partner based on the specified
target distribution levels. The amounts set forth under “Marginal percentage interest in distributions” are the
percentage interests of our general partner and the common unitholders in any available cash from operating
surplus we distribute up to and including the corresponding amount in the column “Total quarterly distribution
per unit target amount.” The percentage interests shown for our common unitholders and our general partner for
the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the
minimum quarterly distribution. The percentage interests set forth below for our general partner include its two
percent general partner interest and assume that our general partner has contributed any additional capital
necessary to maintain its two percent general partner interest, that our general partner has not transferred its
incentive distribution rights and that there are no arrearages on common units.
Minimum Quarterly Distribution
First Target Distribution
Second Target Distribution
Third Target Distribution
Thereafter
Marginal percentage interest
in distributions
Total quarterly distribution
per unit target amount
Unitholders(1) General Partner
$0.2625
above $0.2625
above $0.301875
above $0.328125
above $0.393750
up to $0.301875
up to $0.328125
up to $0.393750
98.0%
98.0%
85.0%
75.0%
50.0%
2.0%
2.0%
15.0%
25.0%
50.0%
(1)
The unitholders’ percentage of distributions is paid to common unitholders and subordinated unitholders, if
any.
88
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 the quarterly distributions on each
Preferred unit will equal 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, the Class B units and the incentive distribution rights, 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.
89
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. The information in
Items 6, 7 and 8 includes periods prior to the acquisition of HSM by MPLX LP, which occurred on March 31,
2016. Consequently, the Partnership’s consolidated financial statements have been retrospectively recast for all
periods presented to include the historical results of HSM, as required for transactions between entities under
common control. See Item 8. Financial Statements and Supplementary Data—Note 4 and Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations for more information on the
MarkWest Merger and acquisition of HSM.
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)
2016
2015
2014
2013
2012
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
Adjusted EBITDA attributable to MPLX LP(2)
DCF(2)
90
$
$ 2,590
507
258
233
1
$
$
961
298
249
156
99
793
245
239
121
115
$
713
213
211
78
76
686
204
204
13
13
$ — $
—
—
1.23
1.22
0.11
$
$
1.55
1.55
1.50
$
1.05
1.05
1.01
0.18
0.18
0.17
$2.0500
$1.8200
$1.4100
$1.1675
$0.1769
$10,730
16,646
4,422
1,000
$ 9,997
16,104
5,255
—
$ 1,324
1,544
644
—
$ 1,248
1,504
10
—
$ 1,167
1,572
10
—
$ 1,288
(1,212)
115
1,206
$ 1,419
1,140
$
$
340
(1,599)
1,275
288
498
399
$
$
$
$
334
(137)
(224)
141
166
137
$
$
297
(158)
(302)
151
111
114
273
64
(120)
159
18
17
(1) Represents cash capital expenditures as reflected on Consolidated Statements of Cash Flows for the periods
(2)
(3)
indicated, which are included in cash used in investing activities.
The 2012 Adjusted EBITDA attributable to MPLX LP is subsequent to the Initial Offering. 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 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.
Includes amounts due within one year. 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 $943 million of borrowings under MarkWest’s credit facility.
91
Operating Data
L&S
Crude oil transported for (mbpd)(1):
MPC
Third parties
Total
% MPC
Products transported for (mbpd)(2):
MPC(3)
Third parties
Total
% MPC
Average tariff rates ($ per barrel):
Crude oil pipelines
Product pipelines
Total pipelines
Barges(4)
Towboats(4)
G&P(5)
Gathering Throughput (mmcf/d)
Marcellus Operations
Utica Operations(6)(7)
Southwest Operations(8)
Total gathering throughput
Natural Gas Processed (mmcf/d)
Marcellus Operations
Utica Operations(6)
Southwest Operations
Southern Appalachian Operations
Total natural gas processed
C2 + NGLs Fractionated (mbpd)
Marcellus Operations(9)(10)
Utica Operations(6)(10)
Southwest Operations
Southern Appalachian Operations(11)
Total C2 + NGLs fractionated(12)
Pricing Information
2016
2015
2014
2013
2012
906
182
864
197
838
203
853
222
830
202
1,088
1,061
1,041
1,075
1,032
83%
81%
80%
79%
80%
862
49
911
95%
0.60
0.56
0.58
184
17
909
71
980
93%
0.57
0.51
0.54
177
15
763
145
908
84%
887
27
914
97%
852
26
878
97%
0.64
0.61
0.63
199
18
0.67
0.69
0.68
204
18
910
932
1,433
3,275
3,210
1,072
1,226
253
5,761
260
42
18
15
335
0.66
0.65
0.65
205
18
889
745
1,441
3,075
2,964
1,136
1,125
243
5,468
220
51
24
12
307
Natural Gas NYMEX HH ($/MMBtu)
C2 + NGL Pricing/gallon(13)
$ 2.55
$ 0.47
$ 2.04
$ 0.40
(1) Represents the average aggregate daily number of barrels of crude oil transported on our pipeline systems
and at our Wood River barge dock for MPC and for third parties. Volumes shown are 100 percent of the
volumes transported on the pipeline systems and barge dock. Volumes shown for all periods exclude
volumes transported on two undivided joint interest crude oil pipeline systems not contributed to MPLX LP
at the Initial Offering.
(2) Represents the average aggregate daily number of barrels of products transported on our pipeline systems
for MPC and third parties. Volumes shown are 100 percent of the volumes transported on the pipeline
systems.
92
(3)
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) Represents the number of owned barges and towboats at the end of the period presented.
(5) G&P volumes represent the volumes after the close of the MarkWest Merger. See Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations—Supplemental MD&A—G&P
Pro Forma for full-year pro forma information.
(6) Utica is an unconsolidated equity method investment and is consolidated for segment purposes only.
(7)
The Jefferson Gas System came online in December 2015. The volumes reported for 2015 are the average
daily rate for the days of operation.
Includes approximately 309 mmcf/d and 310 mmcf/d related to unconsolidated equity method investments,
Wirth and MarkWest Pioneer for the years ended December 31, 2016 and 2015, respectively.
The Sherwood de-ethanization complex came online in December 2015. The volumes reported for 2015 are
the average daily rate for the days of operation.
(8)
(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.
Includes NGLs fractionated for the Marcellus and Utica Operations.
(11)
(12) Purity ethane makes up approximately 128 and 104 mbpd of total fractionated products for the years ended
December 31, 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.
93
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
We have completed a full year of operations following the Partnership’s strategic merger with MarkWest. Given
the challenging economic and commodity environment, our priorities during 2016 included delivering solid
financial results, carefully managing our capital and expenses, improving our financial leverage metrics and
positioning the Partnership for longer term growth. Significant financial and other highlights for the year ended
December 31, 2016 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 $131 million, or
41 percent, in 2016 compared to 2015. This increase was primarily due to the acquisition of the inland
marine business on March 31, 2016, which continues the diversification of earnings streams and adds
additional fee-based revenues to the Partnership. The L&S segment operating income also increased
due to higher average pipeline tariffs. See Item 8. Financial Statements and Supplementary Data—Note
4 for further details of the HSM acquisition.
• G&P segment operating income attributable to MPLX LP increased approximately $1.1 billion, or
1,389 percent, in 2016 compared to 2015, due to the MarkWest Merger. Despite declines in drilling
activity by producers, the G&P segment realized volume increases across most of its businesses during
2016. Compared to full-year 2015, gathering volumes were up 11 percent, processing volumes were up
13 percent and fractionated volumes were up 25 percent.
• Net income for the year ended December 31, 2016 was $258 million, full-year 2016 DCF, a
non-GAAP measure, was over $1.1 billion and full-year 2016 distributions were $2.05 per common
unit, which represents a 13 percent increase over the full-year distributions of 2015.
During 2016, the Partnership substantially improved its financial leverage. This was accomplished through a
balance of managing capital expenditures and costs and opportunistically accessing the capital markets,
including:
• The private placement of approximately 30.8 million 6.5 percent Series A Convertible Preferred units
for a cash purchase price of $32.50 per unit during the second quarter of 2016. The aggregate net
94
proceeds of approximately $984 million from the sale of the Preferred units was used for capital
expenditures and repayment of debt.
• The issuance of an aggregate of 26,347,887 common units under the ATM Program during the year
ended December 31, 2016, generating net proceeds of approximately $776 million. As of
December 31, 2016, $717 million of common units remains available for issuance through the ATM
program under the Distribution Agreement.
During 2016, the Partnership also completed several significant organic growth projects, including:
• On October 11, 2016, the Cornerstone Pipeline became fully operational. This is a key organic growth
project within our L&S segment designed to transport condensate and natural gasoline from the
Marcellus and Utica regions to MPC’s Canton, Ohio, refinery. The Partnership is expanding the
capacity of existing pipelines and constructing new pipelines as part of a larger build-out of Utica Shale
infrastructure, seizing a unique opportunity to connect natural gas liquids to downstream markets in the
Midwest and Canada through our extensive distribution network.
• We expanded our presence in the Southwest with the completion of the Hidalgo gas processing
complex in the Delaware Basin of Texas, and will evaluate further investments in gathering and
processing to support the substantial activity our producer-customers are pursuing in the region.
Looking ahead, the Partnership is taking actions that should contribute to long-term value for our investors,
including the following recent announcements made in 2017:
•
•
•
Planned acquisition of assets from MPC with an estimated $1.4 billion of annual EBITDA, along with
our intentions to reduce the Partnership’s cost of capital by offering to exchange MPLX LP units for
MPC’s IDRs;
Strategic joint venture with Antero Midstream to support Antero Resources in the Marcellus Shale; and
Public debt offering of $2.25 billion principal amount senior notes.
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 distribution.
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) loss (income) from equity
investments; (viii) distributions from unconsolidated subsidiaries; (ix) unrealized derivative losses (gains); and
(x) 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; and (iv) 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, we record changes in the fair value of the derivative as an
unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded
unrealized gain or loss and record the realized gain or loss of the contract.
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
95
Adjusted EBITDA and DCF are net income and net cash provided by operating activities. Adjusted EBITDA and
DCF should not be considered as 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 segment purchased product costs less realized derivative gain
(loss). 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
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 and impairments have impacted comparability of our financial results (see Item 8. Financial
Statements and Supplementary Data—Notes 4 and 18).
96
RESULTS OF OPERATIONS
The following table and discussion is a summary of our results of operations for the years ended 2016, 2015 and
2014, 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.
2016
2015
$ Change
2014
$ Change
(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
(Loss) income from equity method investments
Other income
Other income—related parties
$ 958
603
298
114
572
11
1
(74)
6
101
$130
593
20
101
36
1
—
3
6
71
$ 828
10
278
13
536
10
1
(77)
—
30
Total revenues and other income
2,590
961
1,629
Costs and expenses:
Cost of revenues (excludes items below)
Purchased product costs
Rental cost of sales
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
$28 million, $5 million, and $1 million, respectively)
Other financial costs
Income before income taxes
(Benefit) provision for income taxes
Net income
Less: Net income attributable to noncontrolling interests
Less: Net income attributable to Predecessor
354
448
53
316
546
130
193
43
2,083
507
1
210
50
246
(12)
258
2
23
225
20
5
166
116
—
118
13
663
298
—
35
13
250
1
249
1
92
129
428
48
150
430
130
75
30
1,420
209
1
175
37
(4)
(13)
9
1
(69)
$ 70
662
—
15
—
—
—
—
6
40
793
228
—
1
153
75
—
81
10
548
245
—
4
1
240
1
239
57
61
$ 60
(69)
20
86
36
1
—
3
—
31
168
(3)
20
4
13
41
—
37
3
115
53
—
31
12
10
—
10
(56)
31
$ 35
$332
$262
$262
Net income attributable to MPLX LP
Adjusted EBITDA attributable to MPLX LP(1)
DCF(1)
DCF attributable to GP and LP unitholders(1)
$ 233
$156
$
77
$1,419
$1,140
$1,099
$498
$399
$399
$ 921
$ 741
$ 700
$121
$166
$137
$137
(1) Non-GAAP financial measure. See the following tables for reconciliations to the most directly comparable
GAAP measures.
97
(In millions)
2016
2015
2014
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF
attributable to GP and LP unitholders from Net income:
Net income
Depreciation and amortization
(Benefit) provision for income taxes
Amortization of deferred financing costs
Non-cash equity-based compensation
Impairment expense
Net interest and other financial costs
Loss (income) from equity investments
Distributions from unconsolidated subsidiaries
Unrealized derivative losses (gains)(1)
Acquisition costs
Adjusted EBITDA
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to Predecessor(2)
MarkWest’s pre-merger EBITDA(3)
Adjusted EBITDA attributable to MPLX LP
Deferred revenue impacts
Net interest and other financial costs
Maintenance capital expenditures
Other
DCF pre-MarkWest undistributed
MarkWest undistributed DCF(2)
DCF
Preferred unit distributions
$ 258
546
(12)
46
10
130
215
74
150
36
(1)
1,452
(3)
(30)
—
1,419
8
(215)
(68)
(4)
1,140
—
1,140
(41)
$ 249
116
1
5
4
$239
75
1
—
2
—
43
(3)
15
(4)
30
456
(1)
(119)
162
498
6
(36)
(31)
(6)
431
(32)
399
—
—
5
—
—
—
—
322
(69)
(87)
—
166
(3)
(6)
(22)
2
137
—
137
—
DCF attributable to GP and LP unitholders
$1,099
$ 399
$137
98
(In millions)
2016
2015
2014
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)(1)
Acquisition costs
Other
Adjusted EBITDA
Adjusted EBITDA attributable to noncontrolling interests
Adjusted EBITDA attributable to Predecessor(2)
MarkWest’s pre-merger EBITDA(3)
Adjusted EBITDA attributable to MPLX LP
Deferred revenue impacts
Net interest and other financial costs
Maintenance capital expenditures
Other
DCF pre-MarkWest undistributed
MarkWest undistributed DCF(3)
DCF
Preferred unit distributions
DCF attributable to GP and LP unitholders
$1,288
(89)
(20)
10
1
215
5
5
36
(1)
2
1,452
(3)
(30)
—
1,419
8
(215)
(68)
(4)
1,140
—
$ 340
54
(12)
4
—
43
—
$334
(19)
(2)
2
—
—
5
2
1
(4) —
—
30
—
—
456
(1)
(119)
162
498
6
(36)
(31)
(6)
322
(69)
(87)
—
166
(3)
(6)
(22)
2
137
431
(32) —
1,140
399
(41) —
137
—
$1,099
$ 399
$137
(1)
(2)
(3)
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During
the period when a derivative contract is outstanding, we record changes in the fair value of the derivative as
an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously
recorded unrealized gain or loss and record the realized gain or loss of the contract.
The Adjusted EBITDA adjustments related to the Predecessor are excluded from Adjusted EBITDA
attributable to MPLX LP and DCF prior to the March 31, 2016 HSM acquisition.
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
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
99
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 revenue
Segment purchased product costs
Realized derivative loss (gain) related to revenues and purchased product costs
Net operating margin
Revenue adjustment from unconsolidated affiliates(1)
Realized derivative (loss) gain related to revenues and purchased product
2016
2015
2014
$2,972
(425)
3
2,550
(402)
$ 910
$ 747
(25) —
(4) —
881
747
(28) —
costs(2)
Unrealized derivative (losses) gains(2)
(Loss) income from equity method investments
Other income
Other income—related parties
Cost of revenues (excludes items below)
Rental cost of sales
Purchases—related parties
Depreciation and amortization
Impairment expense
General and administrative expenses
Other taxes
4
4
3
6
71
(225)
(5)
(166)
(116)
(3)
(36)
(74)
6
101
(354)
(53)
(316)
(546)
(130) —
(193)
(43)
(118)
(13)
—
—
—
6
40
(228)
(1)
(153)
(75)
—
(81)
(10)
Income from operations
$ 507
$ 298
$ 245
(1)
(2)
These amounts relate to Partnership-operated unconsolidated affiliates. The chief operating decision maker
and management include these to evaluate the segment performance as we continue to operate and manage
the operations. Therefore, the impact of the revenue is included for segment reporting purposes, but
removed for GAAP purposes.
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During
the period when a derivative contract is outstanding, we record changes in the fair value of the derivative as
an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously
recorded unrealized gain or loss and record the realized gain or loss of the contract.
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.
100
Service revenue-related parties increased $10 million in 2016 compared to 2015. This increase was primarily
related to 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 $13 million in 2016 compared to 2015. This increase was primarily
related to 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.
(Loss) income 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 $88 million related to one of
our equity method investments.
Other income-related parties increased $30 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 $129 million in 2016 compared to 2015. This variance was primarily due to the
MarkWest Merger, 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.
Rental cost of sales increased $48 million in 2016 compared to 2015. This variance was primarily due to the
MarkWest Merger.
Purchases-related parties increased $150 million in 2016 compared to 2015. The increase was primarily due to
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 $430 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. During 2017,
we expect to record accelerated depreciation related to the decommissioning of a plant in the Houston Complex
of approximately $28 million in order to construct an additional 200 mmcf/d processing facility.
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 $75 million in 2016 compared to 2015. The increase was
primarily due to the MarkWest Merger 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.
101
Other taxes increased $30 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 $213 million in 2016 compared to 2015. The increase was
primarily due to the senior notes assumed as part of the MarkWest Merger.
During 2016 and 2015, MPC did not ship its minimum committed volumes on certain of our pipeline systems. As
a result, MPC was obligated to make $48 million and $44 million of deficiency payments in 2016 and 2015,
respectively. We record deficiency payments as Deferred revenue-related parties on our Consolidated Balance
Sheets. During 2016 and 2015, we recognized revenue of $40 million and $38 million, respectively, related to
volume deficiency credits. At December 31, 2016 and 2015, the cumulative balance of Deferred revenue-related
parties on our Consolidated Balance Sheets related to volume deficiencies was $44 million and $36 million,
respectively. The following table presents the future expiration dates of the associated deferred revenue credits
for 2016:
(In millions)
March 31, 2017
June 30, 2017
September 30, 2017
December 31, 2017
March 31, 2018
June 30, 2018
September 30, 2018
December 31, 2018
Total
$ 8
9
7
9
2
2
3
4
$44
We will recognize revenue for the deficiency payments in future periods at the earlier of when volumes are
transported in excess of the minimum quarterly volume commitments, when it becomes impossible to physically
transport volumes necessary to utilize the accumulated credits or upon expiration of the make-up period.
Deficiency payments are included in the determination of DCF in the period in which a deficiency occurs.
2015 Compared to 2014
Service revenue increased $60 million in 2015 compared to 2014. This variance was primarily due to an
$63 million increase in the G&P segment from the MarkWest Merger and a $2 million increase resulting from
higher average tariffs received on the volumes of crude oil and products shipped, partially offset by a $5 million
decrease related to a 13 mbpd reduction in third-party crude oil and products volumes shipped.
Service revenue-related parties decreased $69 million in 2015 compared to 2014. This decrease was primarily
related to the reclassification of income from the transportation service agreement entered into by HSM with
MPC in 2015. After January 2015, it was considered an operating lease, and therefore, a portion of the revenue
was included in rental income-related parties. This decrease was also related to an agreement entered into by
HSM with MPC for the maintenance repair facility which was included in other income in 2015 and a $7 million
decrease in revenue related to volume deficiency credits recognized, partially offset by a $32 million increase
due to higher average tariffs received on the volumes of crude oil and products shipped.
Rental income increased $20 million in 2015 compared to 2014 related entirely to the MarkWest Merger.
Rental income-related parties increased $86 million in 2015 compared to 2014. This increase was primarily
related to the transportation service agreement entered into by HSM with MPC in January 2015. Prior to January
2015, this agreement was not considered an operating lease and the income was included in service revenue-
related parties.
102
Product sales increased $36 million in 2015 compared to 2014. This variance was due to the MarkWest Merger.
Other income and other income-related parties increased a total of $34 million in 2015 compared to 2014. The
increase was primarily due to an increase in fees received for operating MPC’s private pipeline systems, a
reclassification of fees received from the agreements for the maintenance repair facility and an increase due to
the MarkWest Merger.
Cost of revenues decreased $3 million in 2015 compared to 2014 primarily due to the MarkWest Merger,
partially offset by decrease in average fuel costs. The variance was also due to costs associated with rental
income from the operating lease entered into in January 2015 which were reclassified to rental cost of sales.
Rental cost of sales increased $4 million in 2015 compared to 2014 primarily due costs associated with rental
income which were reclassified from cost of revenues related to the HSM transportation services agreement
entered into in January 2015.
Purchased product costs increased $20 million in 2015 compared to 2014. This variance was due to the
MarkWest Merger.
Purchases-related parties increased $13 million in 2015 compared to 2014. The increase was primarily due to
higher compensation expenses provided under the omnibus and employee services agreements with MPC,
partially offset by increased capitalization of employee costs associated with capital projects.
Depreciation and amortization expense increased $41 million in 2015 compared to 2014 primarily due to the
MarkWest Merger.
General and administrative expenses increased $37 million in 2015 compared to 2014. The increase in 2015 was
primarily related to $30 million in acquisition costs.
Other taxes increased $3 million in 2015 compared to 2014. The increase was primarily due to property taxes
from the MarkWest Merger.
Interest expense and other financial costs increased $43 million in 2015 compared to 2014. The increase was due
to borrowings on the bank revolving credit facility, term loan and senior notes in connection with the MarkWest
Merger. The increase was also due to $6 million in transaction costs related to the exchange of MarkWest senior
notes for MPLX LP senior notes.
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 gains (losses), 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 Predecessor of the inland marine business prior to the March 31, 2016
acquisition.
103
The tables below present information about segment operating income for the reported segments for the years
ended December 31, 2016, 2015 and 2014.
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 interest and
Predecessor
Segment portion attributable to noncontrolling interest and Predecessor
Segment operating income attributable to MPLX LP
2016
2015
2014
$787
68
$760
75
$747
46
855
835
793
368
379
392
487
34
456
134
401
188
$453
$322
$213
2016 Compared to 2015
Segment revenue increased $27 million due to 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 $7 million primarily due to a reduction in fees paid to HSM by MPC.
Segment cost of revenues decreased $11 million primarily due to 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 interest and Predecessor decreased primarily due to the
acquisition of HSM as of March 31, 2016.
2015 Compared to 2014
Segment revenue increased due to a $13 million increase in higher average tariffs received on the volumes of
crude oil and products shipped, partially offset by a $7 million decrease in revenue related to volume deficiency
credits recognized and a decrease due to an agreement entered into by HSM with MPC for the maintenance
repair facility which was included in other income in 2015.
Segment other income increased $29 million due to an increase in storage fees, other revenue related to the
expansion of the Patoka Tank Farms and an increase from an agreement entered into by HSM with MPC for the
maintenance repair facility which was included in segment revenue prior to 2015.
Segment cost of revenues decreased $13 million primarily due a decrease in the average fuel costs and increased
capitalization of employee costs associated with capital projects, partially offset by higher compensation
expenses provided under the omnibus and employee services agreements with MPC.
104
Segment portion attributable to noncontrolling interest and Predecessor decreased primarily due to the
acquisition of the remaining interest of Pipe Line Holdings, of which the 0.5 percent was purchased on
December 4, 2015 and the change in the segment portion attributable to Predecessor.
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 interest
Segment portion attributable to noncontrolling interest
2016
2015
2014
$2,185
$150
1 —
2,186
150
907
1,279
147
62
88
12
$—
—
—
—
—
—
Segment operating income attributable to MPLX LP
$1,132
$ 76
$—
The G&P segment increased overall due to the MarkWest Merger. There was no G&P segment prior to the
MarkWest Merger. See Supplemental MD&A—G&P Pro Forma for more information.
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 interest to our consolidated net income attributable to noncontrolling interests for
the years ended December 31, 2016, 2015 and 2014. Adjustments related to unconsolidated affiliates relate to our
Partnership-operated non-wholly-owned entities that we consolidate for segment purposes. (Loss) income from
equity method investments relates to our portion of income 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
(Loss) income from equity method investments
Other income—related parties
Unrealized derivative (losses) gains(1)
Depreciation and amortization
Impairment expense
General and administrative expenses
2016
2015
2014
$ 453
1,132
$ 322
76
$213
—
398
(8)
133
3
2
4
(116)
1,585
(173)
34
(74)
40
(36)
(546)
(130) —
(193)
(118)
213
85
103
—
—
—
(75)
—
(81)
Income from operations
$ 507
$ 298
$245
105
(In millions)
Reconciliation to Total revenues and other income:
Total segment revenues and other income
Revenue adjustment from unconsolidated affiliates
(Loss) income from equity method investments
Other income—related parties
Unrealized derivative losses(1)
Total revenues and other income
(in millions)
Reconciliation to Net income attributable to noncontrolling interests and
Predecessor:
2016
2015
2014
$3,041
(402)
(74)
40
(15)
$ 985
$ 793
(28) —
—
3
2
—
(1) —
$2,590
$ 961
$ 793
2016
2015
2014
Segment portion attributable to noncontrolling interest and Predecessor
Portion of noncontrolling interests and Predecessor related to items below segment
$ 181
$ 146
$ 188
income from operations
Portion of operating income attributable to noncontrolling interests of unconsolidated
affiliates
(124)
(48)
(70)
(32)
(5) —
Net income attributable to noncontrolling interests and Predecessor
$
25
$
93
$ 118
(1)
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During
the period when a derivative contract is outstanding, we record changes in the fair value of the derivative as
an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously
recorded unrealized gain or loss and record the realized gain or loss of the contract.
SUPPLEMENTAL MD&A—G&P PRO FORMA
The tables below present financial information, as evaluated by management, for the reported segments for the
years ended December 31, 2016, 2015 and 2014. This is a supplemental disclosure showing G&P segment results
as if it were acquired as of January 1, 2014 and it incorporates pro forma adjustments necessary, including the
removal of approximately $90 million of transaction costs, to reflect a January 1, 2014 acquisition date (see
reconciliations below). The pro forma information was prepared in a manner consistent with Article 11 of
Regulation S-X and FASB ASC Topic 805 (see Item 8. Financial Statements and Supplementary Data—Note 4).
Results provided for the year ended December 31, 2016 reflect actual results. We believe this data will provide a
more meaningful discussion of trends for the G&P segment as it helps convey the impact of commodity pricing
and volume changes to the business. Future results may vary significantly from the results reflected below
because of various factors. In addition, all Partnership-operated, non-wholly- owned subsidiaries are treated as if
they are consolidated for segment reporting purposes (for more information on how management has determined
our segments 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 interest
Segment portion attributable to noncontrolling interest
Segment operating income attributable to MPLX LP
106
2016
2015
2014
$2,185
1
$2,007
—
$2,168
—
2,186
2,007
2,168
907
1,279
147
875
1,197
1,132
121
971
36
$1,132
$1,011
$ 935
2016 Compared to 2015
Segment revenues and other income increased $179 million in 2016 due to favorable fee revenues from increases
in total gathering throughput, total natural gas processed and total C2+ NGLs fractionated volumes of 11 percent,
13 percent and 25 percent, respectively. Volumes increased due to new processing plants in the Marcellus and
Southwest areas, additional fractionation capacity in the Marcellus area and increased dry gas gathering in the
Utica area. The increased fee revenues were partially offset by lower contributions from commodity derivative
settlements.
Segment cost of revenues increased $32 million due to increased operating costs from expanded plant capacities
offset by lower product costs due to changes in component mix, lower Marcellus purchases related to inventory,
and favorable line fill valuation due to higher liquid pricing.
The change in the segment portion of operating income attributable to noncontrolling interests increased due to
ongoing growth in our entities that are not wholly-owned.
2015 Compared to 2014
Segment revenue decreased due to a 39 percent decrease in natural gas prices and a 50 percent decrease in NGL
prices over the same period in 2014. There was a $151 million decrease in inventory sold compared to the same
period in 2014 due to changes in contractual terms. This decrease was partially offset by an increase in volumes.
Total gathering throughput, total natural gas processed and total C2+ NGLs fractionated volumes increased by
28 percent, 36 percent and 30 percent, respectively.
Segment cost of revenues decreased mainly due to a decrease of $152 million in inventory sold compared to the
same period in 2014 due to changes in contractual terms and decreases in natural gas purchased prices and NGL
prices. Segment cost of revenues as a percentage of segment revenue decreased 13 percent for the year ended
December 31, 2015 compared to the same period in 2014. This decrease was primarily due to an increase in fee
revenue as a percent of total revenue by 16 percent. The decreases were partially offset by increased expenses
related to the expansion of Utica and Marcellus operations.
The change in the segment portion of operating income attributable to noncontrolling interests increased due to
ongoing growth in our entities that are not wholly owned.
Reconciliation of Segment Operating Income to Consolidated Income Before Provision for Income Tax
The following tables provide reconciliations of G&P segment revenues and other income to total revenues and
other income and G&P’s segment operating income attributable to MPLX LP to net income attributable to
MPLX LP, for the years ended December 31, 2016, 2015 and 2014, respectively. The items listed below the
Other income—related parties lines are not allocated to business segments as management does not consider
these items allocable to any individual segment.
(In millions)
Pro forma reconciliation to total revenues and other income:
Total G&P segment revenues and other income
Revenue adjustment from unconsolidated affiliates(1)
(Loss) income from equity method investments
G&P other income (loss)—related parties
Unrealized derivative (losses) gains related to revenue(2)
Total pro forma G&P revenues and other income
Total pro forma L&S revenues and other income
Total pro forma revenues and other income
107
2016
2015
2014
$2,186
(402)
(74)
40
(15)
$2,007
(159)
8
(4)
(10)
$2,168
(41)
(12)
19
25
1,735
855
1,842
835
2,159
813
$2,590
$2,677
$2,972
(In millions)
Pro forma reconciliation to pro forma net income attributable to MPLX LP:
L&S segment operating income attributable to MPLX LP
G&P segment operating income attributable to MPLX LP
Pro forma G&P segment operating income attributable to MPLX LP
Segment portion attributable to unconsolidated affiliates(1)
Segment portion attributable to noncontrolling interest and Predecessor
(Loss) income from equity method investments
Other income (loss)—related parties
Unrealized derivative (losses) gains(2)
Depreciation and amortization
Impairment expense
General and administrative expenses
Pro forma income from operations
Related party interest and other financial costs
Debt retirement expense
Net interest and other financial costs
Pro forma income before income taxes
(Benefit) provision for income taxes
Pro forma net income
Less: Net income attributable to noncontrolling interests
2016
2015
2014
$ 453
1,132
—
(320)
181
(74)
40
(36)
(546)
(130)
(193)
$ 322
76
935
(29)
182
8
(5)
(10)
(575)
(26)
(209)
$ 266
—
935
(8)
21
(12)
19
82
(481)
(62)
(130)
507
1
—
260
246
(12)
258
25
669
—
118
259
292
(10)
302
55
630
—
—
189
441
46
395
66
Pro forma net income attributable to MPLX LP
$ 233
$ 247
$ 329
(1)
(2)
The Partnership consolidated the Utica Operations until December 4, 2015 at which point these were
accounted for as unconsolidated affiliates.
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During
the period when a derivative contract is outstanding, we record changes in the fair value of the derivative as
an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously
recorded unrealized gain or loss and record the realized gain or loss of the contract.
108
Pro Forma Operating Statistics
Gathering Throughput (mmcf/d)
Marcellus Operations
Utica Operations(1)
Southwest Operations(2)
Total gathering throughput
Natural Gas Processed (mmcf/d)
Marcellus Operations
Utica Operations(1)
Southwest Operations
Southern Appalachian Operations
Total natural gas processed
C2 + NGLs Fractionated (mbpd)
Marcellus Operations(3)
Utica Operations(1)(3)
Southwest Operations
Southern Appalachian Operations(4)
Total C2 + NGLs fractionated(5)
Pricing Information
Natural Gas NYMEX HH ($/MMBtu)
C2 + NGL Pricing/gallon(6)
2016
2015
2014
910
932
1,433
3,275
3,210
1,072
1,226
253
5,761
260
42
18
15
335
858
673
1,413
2,944
2,861
883
1,077
267
5,088
194
40
18
15
267
668
289
1,336
2,293
2,064
416
991
280
3,751
147
19
21
19
206
$ 2.55
$ 0.47
$ 2.63
$ 0.46
$ 4.28
$ 0.92
(1) Utica was a consolidated equity method investment prior to December 4, 2015. After this date, it became an
(2)
unconsolidated equity method investment but is consolidated for segment purposes only.
Includes approximately 309 mmcf/d, 242 mmcf/d and 228 mmcf/d related to unconsolidated equity method
investments, Wirth and MarkWest Pioneer, for the years ended December 31, 2016, 2015 and 2014,
respectively.
(3) 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.
Includes NGLs fractionated for the Marcellus and Utica Operations.
Purity ethane makes up approximately 128 mbpd, 79 mbpd and 67 mbpd of total fractionated products for
the years ended December 31, 2016, 2015 and 2014, respectively.
(4)
(5)
(6) C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of approximately 35 percent
ethane, 35 percent propane, 6 percent Iso-Butane, 12 percent normal butane and 12 percent natural gasoline.
109
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Our cash and cash equivalents balance was $234 million at December 31, 2016 compared to $43 million at
December 31, 2015. 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
2016
2015
2014
$ 1,288
(1,212)
115
$
340
(1,599)
1,275
$
334
(137)
(224)
$
191
$
16
$
(27)
Cash Flows Provided by Operating Activities. Net cash provided by operating activities increased $948 million
in 2016 compared to 2015, primarily due to increased operating results as result of the MarkWest Merger as well
as favorable changes in working capital of approximately $143 million compared to 2015.
For 2016, changes in working capital were a net $89 million source of cash. Accounts payable and accrued
liabilities increased $100 million from year-end 2015 due mainly to an increase in our product and freight
accruals as a result of higher NGL prices as well as timing related to general operating payables. Current
receivables increased $52 million primarily due to higher NGL prices and volumes as compared to 2015, and
there was an increase in the liability positions of our derivatives due to changes in the fair value of $43 million
that were primarily due to increases in commodity prices during 2016.
For 2015, changes in working capital were a net $54 million use of cash. Current receivables increased
$29 million primarily due to higher third-party tariff revenue receivables. Net liabilities to related parties
decreased $22 million due to timing of payables to related parties.
For 2014, changes in working capital were a net $19 million source of cash, primarily due to an increase in net
liabilities to related parties and a decrease in current receivables. Net liabilities to related parties increased
$15 million, primarily due to an increase in payables to related parties under the omnibus and employee services
agreements and a decrease in receivables from related parties.
Cash Flows Used in Investing Activities. Net cash used in investing activities decreased $387 million in 2016
compared to 2015, primarily due to a $918 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 $154 million source of cash from investment loans between HSM
and related parties prior to the HSM acquisition.
Net cash used in investing activities increased $1.5 billion in 2015 compared to 2014, primarily due to a
$1.2 billion increase in acquisitions due to the MarkWest Merger and a $147 million increase in additions to
property, plant and equipment.
Net cash used in investing activities in 2014 was primarily used for additions to property, plant, and equipment.
Cash Flows from Financing Activities. Net cash provided by financing activities in 2016 was $115 million
compared to $1.3 billion in 2015. 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.
110
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.
The sources of cash in 2014 primarily consisted of net long-term borrowings and proceeds from the issuance of
common units. The uses of cash in 2014 primarily consisted of distributions of $910 million to MPC for the
acquisition of an interest in Pipe Line Holdings, as well as distributions to unitholders.
Cash used in distributions to unitholders totaled $845 million in 2016, $158 million in 2015, and $103 million in
2014. The increase in 2016 was primarily due to the issuance of units to MarkWest unitholders in connection
with the merger on December 4, 2015.
Long-term debt borrowings and repayments were a net $878 million use of cash in 2016 compared to a
$38 million source of cash in 2015 and a $631 million source of cash in 2014. 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
Our outstanding borrowings at December 31, 2016 and 2015 consisted of the following:
(In millions)
MPLX LP:
Bank revolving credit facility due 2020
Term loan facility due 2019
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
Consolidated subsidiaries:
MarkWest—4.500%—5.500%, due 2023—2025
MPL—capital lease obligations due 2020
Total
Unamortized debt issuance costs
Unamortized discount(1)
Amounts due within one year
December 31,
2016
2015
$ —
250
710
989
1,149
500
1,189
63
8
4,858
(7)
(428)
(1)
$ 877
250
710
989
1,149
500
1,189
63
9
5,736
(8)
(472)
(1)
Total long-term debt due after one year
$4,422
$5,255
(1)
Includes $420 million and $464 million discount as of December 31, 2016 and 2015, respectively, related to
the difference between the fair value and the principal amount of the assumed MarkWest debt.
On November 20, 2014, MPLX LP entered into a credit agreement with a syndicate of lenders (“MPLX Credit
Agreement”) which provides for a five-year, $1 billion bank revolving credit facility and a $250 million term
loan facility. In connection with the closing of the MarkWest Merger, we amended our MPLX Credit Agreement
to, among other things, increase the aggregate amount of revolving credit capacity under the credit agreement by
$1 billion, for total aggregate commitments of $2 billion, and to extend the maturity of the revolving credit
facility to December 4, 2020. The term loan facility was not amended and matures on November 20, 2019. Also
in connection with the closing of the MarkWest Merger, MarkWest’s bank revolving credit facility was
111
terminated and the approximately $943 million outstanding under MarkWest’s bank revolving credit facility was
repaid with $850 million of borrowings under MPLX LP’s bank revolving credit facility and $93 million of cash.
We incurred approximately $2 million of costs related to the borrowing on the bank revolving credit facility.
The bank revolving credit facility includes letter of credit issuing capacity of up to $250 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 from time-to-time during its term to
a date that is one year after the then-effective maturity subject to the approval of lenders holding the majority of
the commitments then outstanding, provided that the commitments of any non-consenting lenders will be
terminated on the then-effective maturity date. During 2016, we borrowed $434 million under the bank revolving
credit facility, at an average interest rate of 1.9 percent, and repaid $1.3 billion under the bank revolving credit
facility. At December 31, 2016, we had no borrowings and $3 million in letters of credit outstanding under this
facility, resulting in total unused loan availability of $2.0 billion, or 99.9 percent of the borrowing capacity.
The term loan facility was drawn in full on November 20, 2014. The maturity date for the term loan facility may
be extended for up to two additional one-year periods subject to the consent of the lenders holding a majority of
the outstanding term loan borrowings, provided that the portion of the term loan borrowings held by any
non-consenting lenders will continue to be due and payable on the then-effective maturity date. The borrowings
under this facility during 2016 were at an average interest rate of 1.954 percent.
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 includes certain representations and warranties, affirmative and negative covenants
and events of default that we consider usual and customary for an agreement of that type and that could, among
other things, limit our ability to pay distributions to our unitholders. The financial covenant requires us to
maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as
defined in the MPLX Credit Agreement) 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 certain of our subsidiaries from incurring debt, creating liens on our assets and entering into
transactions with affiliates. As of December 31, 2016, we were in compliance with this financial covenant with a
ratio of Consolidated Total Debt to Consolidated EBITDA of 3.26 to 1.0, as well as all other covenants contained
in the MPLX Credit Agreement.
As of December 31, 2016, we had five series of senior notes outstanding: $750 million in aggregate principal
amount on the senior notes issued in August 2012 and due February 2023; $1.0 billion aggregate principal
amount on senior notes issued in January 2013 and due July 2023; $1.2 billion aggregate principal amount on
senior notes issued in November 2014 and due in December 2024; $500 million aggregate principal amount on
senior notes issued in February 2015 and due February 2025; and $1.2 billion aggregate principal amount on
senior notes issued in June 2015 and due in June 2025 (altogether the “Senior Notes Outstanding”). As of
December 31, 2016, there were no minimum principal payments on the Senior Notes Outstanding due during the
next five years. For further discussion of the Senior Notes Outstanding and other debt related information, see
Item 8. Financial Statements and Supplementary Data—Note 17.
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
112
principal amount of 5.200 percent unsecured senior notes due March 2047 (the “2047 Senior Notes” and,
collectively with the 2027 Senior Notes, the “New 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
Partnership intends to use the net proceeds from this offering for general partnership purposes, which may
include, from time to time, acquisitions (including the previously announced planned dropdown of assets from
MPC, the acquisition of the Ozark pipeline, and the acquisition of a partial, indirect equity interest in the Bakken
Pipeline system) and capital expenditures.
Our intention is to maintain an investment grade credit profile. As of January 31, 2017, we had the following
credit rating grade levels.
Rating Agency
Rating
Fitch
Moody’s
Standard & Poor’s
BBB- (stable outlook)
Baa3 (stable outlook)
BBB- (stable outlook)
The ratings 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 $2.7 billion at December 31, 2016, consisting of:
(In millions)
MPLX LP—bank revolving credit facility(1)
MPC Investment—loan agreement
Total
Cash and cash equivalents
Total liquidity
December 31, 2016
Total
Capacity
Outstanding
Borrowings
Available
Capacity
$
$
2,000
500
2,500
$
$
(3) $
—
1,997
500
(3) $
2,497
234
$
2,731
(1) Outstanding borrowings include $3 million in letters of credit outstanding under this facility.
We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our
revolving credit agreements and issuances of additional debt and equity securities. 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,
repayment of debt maturities 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.
113
Equity and Preferred Units Overview
The table below summarizes the changes in the number of units outstanding through December 31, 2016:
(In units)
Common
Class B
Subordinated
General
Partner
Total
36,951,515
15,479
2,924,104
3,450,000
43,341,098
18,932
25,166
36,951,515
216,350,465
296,687,176
120,989
Balance at December 31, 2013
Unit-based compensation awards
Contribution of interest in Pipe Line
Holdings
December 2014 equity offering
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
—
—
—
—
—
—
36,951,515
—
1,508,225
316
75,411,255
15,795
—
—
59,676
70,408
2,983,780
3,520,408
36,951,515
—
1,638,625
386
81,931,238
19,318
—
— (36,951,515)
—
7,981,756
7,981,756
—
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
368,555,271
—
—
—
—
—
—
—
—
26,347,887
22,534,002
4,350,057
7,153,177
—
—
(3,990,878)
—
Balance at December 31, 2016
357,193,288
3,990,878
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 will be 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
receive as a 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 year ended December 31, 2016 was $25 million.
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 distribution. MPC funded this cash
payment, which reduced our liability payable to Class B unitholders by approximately $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 August 4, 2016, the Partnership entered into a second amended and restated distribution agreement providing
for the continuous issuance of up to an aggregate of $1.2 billion of common units, in amounts, at prices and on
terms to be determined by market conditions and other factors at the time of any offerings. The Partnership
expects the net proceeds from sales under the ATM Program will be used for general partnership purposes
114
including repayment or refinancing of debt and funding for acquisitions, working capital requirements and
capital expenditures. During the year ended December 31, 2016, the sale of common units under the ATM
Program generated net proceeds of approximately $776 million.
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 $96 million per quarter,
or $384 million per year, based on the number of common and general partner units. On January 25, 2017, we
announced that the board of directors of our general partner had declared a distribution of $0.5200 per unit that
was paid on February 14, 2017 to unitholders of record on February 6, 2017. This represents a four percent
increase over the fourth quarter 2015 distribution. On February 1, 2017, we announced distribution growth
guidance of 12 to 15 percent for 2017. 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.
The allocation of total quarterly cash distributions to general and limited partners is as follows for the years
ended December 31, 2016, 2015 and 2014. 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.
(In millions)
Distribution declared:
Limited partner units—public
Limited partner units—MPC
General partner units—MPC
Incentive distribution rights—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
2016
2015
2014
$
$
533
159
18
187
897
41
$
151
104
6
54
315
—
29
77
2
4
112
—
$
938
$
315
$
112
$0.5050
0.5100
0.5150
0.5200
$0.4100
0.4400
0.4700
0.5000
$0.3275
0.3425
0.3575
0.3825
$2.0500
$1.8200
$1.4100
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
115
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.
Our capital expenditures for the past three years are shown in the table below:
(In millions)
Capital expenditures:
Maintenance
Expansion
Total capital expenditures
Less: (Decrease) increase in capital accruals
Asset retirement expenditures
Additions to property, plant and equipment
Capital expenditures of unconsolidated subsidiaries(1)
Total gross capital expenditures
Less: Joint venture partner contributions(2)
Total capital expenditures, net
Less: Maintenance capital
Total growth capital
Acquisition, net of cash acquired
Total growth capital and acquisition
2016
2015
2014
$
68
1,118
$
1,186
(25)
5
1,206
131
1,337
64
1,273
72
1,201
—
33
282
315
26
1
$ 30
124
154
11
2
288
141
24 —
312
141
8 —
304
33
141
30
271
111
1,218 —
$1,201
$1,489
$111
(1)
(2)
Includes amounts related to unconsolidated, Partnership-operated subsidiaries.
This represents estimated joint venture partners share of growth capital.
Our growth capital plan range for 2017 is $1.4 billion to $1.7 billion, not including the dropdowns or acquisitions
previously discussed in Item 1. Business—Competitive Strengths, or their respective subsequent capital
spending. The G&P segment capital plan includes investments that are expected to support producer customers.
The L&S segment capital plan includes the development of various crude oil and refined petroleum products
infrastructure projects, including a build out of Utica Shale infrastructure in connection with the recently
completed Cornerstone Pipeline, a butane cavern and a tank farm expansion. 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.
We have revised our timeline for completion of certain capital projects that are classified as
construction-in-progress within Property, plant and equipment, net in the accompanying Consolidated Balance
Sheets. The expected completion dates of these projects have been updated to more closely align with the
expected timing of utilization by their respective producer customers as part of the just-in-time component of our
capital program. We continue to believe all amounts capitalized will be recoverable as we expect these projects
to be completed.
116
Other Capital Requirements and Strategic Actions
On January 3, 2017, MPC announced plans to significantly accelerate the dropdown of assets with an estimated
$1.4 billion of MLP-eligible annual EBITDA to MPLX LP now expected to be completed in 2017, subject to
requisite approvals and regulatory clearances, including tax, and market and other conditions. We expect these
dropdowns to be valued consistent with recent industry precedent valuation multiples ranging between 7.0x and
9.0x EBITDA, subject to the MPLX LP conflicts committee review process and receipt of customary fairness
opinions. We also expect the Partnership to finance the dropdown transactions with debt and equity in
approximately equal proportions in the aggregate for all planned dropdown of assets. The equity financing is
expected to be funded through MPLX LP common units issued to MPC. In conjunction with the completion of
the dropdowns, MPC also expects to exchange its economic interests in our general partner, including incentive
distribution rights, for newly issued MPLX LP common units. MPC would continue to retain control of the
general partner following this exchange.
On February 6, 2017, we announced the formation of a strategic joint venture to support the development of
Antero Resources extensive rich-gas position in the Marcellus Shale. The 50-50 joint venture with Antero
Midstream will include the ongoing development of incremental gas processing, including three additional
processing plants at the Sherwood Complex in West Virginia by the first quarter of 2018 and the ownership of
20,000 bpd of the newly constructed Hopedale III fractionation train and an option to invest in additional
fractionation expansions at the Hopedale Complex in Ohio, subject to the production of incremental NGLs from
the joint venture’s processing facilities. In connection with this transaction, the Partnership contributed
approximately $134 million of assets currently under construction at the Sherwood Complex and Antero
Midstream made an initial capital contribution of approximately $155 million.
On February 13, 2017, we also announced the acquisition of Ozark pipeline from Enbridge Ozark for
approximately $220 million. 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 230,000 barrels per
day. This purchase transaction is expected to close in the first quarter of 2017 and will be funded with cash on
hand.
On February 15, 2017, we also acquired a joint venture interest in the Bakken Pipeline system from ETP and
SXL. MPLX LP contributed $500 million of the $2 billion purchase price. The Bakken Pipeline system is
currently expected to deliver in excess of 470,000 barrels per day of crude oil from the Bakken/ Three Forks
production area in North Dakota to the Midwest through Patoka, Illinois and ultimately to the Gulf Coast. MPLX
LP funded this acquisition with cash on hand.
117
Contractual Cash Obligations
The table below provides aggregated information on our consolidated obligations to make future payments under
existing contracts as of December 31, 2016:
(In millions)
Total
2017
2018-2019
2020-2021
Later Years
Bank revolving credit facility(1)
Term loan(1)
Long-term debt(1)
Capital lease obligations
Operating lease and long-term storage agreements(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(7)
AROs(8)
$
16
267
6,300
9
302
588
42
630
103
228
608
26
25
$
4
6
221
1
61
556
38
594
19
17
46
26
—
$
8
261
442
3
93
32
1
33
34
34
123
—
—
$
4
—
442
5
72
—
1
1
33
34
122
—
—
$ —
—
5,195
—
76
—
2
2
17
143
317
—
25
Total contractual cash obligations
$8,514
$995
$1,031
$713
$5,775
(1) Amounts represent outstanding borrowings at December 31, 2016, plus any commitment and administrative
fees and interest.
(2) Amounts relate primarily to a long-term propane storage agreement and our office 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, 2016 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.
118
(7)
(8)
Includes the payable for Class B units recorded in connection with the MarkWest Merger (see Item 8.
Financial Statements and Supplementary Data—Note 4 for further discussion).
Excludes estimated accretion expense of $29 million. The total amount to be paid is approximately
$54 million.
In addition to the obligations included in the table above, we have an omnibus agreement and employee services
agreements with MPC. The omnibus agreement with MPC addresses our payment of a fixed annual fee to MPC
for the provision of executive management services by certain executive officers of our general partner and our
reimbursement to MPC for the provision of certain general and administrative services to us. The omnibus
agreement remains in full force and effect as long as MPC controls our general partner. Under the omnibus
agreement, we pay to MPC in equal monthly installments an annual amount of approximately $51 million in
2016 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 $12 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 any out-of-pocket costs and expenses incurred by MPC on our behalf.
We have four employee services agreements with MPC. Two of the employee services agreements with MPC
were entered into effective October 1, 2012, under which we agreed to reimburse MPC for the provision of
certain operational and management services to us in support of our pipelines, barge dock, butane cavern and
tank farms within the L&S segment. Effective December 28, 2015, we entered into an additional employee
services agreement with MPC, which requires that we reimburse MPC for certain operational and management
services to us in support of our G&P segment and certain of our other operations. Lastly, we are party to an
employee services agreement with MPC dated as of January 1, 2015, pursuant to which HSM reimburses MPC
for employee benefit expenses along with certain operation and management services provided in support of
HSM’s areas of operation. The agreement is effective until December 31, 2019. We incurred $359 million of
expenses under the employee services agreements for 2016.
Off-Balance Sheet Arrangements
As of December 31, 2016, 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 a persistence or increase of the current yield on
119
common units, which is higher than historical yields, adversely affecting the Partnership’s ability to meet its
distribution growth guidance; the time, costs and ability to obtain regulatory or other approvals and consents and
otherwise consummate the strategic initiatives discussed herein and other proposed transactions; the satisfaction
or waiver of conditions in the agreements governing the strategic initiatives discussed herein and other proposed
transactions; our ability to achieve the strategic and other objectives related to the strategic initiatives and
transactions discussed herein, including the dropdowns proposed by MPC, the joint venture with Antero
Midstream Partners LP, the Ozark pipeline, and other proposed transactions; adverse changes in laws including
with respect to tax and regulatory matters; inability to agree with respect to the timing of and value attributed to
assets identified for dropdown; the adequacy of the Partnership’s capital resources and liquidity, including, but
not limited to, availability of sufficient cash flow to pay distributions, and the ability to successfully execute its
business plans and growth strategy; continued/further volatility in and/or degradation of market and industry
conditions; changes to the expected construction costs and timing of projects; completion of midstream
infrastructure by competitors; disruptions due to equipment interruption or failure, including electrical shortages
and power grid failures; the suspension, reduction or termination of MPC’s obligations under the Partnership’s
commercial agreements; modifications to earnings and distribution growth objectives; the level of support from
MPC, including dropdowns, alternative financing arrangements, taking equity units, and other methods of
sponsor support, as a result of the capital allocation needs of the enterprise as a whole and its ability to provide
support on commercially reasonable terms; compliance with federal and state environmental, economic, health
and safety, energy and other policies and regulations and/or enforcement actions initiated thereunder; changes to
the Partnership’s capital budget; prices of and demand for natural gas, NGLs, crude oil and refined products,
delays in obtaining necessary third-party approvals and governmental permits, changes in labor, material and
equipment costs and availability, planned and unplanned outages, the delay of, cancellation of or failure to
implement planned capital projects, project overruns, disruptions or interruptions of our operations due to the
shortage of skilled labor 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, 2016, 2015
or 2014. 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
MPC owns our general partner and an approximate 23.5 percent limited partner interest (including the Class B
units on an as-converted basis) in us as of February 13, 2017 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 30 percent, 79 percent and 90 percent of our
total revenues and other income for 2016, 2015 and 2014, 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 20 percent, 35 percent and 41 percent for 2016, 2015 and
2014, respectively. MPC performed certain services for us related to information technology, engineering, legal,
accounting, treasury, human resources and other administrative services.
120
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.
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)
Capital
Percent of total capital expenditures
Compliance:
Operating and maintenance
Remediation(1)
Total
2016
$10
2015
$ 2
2014
$ 2
1%
1%
3%
$75
2
$77
$22
2
$24
$22
2
$24
(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 $3 million in 2017. Actual expenditures
may vary as the number and scope of environmental projects are revised as a result of improved technology or
121
changes in regulatory requirements and could increase if additional projects are identified or additional
requirements are imposed. The amount of expenditures in 2017 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.
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.
122
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 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
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 MarkWest Merger. That
acquisition was completed
effective December 4, 2015.
123
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Estimates and Assumptions
goodwill or a bargain purchase gain,
respectively. A significant amount of
judgment is involved in estimating
the individual fair values of property,
plant and equipment, intangible
assets, 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 interest,
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 a reporting unit 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 is the
plant level for our G&P segment, the
pipeline system level for our L&S
segment, and the customer
As of December 31, 2016, there
were no indicators of
impairment for any of our long-
lived assets.
Management considers the volume
of reserves dedicated to be
processed by the asset and future
NGL product and natural gas
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 reserves 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 considered the
124
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Estimates and Assumptions
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, 2016. We
determined the fair value of our
reporting units in both the G&P
and L&S segments using the
income and market approaches for
our 2016 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 2016 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 three 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
125
The Partnership recorded
approximately $130 million of
impairment expense related to
charges recorded during the first
and second quarters of the fiscal
year. We recorded no
impairment charge related to our
annual impairment review of
goodwill as of November 30,
2016. 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 7.8 percent to
14.5 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, 2016, the
Partnership had five reporting
units with goodwill: Marcellus
($1.8 billion), East Texas ($228
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
million), West Texas ($41
million), HSM ($11 million),
and MPL ($105 million). Step 1
of the fourth quarter impairment
analysis resulted in the fair
value of the reporting units
exceeding their carrying value
by approximately 28 percent,
8 percent, 44 percent,
303 percent and 167 percent,
respectively. An increase of
0.50 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, 2016. Our fourth
quarter analysis resulted in a
significant increase in the fair
value of the reporting units as
compared to the interim
analyses performed during 2016.
This increase was generally
supported by an increase in our
market capitalization of
approximately 49 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
commodity prices and
producers’ production plans, 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.
126
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Estimates and Assumptions
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
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.
Our impairment assessment
requires us to apply judgment in
estimating future cash flows
received from or attributable to
our equity method investments.
The primary estimates may
include the expected volumes, the
terms of related customer
agreements and future commodity
prices.
127
A fixed asset impairment
analysis was performed during
the second quarter for Ohio
Condensate Company (OCC)
resulting in an 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 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 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
Effect if Actual Results Differ from
Estimates and Assumptions
determinations require
considerable judgment and are
sensitive to changes in
underlying assumptions and
factors. As such, the fair value
of the OCC equity method
investment and its underlying
fixed assets represents a Level 3
measurement.
As of December 31, 2016,
Management determined that
there were no material events or
changes in circumstances that
would indicate an other-than-
temporary decline in our equity
method investments.
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
derivatives at December 31,
2016 would have affected
income before income taxes by
approximately $6 million for the
year ended December 31, 2016.
Description
Judgments and Uncertainties
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.
128
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Estimates and Assumptions
Accounting for Significant Embedded
Derivative Instruments
Identifying and 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
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.
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
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 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,
2016, we have estimated the
probability that the producer
customer will exercise its option
to extend the agreements for the
first renewal period is 50 percent,
and for the second renewal period
is 75 percent based on the inherent
uncertainty of the variables that
would impact its decision.
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
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 an
18 percent increase (decrease) in
the liability as of December 31,
2016. Holding the NGL curves
constant, a 10 percent increase
(decrease) in the natural gas
curves causes a 6 percent
(decrease) increase in the
liability as of December 31,
2016. 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, 2016, the
liability would be reduced by
23 percent. 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
88 percent.
See Item 8. Financial Statements
and Supplementary Data—Note
15 for more information related
to the Natural Gas Embedded
Derivative.
129
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Estimates and Assumptions
Variable Interest Entities
We evaluate all legal entities in
which we hold an ownership or other
pecuniary interest to determine if the
entity is a VIE.
Significant judgment is exercised
in determining that a legal entity is
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.
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.
130
MarkWest Utica EMG, Ohio
Condensate and Jefferson Dry
Gas are VIEs; however, we are
not considered to be the primary
beneficiary. As a result, they are
accounted for under the equity
method. Changes in the design
or nature of the activities of
these entities, or our
involvement with an entity, 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. If we were to consolidate
MarkWest Utica EMG, Ohio
Gathering would need to be
assessed for consolidation or
deconsolidation.
We account for our ownership
interest in Centrahoma and
MarkWest Pioneer under the
equity method and have
determined that these entities are
not VIEs. However, changes in
the design or nature of the
activities of either entities 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
Effect if Actual Results Differ from
Estimates and Assumptions
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
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
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.
131
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk
from commodity price changes and, to a lesser extent, interest rate changes and non-performance by our
customers and counterparties.
Commodity Price Risk
NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well
as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional
factors that are beyond the Partnership’s control. Our profitability is directly affected by prevailing commodity
prices primarily as a result of processing or conditioning at our own or third-party processing plants, purchasing
and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party
transportation and fractionation services. To the extent that commodity prices influence the level of natural gas
drilling by our producer customers, such prices also affect profitability. To protect us financially against adverse
price movements and to maintain more stable and predictable cash flows so that we can meet our cash
distribution objectives, debt service and capital plans, we execute a strategy governed by our risk management
policy. We have a committee comprised of senior management that oversees risk management activities,
continually monitors the risk management program and adjusts our strategy as conditions warrant. We enter into
certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas,
NGLs and crude oil. Derivative contracts utilized are swaps traded on the OTC market and fixed price forward
contracts. The risk management policy does not allow us to take speculative positions with our derivative
contracts.
To mitigate our cash flow exposure to fluctuations in the price of NGLs, we have entered into derivative financial
instruments relating to the future price of NGLs and crude oil. We currently manage the majority of our NGL
price risk using direct product NGL derivative contracts. We enter into NGL derivative contracts when adequate
market liquidity exists and future prices are satisfactory. A small portion of our NGL price exposure is managed
by using crude oil contracts. Based on our current volume forecasts, we expect the majority of our derivative
positions used to manage our future commodity price exposure will be direct product NGL derivative contracts.
To mitigate our cash flow exposure to fluctuations in the price of natural gas, we primarily utilize derivative
financial instruments relating to the future price of natural gas and take 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 believe that we have mitigated a portion of our expected
commodity price risk through the fourth quarter of 2017. We would be exposed to additional commodity risk in
certain situations such as if producers under-deliver or over-deliver products or if processing facilities are
operated in different recovery modes. In the event that we have derivative positions in excess of the product
delivered or expected to be delivered, the excess derivative positions may be terminated.
Management conducts a standard credit review on counterparties to derivative contracts, and we have provided
the counterparties with a guaranty as credit support for our obligations. A separate agreement with certain
counterparties allows MarkWest Liberty Midstream to enter into derivative positions without posting cash
collateral. We use standardized agreements that allow for offset of certain positive and negative exposures in the
event of default or other terminating events, including bankruptcy.
132
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, 2016, including the weighted-average prices (“WAVG”):
WTI Crude Swaps
2017
Natural Gas Swaps
2017
Ethane Swaps
2017
Propane Swaps
2017
IsoButane Swaps
2017
Volumes (Bbl/d)
WAVG Price (Per Bbl)
Fair Value
(in thousands)
100
$52.10
$ (152)
Volumes (MMBtu/d)
WAVG Price (Per MMBtu)
Fair Value
(in thousands)
814
$ 2.93
$
149
Volumes (Gal/d)
WAVG Price (Per Gal)
Fair Value
(in thousands)
42,000
$ 0.26
$ (433)
Volumes (Gal/d)
WAVG Price (Per Gal)
Fair Value
(in thousands)
74,370
$ 0.56
$(3,173)
Volumes (Gal/d)
WAVG Price (Per Gal)
Fair Value
(in thousands)
5,063
$ 0.71
$ (314)
Normal Butane Swaps
Volumes (Gal/d)
WAVG Price (Per Gal)
Fair Value
(in thousands)
2017
22,862
$ 0.71
$(1,051)
Natural Gasoline Swaps
Volumes (Gal/d)
WAVG Price (Per Gal)
Fair Value
(in thousands)
2017
31,628
$ 1.10
$(1,208)
133
The following table provides information on the derivative positions related to long liquids price risk as of
February 13, 2017 that we have entered into subsequent to December 31, 2016, including the WAVG:
WTI Crude Swaps
2017 (Apr.—Dec.)
Natural Gas Swaps
2017 (Apr.—Dec.)
Natural Gas Swaps
2018
Ethane Swaps
2017 (Apr.—Dec.)
Propane Swaps
2017 (Apr.—Dec.)
Propane Swaps
2018
IsoButane Swaps
2017 (Apr.—Dec.)
IsoButane Swaps
2018
Normal Butane Swaps
2017 (Apr.—Dec.)
Normal Butane Swaps
2018
Natural Gasoline Swaps
2017 (Apr.—Dec.)
Natural Gasoline Swaps
2018
Volumes (Bbl/d)
WAVG Price
(Per Bbl)
112
$56.40
Volumes (MMBtu/d)
WAVG Price
(Per MMBtu)
1,141
$ 3.11
Volumes (MMBtu/d)
WAVG Price
(Per MMBtu)
2,542
$ 2.78
Volumes (Gal/d)
WAVG Price
(Per Gal)
14,143
$ 0.28
Volumes (Gal/d)
WAVG Price
(Per Gal)
49,180
$ 0.67
Volumes (Gal/d)
WAVG Price
(Per Gal)
16,925
$ 0.64
Volumes (Gal/d)
WAVG Price
(Per Gal)
7,206
$ 0.87
Volumes (Gal/d)
WAVG Price
(Per Gal)
1,655
$ 0.80
Volumes (Gal/d)
WAVG Price
(Per Gal)
8,591
$ 0.85
Volumes (Gal/d)
WAVG Price
(Per Gal)
4,595
$ 0.75
Volumes (Gal/d)
WAVG Price
(Per Gal)
8,494
$ 1.21
Volumes (Gal/d)
WAVG Price
(Per Gal)
3,089
$ 1.18
We have a commodity contract with a producer customer in the Southern Appalachian region that creates a floor
on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader
regional arrangement that also includes a keep-whole processing agreement. For accounting purposes, these
contracts have been aggregated into a single contract and are evaluated together. In February 2011, we executed
agreements with the producer customer to extend the commodity contract and the related processing agreement
from March 31, 2015 to December 31, 2022, with the producer customer’s option to extend the agreement for
two successive five year terms through December 31, 2032. The purchase of gas at prices based on the frac
spread and the option to extend the agreements have been identified as a single embedded derivative, which is
recorded at fair value. The probability of renewal is determined based on extrapolated pricing curves, a review of
the overall expected favorability of the contracts based on such pricing curves, and assumptions about the
134
counterparty’s potential business strategy decision points that may exist at the time the counterparty would elect
whether to renew the contracts. The changes in fair value of this embedded 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, 2016, the estimated fair value of this contract was a liability of $54 million.
During the years ended December 31, 2016 and 2015, the Partnership had a commodity contract that allowed for
the Partnership to fix a component of the utilities cost to an index price on electricity at a plant location in the
Southwest Operations which expired as of December 31, 2016. Changes in the fair value of the derivative
component of this contract were recognized as Cost of revenues in the Consolidated Statements of Income. As of
December 31, 2015, the estimated fair value of this contract was a liability of $1 million.
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, 2016(1) Change in Fair Value(2)
Change in income before
income taxes for the
Year Ended
December 31, 2016(3)
$4,703
$ 250
$304
N/A
N/A
5
$
(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, 2016.
(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, 2016.
At December 31, 2016, our portfolio of long-term debt consisted of fixed-rate instruments and variable-rate
instruments under our term loan 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, 2016, 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.
135
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. This counterparty credit risk does not apply to our embedded derivatives
as the overall values are liabilities.
136
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
138
138
139
140
141
142
143
144
203
137
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/ Paula L. Rosson
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)
Paula L. Rosson
Senior Vice President
and Chief Accounting Officer
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, 2016.
The effectiveness of MPLX LP’s internal control over financial reporting as of December 31, 2016 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)
138
Report of Independent Registered Public Accounting Firm
To the Partners of MPLX LP and the Board of Directors of MPLX GP LLC
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income,
of equity and of cash flows present fairly, in all material respects, the financial position of MPLX LP and its
subsidiaries at December 31, 2016 and 2015, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2016 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, 2016, based on criteria established in
Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company’s management is responsible for these 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 these financial statements and on the
Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in
accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial
statements are free of material misstatement and whether effective internal control over financial reporting was
maintained in all material respects. Our audits of the financial statements included examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall financial statement presentation.
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.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable
assurance that transactions are recorded as necessary to permit preparation 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 24, 2017
139
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
(Loss) income from equity method investments
Other income
Other income—related parties
Total revenues and other income
Costs and expenses:
Cost of revenues (excludes items below)
Purchased product costs
Rental cost of sales
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 $28 million, $5 million, and
$1 million, respectively)
Other financial costs
Income before income taxes
(Benefit) provision for income taxes
Net income
Less: Net income attributable to noncontrolling interests
Less: Net income attributable to Predecessor
Net income attributable to MPLX LP
Less: Preferred unit distributions
Less: General partner’s interest in net income attributable to MPLX LP
2016
2015
2014
$
$
958
603
298
114
572
11
1
(74)
6
101
2,590
354
448
53
316
546
130
193
43
2,083
507
1
210
50
246
(12)
258
2
23
233
41
191
$
130
593
20
101
36
1
—
3
6
71
961
225
20
5
166
116
—
118
13
663
298
—
35
13
250
1
249
1
92
156
—
57
70
662
—
15
—
—
—
—
6
40
793
228
—
1
153
75
—
81
10
548
245
—
4
1
240
1
239
57
61
121
—
6
115
Limited partners’ interest in net income attributable to MPLX LP
$
1
$
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
$ — $
—
—
1.23
1.22
0.11
$
1.55
1.55
1.50
331
338
—
$2.0500
79
80
18
$1.8200
37
37
37
$1.4100
The accompanying notes are an integral part of these consolidated financial statements.
140
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 (271 million and 240 million units issued and outstanding)
Class B unitholders (4 million and 8 million units issued and outstanding)
Common unitholder—MPC (86 million and 57 million units issued and outstanding)
General partner—MPC (7 million units issued and outstanding)
Equity of Predecessor
Total MPLX LP partners’ capital
Noncontrolling interest
Total equity
December 31,
2016
2015
$
$
234
297
122
54
33
740
2,467
10,730
492
2,199
4
14
43
245
187
51
50
576
2,458
9,997
466
2,570
25
12
$16,646
$16,104
$
123
228
75
2
34
132
33
53
24
704
12
15
4,422
5
169
5,327
$
91
187
54
—
32
168
27
54
12
625
4
9
5,255
378
166
6,437
1,000
—
8,086
133
1,069
1,013
—
10,301
18
10,319
7,691
266
465
819
413
9,654
13
9,667
Total liabilities, preferred units and equity
$16,646
$16,104
The accompanying notes are an integral part of these consolidated financial statements.
141
MPLX LP
Consolidated Statements of Cash Flows
(In millions)
2016
2015
2014
Increase (decrease) 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
Loss (income) from equity method investments
Distributions from unconsolidated affiliates
Changes in:
Current receivables
Inventories
Change in fair value of derivatives
Current accounts payable and accrued liabilities
Receivables from / liabilities to related parties
All other, net
Net cash provided by operating activities
Investing activities:
Additions to property, plant and equipment
Acquisitions, net of cash acquired
Investments—loans to (from) related parties
Disposal of assets
Investments in unconsolidated affiliates
All other, net
$
258
$
249
$ 239
46
546
130
(17)
(5)
(1)
74
148
(52)
(8)
43
100
6
20
1,288
(1,206)
—
77
1
(87)
3
5
116
—
1
(1)
—
(3)
15
(29)
1
(6)
2
(22)
12
340
(288)
(1,218)
(77)
—
(14)
(2)
1
75
—
—
(2)
—
—
—
2
1
—
1
15
2
334
(141)
—
—
—
—
4
Net cash used in investing activities
(1,212)
(1,599)
(137)
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 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 (used in) financing activities
Net increase in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
434
(1,312)
2,532
(2,540)
—
792
984
—
—
(25)
(845)
(3)
6
(25)
225
—
(104)
(4)
1,490
(1,441)
301
(293)
(11)
1
—
169
1,230
—
(158)
(1)
—
—
—
(12)
—
—
115
191
43
234
1,275
16
27
43
$
$
1,160
(526)
—
—
(3)
230
—
—
—
—
(103)
(47)
—
—
—
(910)
(25)
—
(224)
(27)
54
$
27
The accompanying notes are an integral part of these consolidated financial statements.
142
MPLX LP
Consolidated Statements of Equity
Partnership
(In millions)
Common
Unitholders
Public
Class B
Unitholders
Public
Common
Unitholder
MPC
Subordinated
Unitholder
MPC
General Partner
MPC
Noncontrolling
Interest
Equity of
Predecessor Total
Balance at December 31, 2013
$ 412
$ —
$
57
$ 209
$ (32)
$ 468
$ 285 $ 1,399
200
—
27
—
—
—
58
—
(23)
(50)
Purchase/contribution of additional
interest in Pipe Line Holdings
Equity offering, net of issuance costs
Net income
Distributions to MPC from
Predecessor
Distributions to unitholders and
general partner
Distributions to noncontrolling
interest retained by MPC
Equity-based compensation
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
Equity-based compensation
Deferred income tax impact from
changes in equity
Issuance of units in MarkWest
Merger
Noncontrolling interest 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
interest
Contributions from noncontrolling
interest
Class B unit conversion
Equity-based compensation
Deferred income tax impact from
changes in equity
—
221
31
—
(26)
—
1
639
—
—
1
15
(40)
—
17
(1)
7,060
—
7,691
—
—
—
—
776
(5)
—
(513)
—
—
133
6
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
266
—
266
—
—
—
—
—
—
—
—
—
—
(133)
—
—
—
261
—
—
—
36
(52)
—
220
—
—
—
—
465
—
84
—
—
—
6
669
(142)
—
—
—
—
—
—
217
—
—
—
48
(45)
—
(220)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(638)
9
5
—
(4)
—
—
(660)
(6)
1,280
—
57
(21)
—
—
—
169
—
819
—
141
(188)
563
16
191
(337)
(190)
—
—
—
—
(2)
(472)
—
57
—
—
(47)
—
6
(6)
—
—
—
1
(1)
—
—
—
13
13
—
—
—
—
—
2
—
—
(3)
6
—
—
—
—
—
61
(910)
230
239
(25)
(25)
—
—
—
321
—
(103)
(47)
1
784
(12)
— 1,280
—
92
—
—
—
—
1
249
(158)
(1)
—
17
(1)
— 7,495
—
13
413
9,667
(104)
—
—
—
—
23
(104)
225
(188)
563
792
217
(332) —
—
—
—
—
—
—
(845)
(3)
6
—
6
(17)
(2)
—
(13)
Balance at December 31, 2016
$8,086
$ 133
$1,069
$ —
$1,013
$ 18
$ — $10,319
The accompanying notes are an integral part of these consolidated financial statements.
143
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 gathering, transportation and storage of crude oil and refined petroleum
products. 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 public
offering (the “Initial Offering”) on October 31, 2012. On December 4, 2015, a wholly-owned subsidiary of the
Partnership merged with MarkWest Energy Partners L.P. (the “MarkWest Merger”), which is 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. This acquisition is discussed further in Note 4. Effective March 31, 2016, the Partnership
acquired MPC’s inland marine business, Hardin Street Marine LLC. The acquisition is also described further in
Note 4. Unless the context otherwise requires, references in this report to “MPLX LP,” the “Partnership,” 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”), MPLX Pipe Line Holdings LLC (“Pipe Line
Holdings”), Marathon Pipe LLC (“MPL”), Ohio River Pipe Line LLC (“ORPL”) and Hardin Street Marine LLC
(“HSM”). References to “MPC” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other
than the Partnership. References to “Predecessor” refer collectively to HSM’s related assets, liabilities and results
of the operations.
The Partnership’s business consists of two segments: Logistics and Storage (“L&S”) and Gathering and
Processing (“G&P”). 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,
including MPC, have been recorded as Noncontrolling interest 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
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
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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.
L&S Segment
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. When MPC ships volumes on our pipeline
systems under a joint tariff with a third party, those revenues are recorded as sales and other operating revenues,
and not as sales to related parties, because we receive payment from the third party. Revenues are recognized for
crude oil and refined product storage as performed based on contractual rates. Operating fees received for
operating pipeline systems are recognized as a component of other income in the period the service is performed.
All such amounts are reported as Service revenue on the Consolidated Statements of Income.
Under our MPC transportation services agreements, 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. MPC may then apply the amount of any such deficiency payments as a credit for
volumes transported on the applicable pipeline system in excess of its minimum volume commitment during the
following four or eight quarters under the terms of the applicable transportation services agreement. 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 or eight quarter
period. The use or expiration of the credits is a decrease in Deferred revenue—related parties. 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.
HSM is a provider of marine transportation services for its customers and does not assume ownership of the
products it transports. The Partnership transports cargo from a designated origin to a designated destination at a
pre-established fixed rate. Costs incurred as part of moving the products are paid by the customer subsequent to
April 1, 2016.
G&P Segment
The Partnership generates the majority of its G&P segment revenues from natural gas gathering, transportation
and processing; NGL gathering, transportation, fractionation, marketing and storage; and crude oil gathering and
transportation. The Partnership disaggregates revenue as Product sales, Service revenue and Rental income on
the Consolidated Statements of Income. Revenue is reported as follows:
• Product sales—Product sales represent the sale of NGLs, condensate and natural gas. The product is
primarily obtained as consideration for or related to providing midstream services.
•
Service revenue—Service revenue represents all other revenue generated as the result of performing the
services listed above.
• Rental income—Rental income represents revenue generated as the result of implicit operating lease
arrangements.
The Partnership enters into a variety of contract types in order to generate Product sales and Service revenue.
The Partnership provides services under the following different types of arrangements:
• Fee-based arrangements—Under fee-based arrangements, the Partnership receives a fee or fees for one
or more of the following services: gathering, processing and transportation of natural gas; gathering,
transportation, fractionation, exchange and storage of NGLs; and gathering and transportation of crude
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oil. The revenue the Partnership earns from these arrangements is generally directly related to the
volume of natural gas, NGLs or crude oil that flows through the Partnership’s systems and facilities
and is not normally directly dependent on commodity prices. In certain cases, the Partnership’s
arrangements provide for minimum annual payments or fixed demand charges.
•
Fee-based arrangements are reported as Service revenue on the Consolidated Statements of
Income. In certain instances when specifically stated in the contract terms, the Partnership
purchases product after fee-based services have been provided. Revenue from the sale of products
purchased after services are provided is reported as Product sales on the Consolidated Statements
of Income and recognized on a gross basis as the Partnership is the principal in the transaction.
• Percent-of-proceeds arrangements—Under percent-of-proceeds arrangements, 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, 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.
• Percent-of-index arrangements—Under percent-of-index arrangements, the Partnership purchases
natural gas 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 then gathers and delivers the natural gas to pipelines where the Partnership resells the
natural gas at the index price or at a different percentage discount to the index price. Revenue
generated from percent-of-index 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. The terms of the Partnership’s 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
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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. 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 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 customer 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. 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. Revenues and costs related to the portion of the revenue earned
under these contracts considered to be implicit leases are recorded as Rental income and Rental cost of sales,
respectively, on the Consolidated Statements of Income. Similarly, the Partnership is considered to be the lessor
under implicit operating lease arrangements with MPC in accordance with GAAP. The Partnership’s primary
implicit lease operations with MPC relate to the transportation services agreement between HSM and MPC.
Revenue related to this agreement is recorded as Rental income-related parties on the Consolidated Statements
of Income. The rental cost of sales related to the HSM implicit lease is depreciation of the HSM assets. All other
services are provided to MPC on an as-needed basis and recorded as Service revenue-related parties on the
Consolidated Statements of Income.
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 system. At December 31, 2016
and 2015, the amount of restricted cash included in Other current assets on the Consolidated Balance Sheets was
$5 million and $9 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 is 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.
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Imbalances—Within our pipelines and storage assets we experience volume gains and losses due to pressure and
temperature changes, evaporation and variances in meter readings and other measurement methods. Until settled,
positive imbalances are recorded as other current assets and negative imbalances are recorded as accounts
payable. Positive and negative product imbalances are settled in cash, settled by physical delivery of gas from a
different source, or tracked and settled in the future.
Property, Plant and Equipment—Property, plant and equipment are recorded at cost. 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
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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
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 interest, 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, 2015 and November 30, 2016
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. A receivable is recorded for environmental costs indemnified by
MPC.
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
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recognized in the period when sufficient information becomes available to estimate a range of potential
settlement dates.
Investment in Unconsolidated Affiliates—Equity investments in which 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—Derivative instruments (including derivative instruments embedded in other contracts)
are recorded at fair value and are reflected in the Consolidated Balance Sheets on a net basis, as either an asset or
liability, as they are governed by the master netting agreements. The Partnership discloses the fair value of all of
its derivative instruments under the captions Other noncurrent assets, Other current liabilities and Deferred
credits and other liabilities on the Consolidated Balance Sheets, inclusive of option premiums, if any. 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. 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, 2016, 2015 and 2014, the Partnership did not designate any hedges or
designate any contracts as normal purchases and normal sales, with the exception of electricity contracts, for
which the normal purchases and normal sales designation was elected during the year ended December 31, 2016.
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 a fair value hierarchy established by GAAP, which classifies the inputs used
to measure fair value into the following levels:
• Level 1 inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or
liabilities in active markets.
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• Level 2 inputs to the valuation methodology include quoted prices for similar assets and liabilities in
active markets and inputs that are observable for the asset or liability, either directly or indirectly, for
substantially the full term of the financial instrument.
• Level 3 inputs to the valuation methodology are unobservable and significant to the fair value
measurement.
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 determination to classify a financial instrument within Level 3 of the valuation hierarchy is based upon the
significance of the unobservable inputs to the overall fair value measurement. However, Level 3 financial
instruments typically include, in addition to the unobservable or Level 3 inputs, observable inputs (that is, inputs
that are actively quoted and can be validated to external sources); accordingly, the gains and losses for Level 3
financial instruments include changes in fair value due in part to observable inputs that are part of the valuation
methodology. Level 3 financial instruments include crude oil options, all NGL derivatives and the embedded
derivatives in commodity contracts discussed in Note 15 as they have significant unobservable inputs.
The methods and assumptions described above 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 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.
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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. 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
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 incentive distribution rights
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 incentive distribution rights. 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 incentive distribution rights
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
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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 incentive distribution
rights, 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 interest, 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 acquired, liabilities assumed, and
noncontrolling interest, 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 MarkWest Merger.
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 September 2015, the FASB issued an accounting standard update that eliminates the requirement to restate
prior period financial statements for measurement period adjustments related to business combinations. This
accounting standard update requires that the cumulative impact of a measurement period adjustment be
recognized in the reporting period in which the adjustment is identified. The change was effective for interim and
annual periods beginning after December 15, 2015. The Partnership recognized measurement period adjustments
during the first and second quarters of 2016 on a cumulative prospective basis as additional analysis was
completed on the preliminary purchase price allocation for the acquisition of MarkWest. See Notes 4 and 18 for
further discussion and detail related to these measurement period adjustments.
153
In April 2015, the FASB issued an accounting standard update requiring that the earnings of transferred net
assets prior to the dropdown date of the net assets to a master limited partnership be allocated entirely to the
general partner when calculating earnings per unit under the two class method. Under this guidance, previously
reported earnings per unit of the limited partners will not change as a result of a dropdown transaction. The
change was effective for fiscal years and interim periods within those fiscal years beginning after December 15,
2015. Retrospective application is required. The Partnership adopted this accounting standard update in the first
quarter of 2016 and it did not have a material impact on the consolidated financial statements.
In April 2015, the FASB issued an accounting standard update clarifying whether a customer should account for
a cloud computing arrangement as an acquisition of a software license or as a service arrangement by providing
characteristics that a cloud computing arrangement must have in order to be accounted for as a software license
acquisition. The change was effective for fiscal years and interim periods within those fiscal years beginning
after December 15, 2015. Retrospective or prospective application is allowed. The Partnership adopted this
accounting standard update prospectively in the first quarter of 2016 and it did not have a material impact on the
consolidated financial statements.
In February 2015, the FASB issued an accounting standard update making targeted changes to the current
consolidation guidance. The accounting standard update changes the considerations related to substantive rights,
related parties, and decision making fees when applying the VIE consolidation model and eliminates certain
guidance for limited partnerships and similar entities under the voting interest consolidation model. The change
was effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2015.
The Partnership adopted this accounting standard update in the first quarter of 2016 and it did not have a material
impact on the consolidated financial statements.
In August 2014, the FASB issued an accounting standard update requiring management to assess an entity’s
ability to continue as a going concern and to provide related footnote disclosures in certain circumstances.
Management is required to assess if there is substantial doubt about an entity’s ability to continue as a going
concern within one year after the issuance of the financial statements. Disclosures are required if conditions give
rise to substantial doubt and the type of disclosure is determined based on whether management’s plans will be
able to alleviate the substantial doubt. The change was effective for the first fiscal period ending after
December 15, 2016, and for fiscal periods and interim periods thereafter. The adoption of this accounting
standard update in the fourth quarter of 2016 did not have a material impact on the Partnership’s disclosures.
Not Yet Adopted
In January 2017, the FASB issued an accounting standard 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; however, the loss recognized should not exceed the total amount of goodwill allocated to that
reporting unit. The guidance should be applied on a prospective basis, and is effective for annual or any interim
goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for
interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Partnership is
in the process of determining the impact of the accounting standard update on the consolidated financial
statements.
In January 2017, the FASB issued an accounting standard 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 is
in the process of determining the impact of the accounting standard update on the consolidated financial
statements.
154
In November 2016, the FASB issued an accounting standard update requiring that the statement of cash flows
explain the change during the period in the total of cash, cash equivalents, and amounts generally described as
restricted cash or restricted cash equivalents. The change is effective for fiscal years beginning after
December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. Retrospective
application is required. The application of this accounting standard update will not have a material impact on the
Consolidated Statements of Cash Flows.
In October 2016, the FASB issued an accounting standard 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 is effective for the financial statements for fiscal years beginning after December 15, 2016, and interim
periods within those fiscal years, with early adoption permitted. The Partnership is required to apply the standard
retrospectively to January 1, 2016. The Partnership has analyzed the accounting standard update and does not
expect an impact on the consolidated financial statements.
In August 2016, the FASB issued an accounting standard update related to the classification of certain cash
flows. The accounting standard update provides specific guidance on eight cash flow classification issues,
including debt prepayment or debt extinguishment costs and distributions received from equity method investees.
The change is effective for fiscal years beginning after December 15, 2017, and interim periods within those
fiscal years, with early adoption permitted. The Partnership does not expect application of this accounting
standard update to have a material impact on the Consolidated Statements of Cash Flows.
In June 2016, the FASB issued an accounting standard 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 standard update to have a material impact on the
consolidated financial statements.
In March 2016, the FASB issued an accounting standard update on the accounting for employee share-based
payments. This accounting standard update requires the recognition of income tax effects of awards through the
income statement when awards vest or are settled. It will also increase 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 are effective for fiscal years beginning after December 15,
2016, and interim periods within those fiscal years, and early adoption is permitted. Under the new guidance, the
Partnership intends to continue estimating forfeiture rates to calculate compensation cost. The application of this
accounting standard update will not have a material impact on the Partnership’s consolidated financial
statements.
In February 2016, the FASB issued an accounting standard update requiring lessees to record virtually all leases
on their balance sheets. The accounting standard 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 our financial statements and disclosures, internal controls,
and accounting policies. This evaluation process includes reviewing all forms of leases, performing a
completeness assessment over the lease population and analyzing the practical expedients in order to determine
the best path to implementation. The Partnership does not plan to early adopt the standard.
155
In January 2016, the FASB issued an accounting standard 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 accounting standard 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 accounting
standard 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 standard 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 application of this accounting standard
update will not have a material impact on the Partnership’s consolidated financial statements.
In May 2014, the FASB issued an initial accounting standard update for revenue recognition for contracts with
customers. The guidance in the accounting standard 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 then recognizing the revenue as the obligations are
satisfied. 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 change will be
effective on a retrospective or modified retrospective basis for fiscal years beginning after December 15, 2017,
and interim periods within those years, with early adoption permitted no earlier than January 1, 2017.
The Partnership is currently evaluating the impact of the revenue recognition standard on the Partnership’s
financial statements and disclosures, internal controls, and accounting policies. This evaluation process includes
a phased approach, the first phase of which includes reviewing a sample of our contracts and transaction types
across our segments. The Partnership is currently in the process of completing this first phase and evaluating the
methods of adoption.
Based on the results of the first phase assessment to date, the Partnership has reached tentative conclusions for
some contract types and does not believe revenue recognition patterns for fee-based or percent-of-proceeds
contracts will change materially. The Partnership is currently working to understand the accounting impact on
keep-whole and percent-of-liquids agreements under the new standard, specifically related to the accounting for
noncash consideration received in the form of a commodity product. The Partnership does expect certain
amounts to be grossed up in revenue as a result of implementation. The Partnership continues to work through
implementation efforts and will provide updates as qualitative and quantitative conclusions are reached
throughout 2017.
4. Acquisitions
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 LLC (“MPLX GP”), MPLX Logistics Holdings LLC and MPC
Investment LLC (“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 general partner 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 MPLX LP common units issued in
156
connection with this transaction. MPC did not receive general partner distributions or incentive distribution rights
that would have otherwise accrued on such MPLX LP common units with respect to the first quarter
distributions. The value of these waived distributions was $15 million.
The inland marine business, comprised of 18 tow boats and 205 barges which transport light products, heavy oils,
crude oil, renewable fuels, chemicals and feedstocks in the Midwest and U.S. Gulf Coast regions, 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 as a reporting unit of the L&S segment.
The acquisition from MPC was a transfer between entities under common control. As an entity under common
control with MPC, the Partnership recorded the assets acquired from MPC on its consolidated Balance Sheets at
MPC’s historical basis instead of fair value. Transfers of businesses between entities under common control
require prior periods to be retrospectively adjusted to furnish comparative information. Accordingly, the
Partnership has retrospectively adjusted the historical financial results for all periods to include HSM.
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. Each Class B unit of MPLX LP will convert into 1.09 common units of MPLX LP and the right to
receive $6.20 in cash, and the conversion of the Class B units will occur in equal installments, the first of which
occurred on July 1, 2016 and the second of which will occur on 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 is payable in equal amounts, the first of which was paid in July 2016
and the second of which will be paid in 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
MarkWest from the date of the acquisition.
The components of the fair value of consideration transferred are as follows:
(In millions)
Fair value of units issued
Cash
Paid/payable to MarkWest Class B unitholders
Total fair value of consideration transferred
$7,326
1,230
50
$8,606
157
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, are 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 interest
Total liabilities and noncontrolling interest assumed
Net assets acquired excluding goodwill
Goodwill
Net assets acquired
As Originally
Reported
Adjustments
As Adjusted
$
$ —
—
(1)
$
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
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
—
143
43
65
—
250
—
6
—
—
—
3
—
—
9
241
(241)
$ 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 relates to a misstatement in the original preliminary purchase price allocation. The correction of the error
resulted in a $68 million reduction to the carrying value of goodwill and an offsetting increase of $64 million in
intangibles and $2 million in each of equity method investments and property, plant and equipment. Management
concluded that the correction of the error is immaterial to the consolidated financial statements of all periods
presented. 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.
158
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
represents the complimentary aspects of the highly diverse asset base of MarkWest and MPLX LP that will
provide 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 include 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 represent
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 include 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 include 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 are based on significant inputs that are 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 are 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
2014
$2,677
247
0.47
0.45
$2,972
330
1.09
1.03
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.
159
MarkWest has a 60 percent legal ownership interest in MarkWest Utica EMG for the years ended December 31,
2015 and 2014, respectively. 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 re-assessed. 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.
A summary of the amounts included in the historical financial statements of MarkWest for the year ended
December 31, 2014 and the period from January 1, 2015 through December 3, 2015 related to MarkWest Utica
EMG are as follows:
(in millions)
Revenue and other income
Cost of revenue excluding depreciation and amortization
Depreciation and amortization
Net income attributable to noncontrolling interest
Net loss
2015
2014
$152
27
61
64
(5)
$ 85
48
50
31
(46)
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 and $37 million for the period from January 1, 2015 through
December 3, 2015 and the year ended December 31, 2014, respectively. 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 year ended December 31, 2014 and the period from
January 1, 2015 through December 3, 2015.
Purchases of Pipe Line Holdings
Effective December 4, 2015, the Partnership purchased the remaining 0.5 percent interest in 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.
Effective December 1, 2014, the Partnership purchased a 22.875 percent interest in Pipe Line Holdings from
subsidiaries of MPC for consideration of $600 million, which was financed through borrowings under our bank
revolving credit facility, as discussed in Note 17. In addition, the Partnership accepted a contribution of
7.625 percent of outstanding partnership interests of Pipe Line Holdings from subsidiaries of MPC in exchange
for the issuance of equity valued at $200 million, as discussed in Note 8. The Partnership recorded the combined
30.5 percent interest at its historical carrying value of $335 million and the excess cash paid and equity
contributed over historical carrying value of $465 million as a decrease to general partner equity. Prior to this
transaction, the 30.5 percent interest was held by MPC and was reflected as part of the noncontrolling interest
retained by MPC in the consolidated financial statements. Beginning December 1, 2014, the consolidated
financial statements reflect the 99.5 percent general partner interest in Pipe Line Holdings owned by MPLX LP,
while the 0.5 percent limited partner interest held by MPC is reflected as a noncontrolling interest.
On March 1, 2014, the Partnership acquired a 13 percent interest in Pipe Line Holdings from MPC for
consideration of $310 million, which was funded with $40 million of cash on hand and $270 million of
160
borrowings on the bank revolving credit facility. The Partnership recorded the 13 percent interest in Pipe Line
Holdings at its historical carrying value of $138 million and the excess cash paid over historical carrying value of
$172 million as a decrease to general partner equity.
In addition, on May 1, 2013, the Partnership acquired a five percent interest in Pipe Line Holdings from MPC for
consideration of $100 million, which was funded with cash on hand. The Partnership recorded the five percent
interest in Pipe Line Holdings at its historical carrying value of $54 million and the excess cash paid over
historical carrying value of $46 million as a decrease to general partner equity.
These acquisitions were accounted for on a prospective basis and the terms of the acquisitions were approved by
the conflicts committee of the board of directors of the general partner, which is comprised entirely of
independent directors.
Changes in MPLX LP’s equity resulting from changes in its ownership interest in Pipe Line Holdings were as
follows:
(In millions)
Net income attributable to MPLX LP
Transfer to noncontrolling interest:
2015
$156
2014
$ 121
Decrease in general partner-MPC equity for purchases of
additional interest in Pipe Line Holdings
(6)
(638)
Change from net income attributable to MPLX LP and transfer to
noncontrolling interest
$150
$(517)
5. Equity Method Investments
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 (together 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 as currently in effect is
referred to as the “Amended LLC Agreement”). The aggregate funding commitment of EMG Utica was
$950 million (the “Minimum EMG Investment”). Thereafter, Utica Operating was required to fund, as needed,
100 percent of future capital for MarkWest Utica EMG until such time as the aggregate capital that had been
contributed by the Members reached $2 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, 2016, EMG Utica has contributed
$1 billion and Utica Operating has contributed approximately $1.5 billion to MarkWest Utica EMG.
Under the Amended LLC Agreement, after EMG Utica has contributed more than $500 million to MarkWest
Utica EMG and prior to December 31, 2016, EMG Utica’s investment balance will also be increased by a
quarterly special non-cash allocation of income (“Preference Amount”) that is based upon the amount of capital
contributed by EMG Utica in excess of $500 million. No Preference Amount will accrue to EMG Utica’s
investment balance after December 31, 2016. EMG Utica received a special non-cash allocation of income of
approximately $16 million and approximately $4 million for the year ended December 31, 2016 and for the 28
days ended December 31, 2015, respectively.
161
Under the Amended LLC Agreement, Utica Operating continued to receive 60 percent of cash generated by
MarkWest Utica EMG that was available for distribution until the earlier of December 31, 2016 or the date on
which Utica Operating’s investment balance equaled 60 percent of the aggregate investment balances of the
Members. 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, 2016,
Utica Operating’s investment balance in MarkWest Utica EMG was approximately 56 percent.
MarkWest Utica EMG is deemed to be a VIE. As of the date of the MarkWest Merger, Utica Operating is not
deemed to be the primary beneficiary due to EMG Utica’s voting rights on significant matters. The Partnership’s
portion of MarkWest Utica EMG’s net assets, which was $2.2 billion at December 31, 2016 and 2015,
respectively, is reported under the caption Equity Method Investments on the Consolidated Balance Sheets. The
Partnership’s maximum exposure to loss as a result of its involvement with 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 year ended December 31, 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). The
amount of Operational Service revenue related to MarkWest Utica EMG for the year ended December 31, 2016
and for the 28 days ended December 31, 2015 was $16 million and less than $1 million, respectively, and is
reported as Other income—related parties in the Consolidated Statements of Income.
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 (“Summit”). As of December 31, 2016, we have a 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. The amount of Operational Service revenue related to Ohio Gathering for
the year ended December 31, 2016 and the 28 days ended December 31, 2015 was approximately $15 million
and $2 million, respectively, and is reported as Other income—related parties in the Consolidated Statements of
Income.
Ohio Condensate
Ohio Condensate is a joint venture between MarkWest Utica EMG Condensate, L.L.C., a wholly-owned and
consolidated subsidiary of MarkWest, and Summit formed for the purpose of gathering (by pipeline),
stabilization, terminalling, transportation and storage of well-head condensate within certain defined areas in the
state of Ohio. 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. The Partnership’s portion of Ohio Condensate’s
net assets, which was $10 million and $100 million at December 31, 2016 and 2015, respectively, are reported
under the caption Equity method investments on the Consolidated Balance Sheets. The Partnership receives
Operational Service revenue for operating Ohio Condensate. The amount of Operational Service revenue related
to Ohio Condensate for the year ended December 31, 2016 and the 28 days ended December 31, 2015 was
$4 million and less than $1 million, respectively, and is reported as Other income—related parties in the
Consolidated Statements of Income.
162
Summarized financial information for the year ended December 31, 2016 and from the date of the MarkWest
Merger through December 31, 2015 for equity method investments is as follows:
(In millions)
Revenue and other income
Cost and expenses
Income (loss) from operations
Net income (loss)
Income (loss) from equity method investments(2)
(In millions)
Revenue and other income
Cost and expenses
Income from operations
Net income
Income from equity method investments(2)
MarkWest Utica
EMG
Year Ended December 31, 2016
Ohio
Condensate Other VIEs Non-VIEs
Total
$216
100
116
114
8
$ 15
110
(95)
(95)
(89)
$
3
1
2
2
—
$148
117
31
31
7
$382
328
54
52
(74)
MarkWest Utica
EMG
Year Ended December 31, 2015
Ohio
Condensate Other VIEs Non-VIEs
Total
$ 18
9
9
10
2
$
2
2
—
—
1
$—
—
—
—
—
$
9
8
1
1
—
$ 29
19
10
11
3
Summarized balance sheet information as of December 31, 2016 and 2015 for equity method investments is as
follows:
(In millions)
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
(In millions)
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
MarkWest Utica
EMG(1)
December 31, 2016
Ohio
Condensate Other VIEs Non-VIEs
Total
$
45
2,173
30
2
$
2
30
3
13
$—
102
1
—
$ 40
375
26
—
$
87
2,680
60
15
MarkWest Utica
EMG(1)
December 31, 2015
Ohio
Condensate Other VIEs Non-VIEs
Total
$ 113
2,207
77
1
$
7
127
6
12
$—
42
1
—
$ 30
243
18
—
$ 150
2,619
102
13
(1) MarkWest Utica EMG’s noncurrent assets includes its investment in its subsidiary Ohio Gathering, which
does not appear elsewhere in this table. The investment was $794 million and $781 million as of
December 31, 2016 and 2015, respectively.
Income (loss) from equity method investments includes the impact of any basis differential amortization or
accretion.
(2)
As of December 31, 2016 and 2015, the carrying value of our equity method investments was $1.1 billion and
$961 million, respectively, higher than the underlying net assets of investees. 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 as of December 31, 2016.
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
163
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.
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.
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.
• Centennial Pipeline LLC (“Centennial”), in which MPC has a 50 percent interest. Centennial owns a
products pipeline and storage facility.
• Muskegon Pipeline LLC (“Muskegon”), in which MPC has a 60 percent interest. Muskegon owns a
common carrier products pipeline.
• MarkWest Utica EMG, in which MPLX LP has a 56 percent interest as of December 31, 2016.
MarkWest Utica EMG is engaged in significant natural gas processing and NGL fractionation,
transportation and marketing in the state of Ohio.
• Ohio Gathering, in which MPLX LP has a 34 percent indirect interest as of December 31, 2016. Ohio
Gathering is a subsidiary of MarkWest Utica EMG providing natural gas gathering service in the Utica
Shale region of eastern Ohio.
• Ohio Condensate, in which MPLX LP has a 60 percent interest. Ohio Condensate is engaged in
wellhead condensate gathering, stabilization, terminalling, transportation and storage within certain
defined areas of Ohio.
Commercial Agreements
The Partnership has various long-term, fee-based transportation services and storage services agreements with
MPC. Under these long term, fee based agreements, the Partnership provides transportation and storage services
to MPC, and MPC has committed to provide the Partnership with minimum quarterly throughput volumes on
crude oil and products systems and minimum storage volumes of crude oil, products and butane. 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.
164
The commercial agreements with MPC include:
•
•
•
•
•
•
three separate 10-year transportation services agreements and one five-year transportation services
agreement under which MPC pays the Partnership fees for transporting crude oil on various of our crude oil
pipeline systems;
four separate 10-year transportation services agreements under which MPC pays the Partnership fees for
transporting products on each of our refined product pipeline systems;
a five-year transportation services agreement under which MPC pays the Partnership fees for handling crude
oil and products at our Wood River, Illinois barge dock;
a 10-year storage services agreement under which MPC pays the Partnership fees for providing storage
services at our Neal, West Virginia butane cavern;
five separate three-year storage services agreements under which MPC pays the Partnership fees for
providing storage services at our tank farms; 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.
All of the transportation services agreements with MPC for the Partnership’s crude oil and product pipeline
systems include automatic renewal terms ranging from two to five years, unless terminated by either party. The
Partnership’s butane cavern storage services agreement with MPC does not automatically renew. The storage
services agreements with MPC for the Partnership’s tank farms automatically renew for additional one-year
terms unless terminated by either party.
Under all of our transportation services agreements, except for our marine agreement, if MPC fails to transport
its minimum throughput volumes during any quarter, then MPC will pay us a deficiency payment equal to the
volume of the deficiency multiplied by the tariff rate then in effect (the “Quarterly Deficiency Payment”). Under
these transportation services agreements, the amount of any Quarterly Deficiency Payment paid by MPC may be
applied as a credit for any volumes transported on the applicable pipeline system 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 our Wood River to Patoka crude system and our 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 system, without regard to any minimum volume
commitment that may have been in place during the term of the agreement.
Under the storage services agreements, as amended, the Partnership is obligated to make available to MPC on a
firm basis the available storage capacity at our tank farms and butane cavern, and MPC pays the Partnership a
per-barrel fee for such storage capacity, regardless of whether MPC fully utilizes the available capacity.
On January 1, 2015, HSM entered into a long-term, fee-based transportation services agreement with MPC for a
period of six years. Under the agreement, the Partnership provides marine transportation of crude oil, feedstocks
and refined petroleum products, as well as related services. Under the agreement MPC pays HSM monthly for
the following: the specified day rate for equipment and charges for services related to transportation, tankerman
services and cleaning and repair charges. Fleeting services are billed monthly. On the anniversary of the contract,
pursuant to the amended and restated fee-based transportation services agreement effective July 1, 2015, the day
rates and charges for services related to transportation are adjusted for inflation. Prior to January 1, 2015, this
agreement did not exist.
On January 1, 2015, MPC conveyed various operating leases to HSM for third-party barges and fleeting property
within the states of Indiana, Kentucky, Louisiana, Ohio and West Virginia in which MPC was either the lessor or
lessee.
165
Operating Agreements
The Partnership operates various pipeline systems 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.
Management Services Agreements
The Partnership has two management services agreements with MPC under which it provides management
services to MPC with respect to certain of MPC’s retained pipeline assets. The Partnership may adjust annually
for inflation and based on changes in the scope of management services provided.
The Partnership also receives engineering and construction and administrative management fee revenue and
other direct personnel costs for operating some joint venture entities.
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 expires on June 30, 2020.
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 four employee services agreements with MPC. Two of the employee services agreements
with MPC were entered into effective October 1, 2012, under which the Partnership reimburses MPC for the
provision of certain operational and management services in support of our pipelines, barge dock, butane cavern
and tank farms within the L&S segment. Effective December 28, 2015, the Partnership entered into an additional
employee services agreement with MPC, which requires that we reimburse MPC for certain operational and
management services to us in support of our G&P segment and certain of our other operations. Lastly, we are
party to an employee services agreement with MPC dated January 1, 2015, pursuant to which HSM reimburses
MPC for employee benefit expenses along with certain operation and management services provided in support
of HSM’s areas of operation. The agreement is effective until December 31, 2019. Prior to January 1, 2015, this
agreement did not exist.
Loan Agreements
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
166
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. Borrowings were at an average interest
rate of 1.939 percent and 1.744 percent, per annum for 2016 and 2015, respectively. In connection with this loan
agreement, the Partnership terminated the previous revolving credit agreement of $50 million with MPC,
effective December 31, 2015.
During 2016, the Partnership borrowed $2.5 billion and repaid $2.5 billion, resulting in no outstanding balance at
December 31, 2016. During 2015, the Partnership borrowed $301 million and repaid $293 million, for an
outstanding balance at December 31, 2015 of $8 million, which is included in Payables to related parties on the
Consolidated Balance Sheets.
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 and storage services based on contracted rates. Related party sales to MPC
also consist of revenue related to volume deficiency credits.
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
2016
2015
2014
$603
$593
$662
$114
$101
$ 15
$ 11
$
1
$—
(1)
For 2016 and 2015, there were $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. There were no such transactions in 2014.
Related party sales to MPC consist of crude oil and refined products pipeline transportation services based on
regulated tariff rates, storage services based on contracted rates and transportation services provided by HSM.
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 on the Consolidated Balance Sheets. MPC may then apply the amount of any
such deficiency payments as a credit for volumes transported on the applicable pipeline system in excess of its
minimum volume commitment during the following four or eight quarters 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.
167
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
Centennial
Ohio Gathering
Ohio Condensate
Other
Total
2016
2015
2014
$ 60
$ 68
16 —
1
15
4
5
—
—
1
2
$ 39
—
1
—
—
—
$101
$ 71
$ 40
MPC provides executive management services and certain general and administrative services to the Partnership
under the terms of the omnibus agreement. Expenses incurred under these agreements are shown in the table
below by the income statement line where they were recorded. These expenses also include similar charges
incurred by HSM for the time period prior to the acquisition and therefore not covered by the omnibus
agreement. Charges for services included in Purchases from 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 from related parties
General and administrative expenses
Total
2016
2015
2014
$29
39
$68
$30
46
$76
$30
46
$76
Also under terms of the omnibus agreement, some service costs related to engineering services are associated
with assets under construction. These costs added to Property, plant and equipment were as follows:
(In millions)
MPC
2016
2015
2014
$38
$13
$8
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
from related parties on the Consolidated Balance Sheets. 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.
Employee services expenses from related parties were as follows:
(In millions)
Purchases—related parties
General and administrative expenses
Total
2016
2015
2014
$287
72
$359
$136
22
$158
$123
24
$147
168
Receivables from related parties which include 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
Other
Total
December 31,
2016
2015
$117
2
2
1
$122
$175
4
5
3
$187
Long-term receivables with related parties, including straight-line rental income for both periods presented, as
well as reimbursements from the MarkWest Merger to be provided by MPC for the conversion of Class B units
for the period ended December 31, 2015, were as follows:
(In millions)
MPC
Payables to related parties were as follows:
(In millions)
MPC
MarkWest Utica EMG
Total
December 31,
2015
2016
$4
$25
December 31,
2016
2015
$51
24
$75
$33
21
$54
In recent years, MPC did not ship its minimum committed volumes on certain pipeline systems. 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 transportation services 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,
2016
2015
$44
5
$49
$36
5
$41
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 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 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 incentive distribution
rights.
169
The HSM acquisition was a transfer between entities under common control. As an entity 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 HSM 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 2016 and 2015, the Partnership had dilutive potential common units consisting of certain equity-based
compensation awards and Class B units. Diluted net income per limited partner unit for the 2014 reporting period
is the same as basic net income per limited partner unit as there were no potentially dilutive common or
subordinated units outstanding as of December 31, 2014.
(In millions)
Net income attributable to MPLX LP
Less: Distributions declared on Preferred units(1)
General partner’s distributions declared (including IDRs)(1)
Limited partners’ distributions declared on common units(1)
Limited partner’s distributions declared on subordinated units(1)
2016
2015
$ 233
41
205
692
—
$ 156
—
60
224
31
2014
$121
—
6
54
52
Undistributed net (loss) income attributable to MPLX LP
$(705)
$(159)
$
9
(1)
See Note 8 for information regarding the distribution.
(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
2016
$205
$ 692
(14)
(691)
$191
$
1
$ 41
—
$ 41
7
7
331
338
$ —
$ —
$ 938
(705)
$ 233
338
345
170
(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
(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 income 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
2015
General
Partner
Limited Partners’
Common Units
Limited Partner’s
Subordinated
Units
Total
$60
(3)
$57
2
2
$ 224
$ 31
$ 315
(127)
(29)
(159)
$ 97
$
2
$ 156
99
100
79
80
$1.23
$1.22
2014
18
18
$0.11
$0.11
General
Partner
Limited Partners’
Common Units
Limited
Partner’s
Subordinated
Units
Total
$ 6
2
$ 8
2
2
$ 54
$ 52
$ 112
4
3
9
$ 58
$ 55
$ 121
37
37
$1.55
$1.55
37
37
$1.50
$1.50
76
76
(1) Allocation of net income (loss) attributable to MPLX LP assumes all earnings for the period had been
distributed based on the current period distribution priorities.
8. Equity
Units Outstanding—The Partnership had 357,193,288 common units outstanding as of December 31, 2016. Of
that number, 86,619,313 were owned by MPC, which also owned the two percent general partner interest,
represented by 7,371,105 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
171
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, all of the MPLX LP Class A
units were exchanged on a one-for-one basis for newly issued common units representing limited partner
interests in MPLX LP. MPC also contributed $141 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
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 Class B unit of
MarkWest outstanding 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 will automatically convert into 1.09 MPLX LP
common units and the right to receive $6.20 in cash in equal installments, the first of which occurred on July 1,
2016 and the second of which will occur on July 1, 2017.
ATM Program—On August 4, 2016, the Partnership entered into a second amended and restated distribution
agreement (the “Distribution Agreement”) providing for the continuous issuance of common units, in amounts, at
prices and on terms to be determined by market conditions and other factors at the time of our offerings (such
continuous offering program, or at-the-market program is referred to as our “ATM Program”). The Partnership
expects the net proceeds from sales under the ATM Program will be used for general partnership purposes,
including repayment or refinancing of debt, and funding for acquisitions, working capital requirements and
capital expenditures. During the year ended December 31, 2015, the Partnership issued an aggregate of 25,166
common units under our ATM Program, generating net proceeds of approximately $1 million. During the year
ended December 31, 2016, the Partnership issued an aggregate of 26,347,887 common units under the ATM
Program generating net proceeds of approximately $776 million. As of December 31, 2016, $717 million of
common units remains available for issuance through the ATM program under the Distribution Agreement.
172
The table below summarizes the changes in the number of units outstanding for the years ended December 31,
2014, 2015, and 2016:
(In units)
Common
Class B
Subordinated
General
Partner
Total
36,951,515
15,479
2,924,104
3,450,000
43,341,098
18,932
25,166
36,951,515
216,350,465
296,687,176
120,989
Balance at December 31, 2013
Unit-based compensation awards
Contribution of interest in Pipe Line
Holdings
December 2014 equity offering
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
—
—
—
—
—
—
36,951,515
—
1,508,225
316
75,411,255
15,795
—
—
59,676
70,408
36,951,515
—
1,638,625
386
2,983,780
3,520,408
81,931,238
19,318
—
— (36,951,515)
—
7,981,756
7,981,756
—
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
368,555,271
—
—
—
—
—
—
—
—
26,347,887
22,534,002
4,350,057
7,153,177
—
—
(3,990,878)
—
Balance at December 31, 2016
357,193,288
3,990,878
2016 Activity
On July 1, 2016, 3,990,878 Class B units converted to 4,350,057 common units and received the second quarter
distribution. As a result of the Class B units converted to common units during the period, MPLX GP contributed
less than $1 million in exchange for 7,330 general partner units to maintain its two percent general partner
interest.
As a result of the unit-based compensation awards issued during the period, MPLX GP contributed less than
$1 million in exchange for 2,470 general partner units to maintain its two percent general partner interest.
As a result of common units issued under the ATM Program during the period, MPLX GP contributed
$16 million in exchange for 537,710 general partner units to maintain its two percent general partner interest.
In connection with the Class A Reorganization, 7 million common units were acquired by MPC that represents
the common units received by MPC on the exchange of the MPLX LP Class A units less the units redeemed in
the distribution of MPLX Holdings Inc., including the MPLX LP Class A units. Additionally, MPLX LP
transferred common units representing a two percent ownership interest of MPLX Holdings Inc. to MPLX GP in
exchange for 436,758 MPLX LP general partner units held by MPLX GP, as discussed above.
2015 Activity
As a result of common units issued under the ATM Program during 2015, MPLX GP contributed less than
$1 million in exchange for 514 general partner units to maintain its two percent general partner interest.
In connection with the MarkWest Merger discussed in Note 4, MPLX GP contributed $169 million in exchange
for 5,160,950 general partner units to maintain its two percent general partner interest.
173
2014 Activity
Effective December 1, 2014, as discussed in Note 4, the Partnership accepted a contribution of 7.625 percent of
outstanding partnership interests of Pipe Line Holdings from subsidiaries of MPC in exchange for the issuance of
equity valued at $200 million. The equity consideration consisted of 2,924,104 MPLX LP common units and was
calculated by dividing $200 million by the average closing price for MPLX LP common units for the ten trading
days preceding December 1, 2014, which was $68.397.
On December 8, 2014, the Partnership closed an equity offering of 3,450,000 common units at a public offering
price of $66.68 per unit. The Partnership used the net proceeds of $221 million to repay borrowings under its
revolving credit facility and for general partnership purposes.
As a result of the contribution mentioned above and the December 2014 equity offering, MPLX GP contributed
$9 million in exchange for 130,084 general partner units to maintain its two percent general partnership 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.
Incentive Distribution Rights—The following table illustrates the percentage allocations of available cash from
operating surplus between the common and subordinated unitholders and the general partner based on the
specified target distribution levels. The amounts set forth under “Marginal percentage interest in distributions”
are the percentage interests of the general partner and common and subordinated unitholders in any available
cash from operating surplus the Partnership distributes up to and including the corresponding amount in the
column “Total quarterly distribution per unit target amount.” The percentage interests shown for its common and
subordinated unitholders and the general partner for the minimum quarterly distribution are also applicable to
quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set
forth below for the general partner include its two percent general partner interest and assume that the general
partner has contributed any additional capital necessary to maintain its two percent general partner interest, the
general partner has not transferred its incentive distribution rights and that there are no arrearages on common
units.
Net Income Allocation—In preparing the Consolidated Statements of Equity, net income (loss) 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 incentive distribution rights 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 following table presents the allocation of the general
partner’s interest in net income attributable to MPLX LP:
(In millions)
Net income attributable to MPLX LP
Less: Preferred unit distributions
General partner’s incentive distribution rights and other
2016
2015
2014
$233
$156 $121
—
41 —
191
55
4
Net income attributable to MPLX LP available to general and limited partners
$
1
$101
$117
General partner’s two percent interest in net income attributable to MPLX LP
General partner’s incentive distribution rights and other
General partner’s interest in net income attributable to MPLX LP
$— $
191
2
55
$191
$ 57
$
$
2
4
6
Cash distributions—The partnership agreement sets forth the calculation to be used to determine the amount and
priority of cash distributions that the common unitholders and general partner will receive. In accordance with
174
the partnership agreement, on January 25, 2017, the Partnership declared a quarterly cash distribution, based on
the results of the fourth quarter of 2016, totaling $242 million, or $0.5200 per unit. This distribution was paid on
February 14, 2017 to unitholders of record on February 6, 2017. See the table below for the IDR impact for 2016.
The allocation of total quarterly cash distributions to general, limited, and Preferred unitholders is as follows for
the years ended December 31, 2016, 2015 and 2014. The 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
General partner’s incentive distribution rights distributions
Total general partner’s distributions
Limited partners’ distributions:
Common unitholders
Subordinated unitholders
Total limited partners’ distributions
Preferred unit distributions
Total cash distributions declared
9. Redeemable Preferred Units
2016
2015
2014
$
$ 18
187
205
$
6
54
60
2
4
6
692
—
224
31
255
692
41 —
54
52
106
—
$938
$315 $112
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.
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
receive as a 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 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 2016 were as follows:
(In millions)
Issuance of MPLX LP redeemable Preferred units on May 13, 2016
Net income allocated for May 13, 2016 through December 31, 2016
Distributions received by Preferred unitholders
Balance at December 31, 2016
Redeemable
Preferred Units
$ 984
41
(25)
$1,000
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
175
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 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 in 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. Because 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 and stores crude oil and refined petroleum products. Segment information for prior
periods includes HSM as it is an entity under common control.
• 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 views the Partnership-operated equity method investments’ financial information as
if those investments were consolidated.
Segment operating income represents income from operations attributable to the reportable segments. Corporate
general and administrative expenses, unrealized derivative (losses) gains, property, plant and equipment,
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 Predecessor of the inland marine business
prior to the March 31, 2016 acquisition.
176
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 interest
and Predecessor
Segment portion attributable to noncontrolling interest and Predecessor
Segment operating income attributable to MPLX LP
L&S
2016
G&P
Total
$787
68
$2,185
1
$2,972
69
855
2,186
3,041
368
907
1,275
487
34
1,279
147
1,766
181
$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 interest
and Predecessor
Segment portion attributable to noncontrolling interest and Predecessor
L&S
$760
75
835
379
456
134
Segment operating income attributable to MPLX LP
$322
$
(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 interest
and Predecessor
Segment portion attributable to noncontrolling interest and Predecessor
Segment operating income attributable to MPLX LP
177
2015
G&P
Total
$ 150
—
$ 910
75
150
62
88
12
76
985
441
544
146
$ 398
2014
L&S
$ 747
46
793
392
401
188
$ 213
(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
(Loss) income from equity method investments
Other income—related parties
Unrealized derivative (losses) gains(1)
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
(Loss) income from equity method investments
Other income—related parties
Unrealized derivative losses(1)
Total revenues and other income
(in millions)
Reconciliation to Net income attributable to noncontrolling interests and
Predecessor:
2016
2015
2014
$ 453
1,132
$ 322
76
$213
—
1,585
(173)
34
(74)
40
(36)
(546)
(130)
(193)
398
(8)
133
3
2
4
(116)
—
(118)
213
85
103
—
—
—
(75)
—
(81)
$ 507
$ 298
$245
2016
2015
2014
$3,041
(402)
(74)
40
(15)
$2,590
$985
(28)
3
2
(1)
$961
$793
—
—
—
—
$793
2016
2015
2014
Segment portion attributable to noncontrolling interest and Predecessor
Portion of noncontrolling interests and Predecessor related to items below segment
$ 181
$146
$188
income from operations
Portion of operating income attributable to noncontrolling interests of
unconsolidated affiliates
(124)
(48)
(70)
(32)
(5)
—
Net income attributable to noncontrolling interests and Predecessor
$
25
$ 93
$118
(1)
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During
the period when a derivative contract is outstanding, we record changes in the fair value of the derivative as
an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously
recorded unrealized gain or loss and record the realized gain or loss of the contract.
The following 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 G&P segment
Total capital expenditures
2016
2015
2014
$ 443
894
1,337
$212
100
312
$141
—
141
131
24
—
$1,206
$288
$141
178
Total assets by reportable segment were:
(In millions)
Cash and cash equivalents
L&S
G&P
Total assets
December 31,
2016
2015
$
234
2,115
14,297
$
43
1,842
14,219
$16,646
$16,104
11. Major Customers and Concentration of Credit Risk
MPC accounted for 30 percent, 79 percent and 90 percent of the Partnership’s total revenues and other income
for 2016, 2015 and 2014, respectively, excluding revenues attributable to volumes shipped by MPC under joint
tariffs with third parties, which are treated as third-party revenue for accounting purposes.
A second customer accounted for 12 percent of the Partnership’s total revenues and other income for 2016.
Revenues from this customer are from product sales, gathering, processing and fractionation services in the G&P
segment. As of December 31, 2016, the Partnership had $59 million of accounts receivable from this customer.
A third customer accounted for 10 percent of the Partnership’s total revenues and other income for 2016.
Revenues from this customer are from product sales, processing and fractionation services in the G&P segment.
As of December 31, 2016, the Partnership had $13 million of accounts receivable from this customer.
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
allocation of taxable income. The Partnership’s income tax (benefit) provision 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. After MarkWest Hydrocarbon files
its 2016 income tax returns in 2017, the Partnership anticipates a residual tax provision to be recorded. 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 of $12 million, $1 million and
$1 million for the years ended December 31, 2016, 2015 and 2014, respectively. The effective tax rate was five
percent for 2016, and less than one percent for 2015 and 2014, respectively.
179
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 (benefit) expense:
Federal
State
Total deferred
(Benefit) provision for income tax
December 31,
2016
2015
$ 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
$285
— %
$
2
— %
—
1
—
—
—
—
—
—
—
—
$—
$246
(14)
(1)
3
(1)
1
$ (12)
(Benefit) provision for income tax
$(13)
$
1
(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
$240
— %
—
(2)
—
—
$ (2)
1
$
— %
—
—
—
—
$—
$250
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.
180
Deferred tax assets and liabilities consist of the following:
(In millions)
Deferred tax assets:
Derivatives
Net operating loss carryforwards
Total deferred tax assets
Deferred tax liabilities:
Property, plant and equipment
Investments in subsidiaries and affiliates
Total deferred tax liabilities
Net deferred tax liabilities
December 31,
2016
2015
$—
—
—
5
—
5
5
$
$
9
62
71
7
442
449
$378
At December 31, 2016, MarkWest Hydrocarbon had no tax-effected federal or state operating loss carryforwards.
These were assumed by MPC on September 1, 2016 in connection with the Class A Reorganization discussed in
Note 8.
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, 2016, 2015 or
2014.
Any interest and penalties related to income taxes were recorded as a part of the provision for income taxes. Such
interest and penalties were a net expense of less than $1 million in 2016 and 2015, respectively, and a net benefit
of less than $1 million in 2014. As of December 31, 2016 and 2015, less than $1 million, respectively, of 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 2015 and state tax years 2012 through 2015 open to
examination.
13. Inventories
Inventories consist of the following:
(In millions)
NGLs
Line fill
Spare parts, materials and supplies
Total inventories
December 31,
2016
2015
$
2
9
43
$
3
5
43
$ 54
$ 51
181
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
Pipelines and related assets
Barges and towing vessels
Land, building, office equipment and other
Construction-in-progress
Total
Less accumulated depreciation
Property, plant and equipment, net
Estimated
Useful Lives
5 - 30 years
25 - 30 years
19 - 42 years
20 years
3 - 30 years
December 31,
2016
2015
$ 4,748
3,467
1,492
479
701
958
11,845
1,115
$ 4,307
3,185
1,128
475
606
946
10,647
650
$10,730
$ 9,997
Property, plant and equipment includes gross assets acquired under capital leases of approximately $25 million at
December 31, 2016 and 2015, respectively, with related amounts in accumulated depreciation of approximately
$8 million and $7 million at December 31, 2016 and 2015, respectively.
15. Fair Value Measurements
Fair Values—Recurring
Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions as discussed in
Note 16. As part of the MarkWest Merger, the MarkWest opening balance sheet was valued at fair value (see
Note 4).
Money market funds, which are included in Cash and cash equivalents on the Consolidated Balance Sheets, are
measured at fair value and are included in Level 1 measurements of the valuation hierarchy. The derivative
contracts are measured at fair value on a recurring basis and classified within Level 2 and Level 3 of the
valuation hierarchy. The Level 2 and Level 3 measurements are obtained using a market approach. LIBOR rates
are an observable input for the measurement of all derivative contracts. The measurements for all 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 2 instruments include crude
oil and natural gas swap contracts. The valuations are based on the appropriate commodity prices and contain no
significant unobservable inputs. Level 3 instruments include all NGL transactions and embedded derivatives in
commodity contracts. The significant unobservable inputs for NGL transactions and embedded derivatives in
commodity contracts include NGL prices interpolated and extrapolated due to inactive markets, electricity price
curves, and probability of renewal. The following table presents the financial instruments carried at fair value
classified by the valuation hierarchy:
(In millions)
Significant other observable inputs (Level 2)
Commodity contracts
Significant unobservable inputs (Level 3)
Commodity contracts
Embedded derivatives in commodity contracts
Total carrying value in Consolidated Balance Sheets
182
December 31, 2016
December 31, 2015
Assets
Liabilities
Assets
Liabilities
$—
—
—
$—
$— $
2 $ —
(6)
(54)
7
—
$ (60) $
9 $
—
(32)
(32)
The following table provides additional information about the significant unobservable inputs used in the
valuation of Level 3 instruments as of December 31, 2016. The market approach is used for valuation of all
instruments.
Level 3 Instrument
Balance Sheet
Classification
Unobservable Inputs
Value Range
Time Period
Commodity contracts
Liabilities Forward ethane prices (per gallon)(1)
Forward propane prices (per gallon)(1)
Forward isobutane prices (per gallon)(1)
Forward normal butane prices (per gallon)(1)
Forward natural gasoline prices (per gallon)(1)
Embedded derivatives in
commodity contracts
Liabilities Forward propane prices (per gallon)(1)
Forward isobutane prices (per gallon)(1)
Forward normal butane prices (per gallon)(1)
Forward natural gasoline prices (per gallon)(1)
Forward natural gas prices (per mmbtu)(2)
Probability of renewal(3)
Probability of renewal for second 5-yr term(3)
$0.28 - $0.31 Jan. 17 - Dec. 17
$0.66 - $0.72 Jan. 17 - Dec. 17
$0.85 - $0.97 Jan. 17 - Dec. 17
$0.79 - $0.93 Jan. 17 - Dec. 17
$1.16 - $1.24 Jan. 17 - Dec. 17
$0.62 - $0.72 Jan. 17 - Dec. 22
$0.82 - $0.97 Jan. 17 - Dec. 22
$0.78 - $0.93 Jan. 17 - Dec. 22
$1.16 - $1.27 Jan. 17 - Dec. 22
$2.37 - $3.72 Jan. 17 - Dec. 22
50.0%
75.0%
(1) NGL prices used in the valuations decrease in the early years and increase over time.
(2) Natural gas prices used in the valuations are higher in the early years and decrease over time.
(3)
The producer counterparty to the embedded derivative has the option to renew the gas purchase agreement
and the related keep-whole processing agreement for two successive five-year terms after 2022. The
embedded gas purchase agreement cannot be renewed without the renewal of the related keep-whole
processing agreement. Due to the significant number of years until the renewal options are exercisable and
the high level of uncertainty regarding the counterparty’s future business strategy, the future commodity
price environment, and the future competitive environment for midstream services in the Southern
Appalachian region, management determined that a 50 percent probability of renewal for the first five-year
term and 75 percent for the second five-year term are appropriate assumptions. Included in this assumption
is a further extension of management’s estimates of future frac spreads through 2032.
Fair Value Sensitivity Related to Unobservable Inputs
Commodity contracts (assets and liabilities)—For the Partnership’s commodity contracts, increases in forward
NGL prices result in a decrease in the fair value of the derivative assets and an increase in the fair value of the
derivative liabilities. The forward prices for the individual NGL products generally increase or decrease in a
positive correlation with one another.
Embedded derivatives in commodity contracts—The Partnership has a single embedded derivative liability
comprised of both the purchase of natural gas at prices impacted by the frac spread and the probability of
contract renewal (the “Natural Gas Embedded Derivative”), as discussed further in Note 16. Increases
(decreases) in the frac spread result in an increase (decrease) in the fair value of the embedded derivative
liability. An increase in the probability of renewal would result in an increase in the fair value of the related
embedded derivative liability.
Embedded derivatives in utility contracts—The Partnership had an embedded derivative contract that fixed a
component of the utilities costs at a plant in the Southwest operations to an index price of electricity which
expired as of December 31, 2016. Increases (decreases) in the index price for electricity resulted in a decrease
(increase) in the realized losses presented in Cost of Revenues on the Income Statement.
183
Level 3 Valuation Process
The Partnership’s Risk Management Department (the “Risk Department”) is responsible for the valuation of the
Partnership’s commodity derivative contracts and embedded derivatives in commodity contracts, except for the
Natural Gas Embedded Derivative. The Risk Department reports to the Chief Financial Officer and is responsible
for the oversight of the Partnership’s commodity risk management program. The members of the Risk
Department have the requisite experience, knowledge and day-to-day involvement in the energy commodity
markets to ensure appropriate valuations and understand the changes in the valuations from period to period. The
valuations of the Level 3 commodity derivative contracts are performed by a third-party pricing service and
reviewed and validated on a quarterly basis by the Risk Department by comparing the pricing and option
volatilities to actual market data and/or data provided by at least one other independent third-party pricing
service.
Management is responsible for the valuation of the Natural Gas Embedded Derivative discussed in Note 16.
Included in the valuation of the Natural Gas Embedded Derivative are assumptions about the forward price
curves for NGLs and natural gas for periods in which price curves are not available from third-party pricing
services due to insufficient market data. The Risk Department must develop forward price curves for NGLs and
natural gas through the initial contract term (January 2017 through December 2022) for management’s use in
determining the fair value of the Natural Gas Embedded Derivative. In developing the pricing curves for these
periods, the Risk Department maximizes its use of the latest known market data and trends as well as its
understanding of the historical relationships between forward NGL and natural gas prices and the forward market
data that is available for the required period, such as crude oil pricing and natural gas pricing from other markets.
However, there is very limited actual market data available to validate the Risk Department’s estimated price
curves. Management also assesses the probability of the producer customer’s renewal of the contracts, which
includes consideration of:
• The estimated favorability of the contracts to the producer customer as compared to other options that
would be available to them at the time and in the relative geographic area of their producing assets.
• Extrapolated pricing curves, using a weighted average probability method that is based on historical
frac spreads, which impact the calculation of favorability.
• The producer customer’s potential business strategy decision points that may exist at the time the
counterparty would elect whether to renew the contracts.
184
Changes in Level 3 Fair Value Measurements
The tables below include a roll forward of the balance sheet amounts for the years ended December 31, 2016 and
2015 (including the change in fair value) for assets and liabilities classified by the Partnership within Level 3 of
the valuation hierarchy, except for the changes in goodwill. 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.
(In millions)
Fair value at beginning of period
Net positions assumed in conjunction with the MarkWest
Merger
Total (loss) gain (realized and unrealized) included in
earnings(1)
Settlements
Fair value at end of period
The amount of total (losses) gains for the period included in
earnings attributable to the change in unrealized gains or
losses relating to liabilities still held at end of period
2016
2015
Commodity
Derivative
Contracts
(net)
Embedded
Derivatives in
Commodity
Contracts
(net)
Commodity
Derivative
Contracts
(net)
Embedded
Derivatives in
Commodity
Contracts
(net)
$
7
$ (32)
$—
$—
—
(13)
—
$ (6)
—
(29)
7
7
3
(3)
(38)
5
1
$ (54)
$
7
$ (32)
$ (6)
$ (26)
$
2
$
5
(1) Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Product sales in
the accompanying Consolidated Statements of Income. Gains and losses on Embedded Derivatives in
Commodity Contracts are recorded in Cost of revenues and Purchased product costs.
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 SMR liability and $4.1 billion aggregate principal of the Partnership’s long-term debt were recorded at fair
value in connection with the MarkWest Merger as of December 4, 2015, which established a new cost basis for
each of those liabilities. The fair value of the long-term debt is estimated based on recent market non-binding
indicative quotes. The fair value of the SMR liability is estimated using a discounted cash flow approach based
on the contractual cash flows and the Partnership’s unsecured borrowing rate. The long-term debt and SMR
liability fair values are considered Level 3 measurements.
185
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
December 31,
2016
2015
Fair Value
Carrying Value
Fair Value
Carrying Value
$4,953
$ 108
$4,422
96
$
$5,212
99
$
$5,255
$ 100
16. Derivative Financial Instruments
Commodity Derivatives
NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well
as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional
factors that are beyond the Partnership’s control. The Partnership’s profitability is directly affected by prevailing
commodity prices primarily as a result of processing or conditioning at its own or third-party processing plants,
purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of
third-party transportation and fractionation services. To the extent that commodity prices influence the level of
natural gas drilling by the Partnership’s producer customers, such prices also affect profitability. To protect itself
financially against adverse price movements and to maintain more stable and predictable cash flows so that the
Partnership can meet its cash distribution objectives, debt service and capital plans, the Partnership executes a
strategy governed by its risk management policy. The Partnership has a committee comprised of senior
management that oversees risk management activities, continually monitors the risk management program and
adjusts its strategy as conditions warrant. The Partnership enters into certain derivative contracts to reduce the
risks associated with unfavorable changes in the prices of natural gas and NGLs. Derivative contracts utilized are
swaps traded on the OTC market and fixed price forward contracts. The risk management policy does not allow
the Partnership to take speculative positions with its derivative contracts.
To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has entered into
derivative financial instruments relating to the future price of NGLs and crude oil. The Partnership currently
manages the majority of its NGL price risk using direct product NGL derivative contracts. The Partnership enters
into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory. A portion
of the Partnership’s NGL price exposure is managed by using crude oil contracts. In periods where NGL prices
and crude oil prices are not consistent with the historical relationship, the crude oil contracts create increased risk
and additional gains or losses. The Partnership may settle its crude oil contracts prior to the contractual
settlement date in order to take advantage of favorable terms and reduce the future exposure resulting from the
less effective crude oil contracts. Based on its current volume forecasts, the majority of its derivative positions
used to manage the future commodity price exposure are expected to be direct product NGL derivative contracts.
To mitigate its cash flow exposure to fluctuations in the price of natural gas, the Partnership primarily utilizes
derivative financial instruments relating to the future price of natural gas and takes into account the partial offset
of its long and short gas positions resulting from normal operating activities.
As a result of its current derivative positions, the Partnership has mitigated a portion of its expected commodity
price risk through the fourth quarter of 2017. The Partnership would be exposed to additional commodity risk in
certain situations such as if producers under deliver or over deliver product or when processing facilities are
operated in different recovery modes. In the event the Partnership has derivative positions in excess of the
product delivered or expected to be delivered, the excess derivative positions may be terminated.
Management conducts a standard credit review on counterparties to derivative contracts, and has provided the
counterparties with a guaranty as credit support for its obligations. A separate agreement with certain
186
counterparties allows MarkWest Liberty Midstream to enter into derivative positions without posting cash
collateral. The Partnership uses standardized agreements that allow for offset of certain positive and negative
exposures (“master netting arrangements”) in the event of default or other terminating events, including
bankruptcy.
The Partnership records derivative contracts at fair value in the Consolidated Balance Sheets and has not elected
hedge accounting or the normal purchases and normal sales designation (except for electricity and certain other
qualifying contracts, for which the normal purchases and normal sales designation has been elected). The
Partnership’s accounting may cause volatility in the Consolidated Statements of Income as the Partnership
recognizes in current earnings all unrealized gains and losses from the changes in fair value of derivatives. The
Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period
when a derivative contract is outstanding, we record changes in the fair value of the derivative as an unrealized
gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded unrealized gain
or loss and record the realized gain or loss of the contract.
Volume of Commodity Derivative Activity
As of December 31, 2016, the Partnership had the following outstanding commodity contracts that were executed
to manage the cash flow risk associated with future sales of NGLs:
Derivative contracts not designated as hedging instruments
Financial Position
Crude Oil (bbl)
Natural Gas (MMBtu)
NGLs (gal)
Short
Long
Short
Notional Quantity
(net)
36,500
297,017
64,211,702
Embedded Derivatives in Commodity Contracts
The Partnership has a commodity contract with a producer customer in the Southern Appalachian region that
creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a
broader regional arrangement that also includes a keep-whole processing agreement. For accounting purposes,
these contracts have been aggregated into a single contract and are evaluated together. In February 2011, the
Partnership executed agreements with the producer customer to extend the commodity contract and the related
processing agreement from March 31, 2015 to December 31, 2022, with the producer customer’s option to
extend the agreement for two successive five year terms through December 31, 2032. The purchase of gas at
prices based on the frac spread and the option to extend the agreements have been identified as a single
embedded derivative, which is recorded at fair value. The probability of renewal is determined based on
extrapolated pricing curves, a review of the overall expected favorability of the contracts based on such pricing
curves, and assumptions about the counterparty’s potential business strategy decision points that may exist at the
time the counterparty would elect whether to renew the contract. The changes in fair value of this embedded
derivative are based on the difference between the contractual and index pricing, the probability of the producer
customer exercising its option to extend and the estimated favorability of these contracts compared to current
market conditions. The changes in fair value are recorded in earnings through Purchased product costs in the
Consolidated Statements of Income. As of December 31, 2016 and 2015, the estimated fair value of this contract
was a liability of $54 million and $31 million, respectively.
During the years ended December 31, 2016 and 2015, the Partnership had a commodity contract that allowed for
the Partnership to fix a component of the utilities cost to an index price on electricity at a plant location in the
Southwest Operations which expired as of December 31, 2016. Changes in the fair value of the derivative
component of this contract were recognized as Cost of revenues in the Consolidated Statements of Income. As of
December 31, 2015, the estimated fair value of this contract was a liability of $1 million.
187
Financial Statement Impact of Derivative Contracts
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, 2016 and
2015, 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, 2016
December 31, 2015
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
$—
—
$—
$(13)
(47)
$(60)
$
9
—
$
9
$ (5)
(27)
$(32)
(1)
Includes embedded derivatives in commodity contracts as discussed above.
In the table above, the Partnership does not offset a counterparty’s current derivative contracts with the
counterparty’s non-current derivative contracts, although the Partnership’s master netting arrangements would
allow current and non-current positions to be offset in the event of default. Additionally, in the event of a default,
the Partnership’s master netting arrangements would allow for the offsetting of all transactions executed under
the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives
qualifying for scope exceptions, receivables and payables arising from settled positions and other forms of
non-cash collateral (such as letters of credit).
The impact of the Partnership’s derivative contracts not designated as hedging instruments and the location of
gain or (loss) recognized in the Consolidated Statements of Income is summarized below:
(In millions)
Product sales
Realized gain
Unrealized loss
Total revenue: derivative (loss) gain from product sales
Purchased product costs
Realized loss
Unrealized (loss) gain
Total purchased product costs: derivative (loss) gain from product purchases
Cost of revenues
Realized loss
Unrealized gain
Total cost of revenues: derivative loss from cost of revenues
December 31,
2016
2015
$
2
(15)
(13)
(5)
(22)
(27)
(3)
1
(2)
$
4
(1)
3
—
5
5
—
—
—
Total derivative (losses) gains
$ (42)
$
8
188
17. Debt
The Partnership’s outstanding borrowings at December 31, 2016 and 2015 consisted of the following:
(In millions)
MPLX LP:
Bank revolving credit facility due 2020
Term loan facility due 2019
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
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
December 31,
2016
2015
$ —
250
710
989
1,149
500
1,189
63
8
4,858
(7)
(428)
(1)
$ 877
250
710
989
1,149
500
1,189
63
9
5,736
(8)
(472)
(1)
Total long-term debt due after one year
$4,422
$5,255
(1)
Includes $420 million and $464 million discount as of December 31, 2016 and 2015, respectively, related to
the difference between the fair value and the principal amount of the assumed MarkWest debt.
The following table shows five years of scheduled debt payments.
(In millions)
2017
2018
2019
2020
2021
Credit Agreements
$
1
1
251
5
—
On November 20, 2014, MPLX LP entered into a credit agreement with a syndicate of lenders (“MPLX Credit
Agreement”) which provided for a five-year, $1 billion bank revolving credit facility and a $250 million term
loan facility. In connection with the closing of the MarkWest Merger, the Partnership amended the MPLX Credit
Agreement to, among other things, increase the aggregate amount of revolving credit capacity under the credit
agreement by $1 billion, for total aggregate commitments of $2 billion, and to extend the maturity for the bank
revolving credit facility to December 4, 2020. The term loan facility was not amended and matures on
November 20, 2019. Also in connection with the closing of the MarkWest Merger, MarkWest’s bank revolving
credit facility was terminated and the approximately $943 million outstanding under MarkWest’s bank revolving
credit facility was repaid with $850 million of borrowings under MPLX LP’s bank revolving credit facility and
$93 million of cash.
The bank revolving credit facility includes a letter of credit issuing capacity of up to $250 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
189
commitments would increase. In addition, the maturity date may be extended from time-to-time during its term to
a date that is one year after the then-effective maturity subject to the approval of lenders holding the majority of
the commitments then outstanding, provided that the commitments of any non-consenting lenders will be
terminated on the then-effective maturity date.
The term loan facility was drawn in full on November 20, 2014. The maturity date for the term loan facility may
be extended for up to two additional one-year periods subject to the consent of the lenders holding a majority of
the outstanding term loan borrowings, provided that the portion of the term loan borrowings held by any
non-consenting lenders will continue to be due and payable on the then-effective maturity date. The borrowings
under this facility during 2016 were at an average interest rate of 1.954 percent.
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 bank revolving credit facility and fees with respect to issued and
outstanding letters of credit. The applicable margins to the benchmark interest rates and certain fees fluctuate
based on the credit ratings in effect from time to time on the Partnership’s long-term debt.
The MPLX Credit Agreement includes 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. This agreement includes 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 completed and capital projects undertaken during the relevant period. Other covenants restrict the
Partnership and certain of its subsidiaries from incurring debt, creating liens on its assets and entering into
transactions with affiliates. As of December 31, 2016, the Partnership was in compliance with the covenants
contained in the MPLX Credit Agreement.
During 2016, the Partnership borrowed $434 million under the bank revolving credit facility, at an average
interest rate of 1.899 percent, per annum, and repaid $1.3 billion under the bank revolving credit facility. At
December 31, 2016, the Partnership had no borrowings against the facility and $3 million letters of credit
outstanding under this facility, resulting in total availability of $2 billion, or 99.9 percent of the borrowing
capacity.
During 2015, the Partnership borrowed $992 million under the bank revolving credit facility, at an average
interest rate of 1.617 percent, per annum, and repaid $500 million of these borrowings. At December 31, 2015,
the Partnership had $877 million of borrowings and $8 million letters of credit outstanding under this facility,
resulting in total unused loan availability of $1.12 billion, or 55.8 percent of the borrowing capacity.
During 2014, in connection with entering into the above mentioned MPLX Credit Agreement, the Partnership
terminated its previously existing $500 million five-year MPLX Operations bank revolving credit agreement,
dated as of September 14, 2012. However, during 2014, we borrowed $280 million under the previously existing
agreement, at an average interest rate of 1.535 percent, per annum, and repaid all of these borrowings.
Senior Notes
In connection with the MarkWest Merger, MPLX LP assumed MarkWest’s outstanding debt, which included
$4.1 billion aggregate principal amount of senior notes. On December 22, 2015, approximately $4.04 billion
aggregate principal amount of MarkWest’s outstanding senior notes were exchanged for an aggregate principal
amount of approximately $4.04 billion of new unsecured senior notes issued by MPLX LP in an exchange offer
and consent solicitation undertaken by MPLX LP and MarkWest, leaving approximately $63 million aggregate
principal of outstanding senior notes held by MarkWest.
190
The MPLX LP senior notes consist of (i) approximately $710 million aggregate principal amount of
5.500 percent senior notes due February 15, 2023, (ii) approximately $989 million aggregate principal amount of
4.500 percent senior notes due July 15, 2023, (iii) approximately $1.15 billion aggregate principal amount of
4.875 percent senior notes due December 1, 2024, (iv) approximately $500 million aggregate principal amount of
four percent unsecured senior notes due February 15, 2025, and (v) approximately $1.19 billion aggregate
principal amount of 4.875 percent senior notes due June 1, 2025. Interest on each series of MPLX LP 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
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
After giving effect to the exchange offer and consent solicitation referred to above, as of December 31, 2016,
MarkWest had outstanding (i) approximately $40 million aggregate principal amount of 5.500 percent senior
notes due February 15, 2023, (ii) approximately $11 million aggregate principal amount of 4.500 percent senior
notes due July 15, 2023, (iii) approximately $1 million aggregate principal amount of 4.875 percent senior notes
due December 1, 2024 and (iv) approximately $11 million aggregate principal amount of 4.875 percent senior
notes due June 1, 2025. Interest on each series of the MarkWest senior notes is payable semi-annually in arrears
consistent with the table above.
On February 12, 2015, the Partnership completed a public offering of $500 million aggregate principal amount of
four percent unsecured senior notes due February 15, 2025 (the “Feb 2025 Notes”). The net proceeds from the
offering of the Feb 2025 Notes were approximately $495 million, after deducting underwriting discounts. The net
proceeds were used to repay the amounts outstanding under its bank revolving credit facility, as well as for
general partnership purposes. Interest is payable semi-annually in arrears, commencing on August 15, 2015.
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, 2016 and 2015, the
following amounts related to the SMR are included in the accompanying Consolidated Balance Sheets:
(In millions)
Assets
December 31, 2016 December 31, 2015
Property, plant and equipment, net of accumulated depreciation
Liabilities
Accrued liabilities
Deferred credits and other liabilities
$61
5
91
$69
4
96
191
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.
192
The changes in carrying amount of goodwill were as follows for the periods presented:
(In millions)
Gross goodwill as of December 31, 2014
Accumulated impairment losses
Balance as of December 31, 2014
Acquisitions
Gross goodwill as of December 31, 2015
Accumulated impairment losses
Balance as of December 31, 2015
Purchase price allocation adjustments(1)
Impairment losses
Balance as of December 31, 2016
Gross goodwill as of December 31, 2016
Accumulated impairment losses
Balance as of December 31, 2016
L&S
G&P
Total
$116
—
116
—
116
—
116
—
—
$ — $ 116
—
—
2,454
2,454
—
2,454
(241)
(130)
—
116
2,454
2,570
—
2,570
(241)
(130)
$116
$2,083 $2,199
$116
—
$2,213 $2,329
(130)
(130)
$116
$2,083 $2,199
(1)
See Note 4 for further discussion on purchase price allocation adjustments.
Intangible Assets
The Partnership’s intangible assets as of December 31, 2016 and 2015 are comprised of customer contracts and
relationships, as follows:
(In millions)
Gross
December 31, 2016
Accumulated
Amortization
Net
Gross
December 31, 2015
Accumulated
Amortization
Net
Useful Life
L&S
G&P
$—
533
$ 533
$—
(41)
$ (41)
$—
492
$ 492
$—
468
$ 468
$ —
(2)
$ (2)
$ —
466
$ 466
N/A
11-25 years
Estimated future amortization expense related to the intangible assets at December 31, 2016 is as follows:
(In millions)
2017
2018
2019
2020
2021
Thereafter
Total
$ 38
38
38
38
38
302
$492
193
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—common units issued(1)
Acquisition:
Fair value of MPLX LP units issued(1)
Payable to seller
(1)
See Note 4.
2016
2015
2014
$ 212
3
$
13
—
3
$
—
$
4
669
$
5
—
1
$
200
—
—
7,326
50
—
—
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)
(Decrease) increase in capital accruals
2016
2015
$ (25)
$
26
2014
$ 11
In connection with the acquisition of HSM described in Note 4, MPC agreed to waive first quarter 2016
distributions on the MPLX LP common units issued in connection with the transaction. MPC did not receive
general partner distributions or incentive distribution rights that would have otherwise accrued on such MPLX
LP common units with respect to the first quarter distributions. The value of these waived distributions was
$15 million.
20. Equity-based Compensation Plan
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.
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.
194
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, 2016 and
2015 were $2 million and less than $1 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
MPLX LP’s 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 and have a weighted average grant date fair value of $0.63 per unit for 2016 and $1.03 per
unit for 2015, 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 2016:
Outstanding at December 31, 2015
Granted
Settled
Forfeited
Outstanding at December 31, 2016
Vested and expected to vest at December 31, 2016
Convertible at December 31, 2016
Phantom Units
Number
of Units
1,031,219
458,727
(166,576)
(149,959)
1,173,411
1,157,676
494,189
Weighted
Average
Fair Value
$35.49
29.42
38.12
32.72
33.09
33.12
34.11
Aggregate
Intrinsic
Value
(In millions)
$40
$17
The 494,189 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.
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
$5
3
1
$29.42
35.00
49.56
2016
2015
2014
As of December 31, 2016, unrecognized compensation cost related to phantom unit awards was $17 million,
which is expected to be recognized over a weighted average period of 2.0 years.
195
Outstanding Performance Unit Awards
The following is a summary of activity of performance unit awards paying out in MPLX LP common limited
partner units in 2016:
Outstanding at December 31, 2015
Granted
Settled
Forfeited
Outstanding at December 31, 2016
Performance Units
Number of
Units
1,521,392
789,375
(458,011)
(53,507)
1,799,249
Weighted
Average
Fair Value
$1.00
0.63
0.79
1.06
0.89
As of December 31, 2016, 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 1.6 years.
Performance units paying out in 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
0.96%
0.95%
0.63%
2.83 years
2.84 years
2.84 years
47.59%
0.63
$
30.12%
1.03
$
17.17%
1.16
$
2016
2015
2014
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 $10 million in 2016,
$4 million in 2015 and $3 million in 2014. 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.
MPC’s Stock-based Compensation
Stock-based compensation expenses charged to MPLX LP under our employee services agreement with MPC
were $5 million for 2016 and $1 million for 2015 and 2014, 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
196
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 expire during 2023 and 2030.
Based on the terms of the Partnership’s fee-based transportation services agreement with MPC, HSM is also
considered to be a lessor of its marine equipment in accordance with GAAP. The Partnership’s revenue from its
implicit lease arrangements, excluding executory costs, totaled approximately $464 million in 2016, $89 million
in 2015 and $14 million in 2014.
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, 2016 and 2015, the Partnership received
$7 million and less than $1 million, respectively, in contingent lease payments.
The following is a schedule of minimum future rentals on the non-cancellable operating leases as of
December 31, 2016:
(In millions)
2017
2018
2019
2020
2021
2022 and thereafter
Total minimum future rentals
Intercompany
Third Party
Total
$101
101
101
101
—
—
$404
$ 197
200
202
201
185
460
$1,445
$ 298
301
303
302
185
460
$1,849
The following schedule summarizes the Partnership’s investment in assets held for operating lease by major
classes as of December 31, 2016 and 2015:
(In millions)
Natural gas gathering and NGL transportation pipelines and
facilities
Natural gas processing facilities
Barges
Towing vessels
Construction in progress
Property, plant and equipment
Less: accumulated depreciation
December 31,
2016
2015
$ 650
844
388
91
219
2,192
(266)
$ 619
753
360
91
110
1,933
(170)
Total property, plant and equipment
$1,926
$1,763
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.
197
The following is a reconciliation of the changes in the ARO from January 1, 2015 to December 31, 2016:
(In millions)
ARO at beginning of period
Liabilities assumed in conjunction with the MarkWest Merger
Liabilities incurred
Adjustments to AROs
Accretion expense
2016
2015
$—
$ 17
—
8
(1) —
1 —
15
2
ARO at end of period
$ 25
$ 17
At December 31, 2016 and 2015, 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.
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, 2016 and 2015, accrued liabilities for remediation totaled $1 million and $1 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 and 2015, there was
less than $1 million, respectively, in receivables from MPC for indemnification of environmental costs related to
incidents occurring prior to the Initial Offering.
In July 2015, representatives from the EPA and the United States Department of Justice conducted a raid on a
MarkWest Liberty Midstream pipeline launcher/receiver site utilized for pipeline maintenance operations in
Washington County, Pennsylvania pursuant to a search warrant issued by a magistrate of the United States
District Court for the Western District of Pennsylvania. As part of this initiative, the U.S. Attorney’s Office for
the Western District of Pennsylvania, proceeded with an investigation of MarkWest Liberty Midstream’s
launcher/receiver, pipeline and compressor station operations. In response to the investigation, MarkWest
initiated independent studies which demonstrated that there was no risk to worker safety and no threat of public
harm associated with MarkWest Liberty Midstream’s launcher/receiver operations. These findings were
supported by a subsequent inspection and review by the Occupational Safety and Health Administration. After
providing these studies, and other substantial documentation related to MarkWest Liberty Midstream’s pipeline
and compressor stations, and arranging site visits and conducting several meetings with the government’s
representatives, on September 13, 2016, the U.S. Attorney’s Office for the Western District of Pennsylvania
rendered a declination decision, dropping its criminal investigation and declining to pursue charges in this matter.
198
MarkWest Liberty Midstream continues to discuss with the EPA and the State of Pennsylvania civil enforcement
allegations associated with permitting or other related regulatory obligations for its launcher/receiver and
compressor station facilities in the region. In connection with these discussions, MarkWest Liberty Midstream
received an initial proposal from the EPA to settle all civil claims associated with this matter for the combination
of a proposed cash penalty of approximately $2.4 million and proposed supplemental environmental projects
with an estimated cost of approximately $3.6 million. MarkWest Liberty Midstream will be submitting a
response asserting that this action involves novel issues surrounding primarily minor source emissions from
facilities that the agencies themselves considered de minimis were not the subject of regulation and consequently
that the settlement proposal is excessive. MarkWest will continue to negotiate with EPA regarding the amount
and scope of the proposed settlement.
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—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. 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, 2016 the Partnership’s contractual
commitments to acquire property, plant and equipment totaled $588 million. 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. Our contractual commitments at
199
December 31, 2016 were primarily related to plant expansion projects for the Marcellus and Southwest
Operations and the Cornerstone Pipeline project. 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, 2016,
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.
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, 2016 are as follows:
(In millions)
2017
2018
2019
2020
2021
2022 and thereafter
Total
$ 46
62
61
61
61
317
$608
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, 2016, 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)
2017
2018
2019
2020
2021
Later years
Capital
Lease
Obligations
Operating
Lease
Obligations
$
—
—
$ 61
51
42
37
36
76
$303
1
1
2
5
9
1
8
Total minimum lease payments
Less: imputed interest costs
Present value of net minimum lease payments
$
Operating lease rental expense was:
(In millions)
Minimum rental expense
2016
$57
2015
$21
2014
$ 17
200
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)
2017
2018
2019
2020
2021
2022 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
143
228
87
45
96
5
$ 91
24. Subsequent Event
On February 6, 2017, MarkWest Liberty Midstream executed definitive agreements with Antero Midstream
LLC, and affiliate of Antero Midstream LP (“Antero Midstream”) for the formation of a joint venture, Sherwood
Midstream LLC (“Sherwood Midstream”), to process natural gas at the Sherwood Complex and fractionate
natural gas liquids at the Hopedale Complex. Sherwood Midstream is owned 50 percent by Antero Midstream
and 50 percent by MarkWest Liberty Midstream. These transactions were effective as of January 1, 2017. In
connection with these transactions, MarkWest Liberty Midstream contributed approximately $134 million of
assets to Sherwood Midstream, comprised of the three 200 mmcf/d gas processing plants under construction at
the Sherwood Complex. MarkWest Liberty Midstream will operate Sherwood Midstream’s gas processing
facilities and will also retain sole and exclusive ownership and operation of the existing six 200 mmcf/d gas
processing plants at the Sherwood Complex. In addition, MarkWest Liberty Midstream and Sherwood Midstream
entered into a joint venture, Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”), to own
certain infrastructure at the Sherwood Complex that is shared by and supports the operation of both the Sherwood
Midstream and MarkWest Liberty Midstream gas processing plants. MarkWest Liberty Midstream contributed
approximately $207 million of assets to Sherwood Midstream Holdings, and as of February 6, 2017, MarkWest
Liberty Midstream owned a 79 percent ownership interest in Sherwood Midstream Holdings, and the remaining
21 percent ownership interest was owned by Sherwood Midstream. Sherwood Midstream also purchased an
interest in 20 mbpd of existing propane and heavier NGL fractionation capacity owned by MarkWest Ohio
Fractionation Company, L.L.C. (“Ohio Fractionation”), a subsidiary of MarkWest Liberty Midstream, at the
Hopedale Complex for $125 million. Sherwood Midstream will also have the option to purchase an interest in
future fractionation train expansions at the Hopedale Complex, subject to the production of incremental NGLs
from Sherwood Midstream’s processing facilities. Ohio Fractionation and MarkWest Utica EMG will continue to
own and operate the remaining portion of the Hopedale Complex, including all rail and marketing infrastructure,
as well as the NGL pipelines connecting MarkWest Liberty Midstream’s and MarkWest Utica EMG’s gas
processing plants to the Hopedale Complex. In connection with the foregoing transactions, Antero Midstream
made an initial capital contribution to Sherwood Midstream of approximately $154 million, and it is expected
that MarkWest Liberty Midstream and Antero Midstream will each contribute 50 percent of capital needed to
fund Sherwood Midstream’s operations.
201
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” and,
collectively with the 2027 Senior Notes, the “New 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, at an
interest rate of 4.125 percent and 5.200 percent, respectively. The Partnership intends to use the net proceeds
from this offering for general partnership purposes, which may include, from time to time, acquisitions
(including the previously announced planned dropdown of assets from MPC, the acquisition of the Ozark
pipeline, and the acquisition of a partial, indirect equity interest in the Bakken Pipeline system) and capital
expenditures.
On February 13, 2017, the Partnership announced that it has entered into an asset purchase agreement with
Enbridge Pipelines (Ozark) LLC (“Enbridge Ozark”), under which an affiliate of Pipe Line Holdings has agreed
to purchase Ozark pipeline for approximately $220 million from Enbridge Ozark. The Ozark pipeline is a
433-mile, 22-inch crude oil pipeline originating in Cushing, Oklahoma, and terminating in Wood River, Illinois,
and capable of transporting approximately 230,000 barrels per day. This purchase transaction is expected to close
in the first quarter of 2017.
On February 15, 2017, MPLX LP closed on its previously announced intent to participate in a joint venture with
Enbridge Energy Partners L.P. (“Enbridge Energy Partners”) to acquire a 9.1875 percent indirect interest in the
Dakota Access Pipeline (“DAPL”) and Energy Transfer Crude Oil Company Pipeline (“ETCOP”) projects,
collectively referred to as the Bakken Pipeline system, from Energy Transfer Partners, L.P. (“ETP”) and Sunoco
Logistics Partners, L.P. (“SXL”) for $500 million.
The Bakken Pipeline system is currently expected to deliver in excess of 470,000 barrels per day 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. ETP and SXL collectively own a 75 percent interest in each of the two joint
ventures that are developing the Bakken Pipeline system. MPLX LP and Enbridge Energy Partners intend to
form a new joint venture to acquire 49 percent of ETP and SXL’s 75 percent indirect interest in the Bakken
Pipeline system. MPLX LP will own 25 percent of this new joint venture with Enbridge, which results in its
9.1875 percent indirect ownership interest in the Bakken Pipeline system. MPLX LP expects to account for its
investment using the equity method of accounting.
202
Select Quarterly Financial Data (Unaudited)
(In millions, except per unit data)
1st Qtr.(1) 2nd Qtr.(2)
3rd Qtr.
4th Qtr.
1st Qtr.
2nd Qtr.
3rd Qtr.
4th Qtr.(3)
2016(3)
2015
Total revenues and other income
Income from operations
Net (loss) income
Net (loss) income attributable to
MPLX LP
Net (loss) income attributable to
MPLX LP per limited partner unit:
Common—basic
Common—diluted
Subordinated—basic and
diluted
Cash distributions declared per
limited partner common unit
Distributions declared:
Limited partner units—Public
Limited partner units—MPC
General partner units—MPC
Incentive distribution rights—
MPC
Redeemable preferred units
Total distributions
$
609 $
27
(37)
564 $
76
20
703 $
207
143
714 $
197
132
201 $
74
68
213 $
82
76
214 $
68
63
(60)
19
141
133
46
51
41
333
74
42
18
$ (0.33) $ (0.11) $
(0.33)
(0.11)
0.22 $
0.21
0.17 $
0.17
0.46 $
0.46
0.50 $
0.50
0.41 $ (0.14)
(0.14)
0.41
—
—
—
—
0.46
0.50
—
—
$0.5050 $0.5100 $0.5150 $0.5200 $0.4100 $0.4400 $0.4700 $0.5000
$
127 $
29
4
131 $
41
4
135 $
44
5
140 $
45
5
10 $
23
1
10 $
25
1
11 $
27
1
40
—
46
9
49
16
52
16
3
—
6
—
8
—
120
29
3
37
—
declared
$
200 $
231 $
249 $
258 $
37 $
42 $
47 $
189
(1)
(2)
(3)
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.
These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4
for more information on the MarkWest Merger.
203
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, 2016. Based on this evaluation, the Partnership’s management, including our
Chief Executive Officer and Chief Financial Officer, concluded that as of December 31, 2016, 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 fourth quarter ended December 31, 2016, we completed the integration of MarkWest into our internal
control environment. 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
On February 23, 2017, our general partner executed an amendment (the “First Amendment”) to the Third
Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of October 31, 2016 (the
“Partnership Agreement”). The First Amendment includes, among other amendments, modifications to the
Partnership Agreement associated with recently issued Treasury Regulations promulgated under Section 707 of
the Internal Revenue Code of 1986, as amended.
The foregoing description of the First Amendment is summary in nature and subject to, and qualified in its
entirety by, the full text of the First Amendment, a copy of which is attached as Exhibit 3.4 to this Annual Report
on Form 10-K and is incorporated herein by reference.
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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 directors. 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, John P. Surma
and C. Richard Wilson 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. In making its determinations, our board considered that
Mr. Helms serves on the board of directors of Range Resources Corporation. During 2016, Range Resources was
a significant customer of MarkWest and MarkWest provided gathering, processing and NGL fractionation
services to 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 that 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.
Audit Committee
C. Richard Wilson serves as the chairman, and Michael L. Beatty, Christopher A. Helms, Garry L. Peiffer and
Dan D. Sandman are members, of our audit committee. Mr. Peiffer is the chair-elect of the audit committee and
205
will assume the position of chairman effective March 1, 2017. 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 C. Richard Wilson, Christopher A. Helms and Garry L.
Peiffer each qualify as an “Audit Committee Financial Expert.”
Mr. Wilson served as the president of Buckeye Partners, L.P. and its general partner, Buckeye GP LLC, and also
served as its chief operating officer, a director and its vice chairman. During the period he was chief operating
officer, Mr. Wilson was responsible for all aspects of Buckeye Partners, L.P.’s operations and administration,
including the oversight of accounting and audit functions, and legal and regulatory compliance.
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 assistant controller and 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.
Audit Committee Report
The Audit Committee has reviewed and discussed the Partnership’s audited financial statements and its report on
internal controls over financial reporting for 2016 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
206
to above, the Audit Committee recommended to the Board that the audited financial statements and the report on
internal controls over financial reporting for MPLX LP be included in the Partnership’s Annual Report on Form
10-K for the year ended December 31, 2016, for filing with the SEC.
C. Richard Wilson, Chairman
Michael L. Beatty
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
Conflicts Committee
Christopher A. Helms serves as the chairman, and Michael L. Beatty, Dan D. Sandman and C. Richard Wilson
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.
207
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
Donald C. Templin
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
C. Richard Wilson
C. Corwin Bromley
Gregory S. Floerke
Randy S. Nickerson
Paula L. Rosson
Timothy J. Aydt(1)
Molly R. Benson(1)
Peter Gilgen(1)
Frank A. Quintana(1)
John S. Swearingen
(1) Corporate officer.
Age as of
January 31, 2017
Position with MPLX GP LLC
63
53
60
69
71
47
62
65
68
65
62
72
59
53
55
50
53
50
60
43
57
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 and General Counsel (Chief Legal Officer)
Executive Vice President and Chief Operating Officer, MarkWest
Operations
Executive Vice President and Chief Commercial Officer, MarkWest
Assets
Senior Vice President and Chief Accounting Officer
Vice President, Operations
Vice President, Corporate Secretary and Chief Compliance Officer
Vice President and Treasurer
Vice President, Tax
Vice President, Crude Oil and Refined Products Pipelines
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, president and chief executive
officer of MPC, and a member of the board of directors of Fifth Third Bancorp. 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 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 Marathon Petroleum Corporation on July 1, 2011,
and to his current position in 2016. 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.
208
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 one outside
public company board 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)
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 our general partner and executive vice president of MPC. He is a member of the
board of directors of Calgon Carbon Corporation. Mr. Templin is on the Downstream Committee of API. He is
active in a number of charitable organizations, including the United Way. 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, and assumed his
current positions in 2016. 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 in 2009. 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 our general partner and executive vice president of MPC, along with
his prior positions with both companies, 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)
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
209
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.
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 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.
210
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
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)
211
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
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. Mr. Peiffer brings a wealth of knowledge and market expertise to his role on our
board.
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 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 Heinz History Center, the Carnegie Science Center, the Carnegie Hero Commission, the Pittsburgh Opera
and Grove City College. He has served as a court-appointed mediator of commercial cases pending in U.S.
federal courts and has lectured on corporate governance law at Oxford University. Mr. Sandman began his career
with Marathon in 1973 and served in a series of legal positions of increasing responsibility. In 1986,
Mr. Sandman was appointed general counsel and secretary of Marathon Oil Company, 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 the legal 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
private company engaged in manufacturing. Mr. Sandman brings to our board his valuable perspective,
specifically on matters of strategic focus, governance and leadership.
212
Other Public Company Directorships: CNX 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
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 serves as the chair of the board of directors of the Federal Reserve Bank of Cleveland.
Additionally, Mr. Surma is the chair of the board of directors of the National Safety Council and is a member of
the board of directors of the University of Pittsburgh Medical Center. 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);
Bank of New York Mellon (2007 to 2012)
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C. Richard Wilson. C. Richard Wilson was elected a member of the board of directors of our general partner
effective October 2012. Mr. Wilson is the owner of Plough Penny Associates, LLC, a consulting firm that offers
services in the finance, marketing and general management disciplines. Mr. Wilson is an officer and serves on
the board of directors of Minsi Trails Council, Inc., which is affiliated with the Boy Scouts of America.
Mr. Wilson previously served in director and executive officer capacities with Buckeye Partners, L.P. and its
general partner, Buckeye GP LLC. During his tenure with Buckeye Partners, Mr. Wilson held the positions of
president and chief operating officer. While serving as chief operating officer, he was responsible for all aspects
of Buckeye Partners’ operations and administration. In addition to pipeline operations, such responsibilities
included finance, mergers and acquisitions, investor relations, legal, regulatory compliance, engineering and
human relations. Mr. Wilson was a director of Buckeye GP LLC from 1986 until 2000, holding the role of vice
chairman for two years. After Mr. Wilson’s retirement in 2000, he remained as a consultant to Buckeye Partners
for an additional five years. Mr. Wilson graduated with a bachelor of arts degree in economics and a master’s
degree in business administration, both from Rutgers University.
Qualifications: As a former director and the president and chief operating officer of Buckeye Partners, L.P.,
Mr. Wilson’s experience with the management and oversight of a master limited partnership dates back to the
emergence of this business form in the pipeline industry. Mr. Wilson’s background as an executive in the
midstream energy sector includes, at various points in time, his responsibility for pipeline operations,
engineering, corporate administration, finance, mergers and acquisitions, investor relations and regulatory
compliance. He draws upon his prior capacity supervising financial reporting functions in his role as chair of the
audit committee of our board and in serving as a named audit committee financial expert. Mr. Wilson brings to
our board his wealth of knowledge of the energy business, which makes him a valued contributor.
Other Public Company Directorships: None within the last five years
C. Corwin Bromley. C. Corwin Bromley is executive vice president and general counsel (chief legal officer) of
our general partner. He joined our general partner in December 2015, at the time of the MarkWest Merger. Prior
to this appointment, Mr. Bromley was executive vice president, general counsel and secretary at MarkWest
beginning in July 2013, and senior vice president, general counsel and secretary at MarkWest beginning in 2004.
Gregory S. Floerke. Gregory S. Floerke is executive vice president and chief operating officer, MarkWest
operations 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 assumed his
current position in 2016. 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.
Randy S. Nickerson. Randy S. Nickerson is executive vice president and chief commercial officer, MarkWest
assets of our general partner. He was appointed to his current position in October 2016. He also serves as the
executive vice president, Corporate Strategy of MPC, effective December 4, 2015, at the time of the MarkWest
Merger. Prior to these appointments, Mr. Nickerson served as chief commercial officer of MarkWest beginning
in 2006 and senior vice president, Corporate Development beginning in 2003.
Paula L. Rosson. Paula L. Rosson is senior vice president and chief accounting officer of our general partner. She
joined our general partner in December 2015, at the time of the MarkWest Merger. Prior to this appointment,
Ms. Rosson was senior vice president at MarkWest beginning in 2014, principal accounting officer beginning in
2011, and vice president and controller beginning in 2006.
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.
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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.
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.
Frank A. Quintana. Frank A. Quintana is vice president, Tax of our general partner. He joined our general
partner in December 2015, at the time of the MarkWest Merger. Prior to this appointment, Mr. Quintana was vice
president, Tax, beginning in 2012 and director, Tax, beginning in 2005 at MarkWest.
John S. Swearingen. John S. Swearingen was appointed vice president, crude oil and refined products pipelines
and chief operating officer of pipeline operations in 2015 and was appointed senior vice president, Transportation
and Logistics of MPC in 2015. Prior to this appointment, 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.
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.
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,
215
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, 2016.
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 2016, none of our general partner’s executive officers served as a member of a compensation
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. Frank
M. Semple serves as a director of our general partner and MPC and served as an executive officer of our general
partner until his retirement in 2016.
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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 2016 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, 2016.
Gary R. Heminger, Chairman
Michael L. Beatty
David A. Daberko
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
John P. Surma
C. Richard Wilson
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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 2016 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”), each principal financial officer (“PFO”) who
served in the position during 2016, and the next three most highly compensated executive officers of our general
partner as of December 31, 2016. The names and titles of our six NEOs as of that date were as follows:
Name
Title
Gary R. Heminger
Pamela K.M. Beall
Nancy K. Buese
Donald C. Templin
C. Corwin Bromley
Gregory S. Floerke
Chairman of the Board and Chief Executive Officer
Executive Vice President and Chief Financial Officer
Former Executive Vice President and Chief Financial Officer
President
Executive Vice President and General Counsel (Chief Legal Officer)
Executive Vice President and Chief Operating Officer, MarkWest Operations
Ms. Buese resigned effective November 1, 2016. Ms. Beall was appointed Executive Vice President and Chief
Financial Officer on October 6, 2016.
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
below. In 2016, Mses. Beall and Buese and Messrs. Bromley and Floerke devoted 100 percent of their total
business time to our business; accordingly, all of the material elements of their compensation are disclosed
below. Mr. Templin devoted 90 percent of his total business time to our business; thus, the material elements of
his compensation for the services he provides to our business are disclosed 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 only be granted to one of our NEOs if it is approved by the board of directors of our general partner, which
is typically done on an annual basis.
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
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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. BDO USA, LLP and Pay Governance, LLC have been engaged to provide
compensation consulting services and benchmarking information to the compensation department and executive
management of MPC. The advice these consultants provide to MPC is typically shared with the board of
directors of our general partner for use in making certain compensation decisions with respect to our NEOs.
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, 2016, we incurred the annualized fixed fee for Mr. Heminger of
$1,220,000. The MPC Compensation Committee made the following adjustments to our NEOs’ base salary in
2016, which was paid by MPC:
Previous
Base Salary
($)
Base Salary
Effective
Dec. 31,
2016 ($)
Increase
(%)
475,000
525,000
10.5
450,000
675,000
475,000
720,000
5.6
6.7
3.3
5.0
Name
Title
Pamela K.M. Beall
Nancy K. Buese
Executive Vice President and Chief Financial Officer
Former Executive Vice President and Chief Financial
Officer
Donald C. Templin Executive Vice President and President MPLX
C. Corwin Bromley Executive Vice President and General Counsel (Chief
Gregory S. Floerke
Legal Officer)
Executive Vice President and Chief Operating Officer,
MarkWest Operations
450,000
465,000
400,000
420,000
Ms. Beall’s increase reflects an adjustment to maintain market competitiveness and her appointment as Executive
Vice President and Chief Financial Officer, which became effective as of October 6, 2016. Mr. Templin’s
increase reflects his appointment as President, which became effective as of January 1, 2016. All other increases
were made to maintain market competitiveness.
Annual Cash Bonus Payments
Ms. Beall and Messrs. Templin, Bromley and Floerke 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. No portion of any bonus paid by MPC to our NEOs will be charged back to us under the
provisions of the omnibus agreement.
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 funded 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.
219
The financial and operational performance metrics used for the 2016 ACB program were:
Performance Metric
Description
Operating Income Per Barrel(1)
EBITDA(2)
Mechanical Availability(3)
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 the consolidated
financial statements and as disclosed to
investors as part of the quarterly earnings
materials.
Measures the mechanical availability and
reliability of the processing equipment in
MPC’s refining, pipeline, terminal and
marine operations.
Type of Measure
Financial (relative)
Financial (absolute)
Operational (absolute)
Selling, General and
Administrative Costs (SG&A)(4)
Actual selling, general and administrative
expenses adjusted for certain items.
Financial (absolute)
MPLX LP/MarkWest
Commercial Synergies
Responsible Care
Marathon Safety Performance
Index(5)
Process Safety Events Score
Financial (absolute)
Operational (absolute)
Operational (absolute)
Measures revenue enhancements or cost
savings at either MPLX LP or MPC
resulting from the combination for which
committed actions were taken in 2016.
The metrics below measure MPC’s
success in meeting MPC’s goals for the
health and safety of its employees,
contractors and neighboring communities,
while continuously improving on MPC’s
environmental stewardship commitment
by minimizing MPC’s 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.
220
Performance Metric
Description
Designated Environmental
Incidents
Quality
Measures environmental performance and
consists of tracking certain: a) releases of
hazardous substances into air, water or
land; b) permit exceedences; 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).(6)
Type of Measure
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 2016 were: BP
p.l.c.; Chevron Corporation; ExxonMobil Corporation; HollyFrontier Corporation; PBF Energy; Phillips 66;
Tesoro Corporation; 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 reflected in their results such as the gain/loss on assets, certain asset impairment expense or tax
law changes.
This is a non-GAAP performance metric. It is calculated as earnings before interest and financing costs,
interest income, income taxes, depreciation and amortization expense, impairment expense and inventory
market valuation adjustments.
(3) Mechanical availability represents the percentage of capacity available for critical downstream equipment to
(4)
(5)
perform its primary function for the full year.
This represents SG&A costs adjusted to exclude costs related to employee bonus program accruals, pension
settlement expense, insurance expense and certain other expenses.
This metric excluded Speedway. In the event of a fatality, payout is determined by the MPC Compensation
Committee. The OSHA Recordable Incident Rate is calculated by taking the total number of OSHA
recordable incidents, multiplied by 200,000 and divided by the total number of hours worked.
(6) A Category 4 Incident is one that involves a fatality. Category 3 Incidents include those in which: MPC
incurs out-of-pocket costs for incident response and recovery activities, mitigation of customer claims or
regulatory penalties in excess of $50,000; a media advisory is issued; 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.
The threshold, target and maximum levels of performance for each performance metric were established for 2016
by evaluating factors such as performance achieved in the prior year(s), anticipated challenges for 2016, MPC’s
business plan and overall strategy. At the time the performance levels were set for 2016, 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.
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The table below provides both the goals for each metric and MPC’s performance achieved in 2016:
Performance Metric
Operating Income Per
Barrel
Threshold
Level
5th or 6th
Position
Target Level
3rd or 4th
Position
Maximum
Level
1st or 2nd
Position
Performance
Achieved
Target
Weighting
Performance
Achieved
3rd Position
(100% of
target)
20.0%
20.0%
EBITDA(1)
$
3,650
$
4,750
$
6,670 $4,501 (89%
10.0%
8.9%
Mechanical Availability
92.4%
93.4%
94.4%
Selling, General and
$
1,339
$
1,309
$
1,279
Administrative Costs(1)
MPLX LP/MarkWest
$25,000,000
$35,000,000
$50,000,000
Commercial Synergies
Responsible Care
Marathon Safety
Performance Index
Process Safety Events
Score
Designated
Environmental
Incidents
Quality
.90
120
72
.60
80
51
.40
60
30
$
500,000 $
250,000
$
125,000
of target)
94.9%
(200% of
target)
$1,243
(200% of
target)
$75,500,000
(200% of
target)
0.95 (0% of
target)
56 (200% of
target)
30 (200% of
target)
$135,000
(192% of
target)
Total
10.0%
20.0%
5.0%
10.0%
5.0%
10.0%
5.0%
0.0%
5.0%
10.0%
5.0%
10.0%
5.0%
9.6%
70.0%
98.5%
(1) Represented in millions.
Organizational and Individual Performance Achievements for the 2016 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 2016 fell into the following general categories:
Mr. Templin Ms. Beall
Mr. Floerke Mr. Bromley
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 assets for potential dropdown to MPLX LP
Progress on diversity initiatives
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
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MPC’s Chairman, President 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 2016
included:
•
net income attributable to MPC decreased 59 percent to $1.17 billion in 2016 from $2.85 billion in
2015;
• MPC’s TSR for 2016 of -1.8 percent compared to the median TSR of -1.5 percent for its performance
unit peer group;
•
•
sustained focus on shareholder returns with $916 million returned to shareholders through dividends
and share repurchases; and
continued integration of the MarkWest assets into the MPLX LP portfolio.
Bonus opportunities for our NEOs under the ACB program are communicated as a target percentage of
annualized base salary at year end. Each of our NEOs can generally earn a maximum of 200 percent of the target
award, although the MPC Compensation Committee has discretion to award each of our NEOs up to a maximum
of 200 percent of target, or make no award at all, depending on MPC’s overall performance and the subjective
evaluation of each NEO’s organizational and individual performance. The MPC Compensation Committee
reviews market data provided by its compensation consultant annually with respect to competitive pay levels and
sets specific bonus target opportunities for each of our NEOs. MPC does not guarantee minimum bonus
payments to any of our NEOs.
2017 Bonus Payments (for 2016 Performance)
In February 2017, the MPC Compensation Committee certified the results of the performance metrics for the
2016 ACB program and applied the following formula based on performance of established metrics,
organizational and individual performance to determine our NEOs’ final award for 2016 performance:
Annualized
Base Salary
(as of 12/31/16)
X
Bonus Target
(as a percent of base
salary)
X
Final Award Percent
(as a percent of
target)
=
Final
Award
Name
Pamela K.M. Beall
Donald C. Templin
C. Corwin Bromley
Gregory S. Floerke
Annualized
Base Salary
(as of
12/31/16)
($)(1)
525,000
720,000
465,000
420,000
Bonus Target
as a % of
Base Salary
(%)
70
100
80
80
Target Bonus
($)
367,500
720,000
372,000
336,000
Final Award
as a % of
Target
(%)
149.6
162.5
120.9
126.4
Final Award
($)(2)
550,000
1,170,000
450,000
425,000
(1) Mr. Templin’s salary reflects his allocation of 90 percent to our General Partner.
(2)
The final award is rounded to the nearest $5,000.
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Long-Term Incentive Compensation
In January 2016, 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 will be 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 and partnership performance conditions 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
Performance Units
Phantom Units
25 percent in MPLX LP common units and
75 percent in cash
MPLX LP common units
$0.00 to $2.00 per unit based on our relative
ranking among a group of peer companies
Value of common units upon vesting
Performance Units
The board of directors of our general partner believes that a performance unit program serves to complement our
award of phantom units. Our program benchmarks MPLX LP’s Total Unitholder Return (“TUR”), relative to a
peer group of midstream competitors. The board of directors of our general partner continues to believe TUR
relative to a peer group is the single best metric for our performance unit program as it is commonly used by
unitholders to measure a company’s performance relative to others within the same industry. It also aligns the
pay of our NEOs to the value delivered to our unitholders. The design of our performance unit program ensures
we pay above target compensation only when our TUR is above the median of the peer group.
Under our performance unit program, TUR for MPLX LP and each of the peer group partnerships is measured
over a 36-month performance cycle. Each performance cycle has four equally weighted performance periods:
(1) the first 12 months, (2) the second 12 months, (3) the third 12 months and (4) the entire 36 months. MPLX
LP’s TUR performance percentile within the peer group is measured for each performance period with the
related payout percentage determined using the following table. However, if MPLX LP’s TUR is negative for a
performance period, the payout percentage for that performance period is capped at target (100 percent)
regardless of actual relative TUR performance percentile.
Performance Unit TUR Ranking vs. Payout
TUR
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 will vary from
$0.00 to $2.00 (zero percent to 200 percent of target.) The final value of the award will be determined by
multiplying the simple average of the payout percentages for the four performance periods by the number of
performance units granted. These awards will settle 25 percent in MPLX LP common units and 75 percent in
cash.
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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 performance 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 used for each peer group member in the TUR calculation will be the
average of its respective closing unit prices for the 20 trading days immediately preceding the beginning or
ending date of the applicable performance period.
The board of directors of our general partner believes that providing four performance periods over a 36-month
cycle is appropriate and serves the best interest of our unitholders. By having four equally weighted performance
periods, the attainment of maximum payout is more difficult to obtain as maximum payout levels can only be
achieved by outperforming the TUR peer group for all four performance periods. Our design also mitigates
significant market fluctuations in unit price at the beginning or end of a performance cycle and does not
encourage high-risk decisions near the end of a performance cycle by limiting their impact on the overall payout
of the award. In addition, the board of directors of our general partner also believes that having the maximum
payout capped at $2.00 per unit helps mitigate excessive or inappropriate risk-taking.
Performance Units Granted in 2014
Performance units granted in 2014 have a performance cycle of January 1, 2014, through December 31, 2016.
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, 2014.
In January 2017, the board of directors of our general partner approved the final TUR for the four performance
periods for the 2014 performance unit grants, which are as follows:
Performance Period
January 1, 2014—December 31, 2014
January 1, 2015—December 31, 2015
January 1, 2016—December 31, 2016
January 1, 2014—December 31, 2016
Actual TUR
(%)
68.4
(45.3)
3.2
(3.7)
Position
2nd
10th
9th
9th
Percentile Ranking
(%)
Payout
(% of target)
90.91
10.00
20.00
20.00
181.82
—
—
—
45.46
Average:
The resulting average of 45.46 percent of target provided for a payment equal to $0.4546 per performance unit
granted. The board of directors approved the following payout to Ms. Beall and Messrs. Heminger and Templin:
Name
Gary R. Heminger
Pamela K.M. Beall
Donald C. Templin
Target Number of
Performance Units
Compensation Committee
Approved Payout
($)
1,000,000
85,000
220,000
454,600
38,641
100,012
The payout was settled 25 percent in full value MPLX LP common units and 75 percent in cash. Mr. Bromley
and Mr. Floerke were not eligible for a payout as these awards were made prior to the MarkWest Merger.
Performance Units Granted in 2015
Performance units granted in 2015 have a performance cycle of January 1, 2015, through December 31, 2017. They
remain outstanding and are included in the “Outstanding Equity Awards at 2016 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 our Annual Report on Form 10-K for the year ended December 31, 2015.
225
Performance Units Granted in 2016
After an annual review of market practices, the board of directors of our general partner again made performance
unit grants in February 2016. The following peer group was approved for those performance units:
- Buckeye Partners, L.P.
- Enbridge Energy Partners, L.P.
- Energy Transfer Partners, L.P.
- Enterprise Products Partners L.P.
- Magellan Midstream Partners, L.P.
- ONEOK Partners, L.P.
- Phillips 66 Partners LP
- Plains All American Pipeline, L.P.
- Sunoco Logistics Partners L.P.
- Tesoro Logistics LP
- Valero Energy Partners LP
- Western Gas Partners, LP
- Williams Partners L.P.
Holly Energy Partners, Nustar Energy L.P., and Shell Midstream Partners L.P. were removed for 2016 while
Enbridge Energy Partners, L.P., Energy Transfer Partners, L.P., Enterprise Products Partners L.P., ONEOK
Partners, L.P. and Williams Partners L.P. were added. These changes were primarily made to better align the peer
group with the increased size and operational structure of MPLX LP after its merger with MarkWest.
The number of performance units granted to Ms. Beall and Messrs. Heminger and Templin can be found in the
Grants of Plan-Based Awards table below.
Phantom Units
A phantom unit is a notional unit that entitles our NEOs to receive a common unit upon vesting, which occurs on
a deferred basis on specified future dates. Grants of phantom units provide diversification of the mix of LTI
awards, promote ownership of actual MPLX LP common units and encourage executive retention. Further,
phantom unit grants also help our NEOs increase their holdings in MPLX LP common units and achieve
established unit ownership guideline levels.
Phantom unit awards vest in equal installments on the first, second and third anniversary of the date of grant and
are settled in MPLX LP common units upon vesting. Prior to vesting, recipients have no right to vote the units,
and cash distributions on the underlying equity accrue and are paid in cash upon vesting.
MPC LTI Awards
Annual MPC LTI awards are granted in the form of performance units (40 percent), stock options (40 percent)
and restricted stock (20 percent). The award vehicles differ as illustrated below:
MPC Performance Units
25 percent in MPC common stock
and 75 percent cash
MPC Stock Options
MPC Restricted Stock
Stock
Stock
$0.00 to $2.00 per unit based on
its relative TSR ranking among
a group of peer companies
Stock price appreciation from
grant date to exercise date
Full value of 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 stock at the time of settlement. The 2016 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 2016 LTI awards to Ms. Beall on March 1, 2016. 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 LTI award vehicles in more detail below.
226
MPC Performance Units
The MPC Compensation Committee believes a performance unit program serves as a complement to stock
options and restricted stock. 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 measurement periods: (1) the first 12 months, (2) the second
12 months, (3) the third 12 months, and (4) the entire 36-month period. MPC’s TSR performance percentile
within the peer group is measured for each performance period, with the related payout percentage determined
using the following table. However, if MPC’s TSR is negative for a performance period, the payout percentage
for that performance period is capped at target (100 percent) regardless of actual relative TSR performance
percentile.
Performance Unit TSR Ranking vs. Payout
TUR
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 final value of the 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 grants will then settle 25 percent in MPC common stock and 75 percent in
cash.
TSR is determined by taking the sum of a company’s stock price appreciation or reduction, plus its cumulative
dividends, for each performance 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 will be
the average of their respective closing stock prices for the 20 trading days immediately preceding the beginning
and ending date of the applicable performance period.
The MPC Compensation Committee believes that providing four measurement periods over a 36-month cycle is
appropriate and serves the best interest of its shareholders. By having four equally weighted measurement
periods, attaining maximum payout is more difficult as maximum payout levels can only be achieved by
outperforming the TSR peer group for all four measurement periods. The design also mitigates significant market
fluctuations in stock price at the beginning or end of a performance cycle and does not encourage high-risk
227
decisions near the end of a performance cycle by limiting their impact on the overall payout of the award. In
addition, the MPC Compensation Committee also believes that having the maximum payout capped at $2.00 per
unit helps mitigate excessive or inappropriate risk-taking.
MPC Performance Units Granted in 2014
Performance units granted by MPC in 2014 had a performance cycle of January 1, 2014, through December 31,
2016. Additional information about these grants, including the peer group used, can be found in the “Long-Term
Incentive Compensation Program” section of the MPC 2015 Proxy Statement.
In January 2017, the MPC Compensation Committee certified the final TSR for the four performance periods for
the 2014 performance unit grants, which are as follows:
Performance Period
January 1, 2014—December 31, 2014
January 1, 2015—December 31, 2015
January 1, 2016—December 31, 2016
January 1, 2014—December 31, 2016
Actual TSR
(%)
Position
Percentile Ranking
(%)
Payout
(% of target)
3.2
20.2
(1.8)
21.5
3rd
4th
5th
4th
71.43
57.14
42.85
57.14
Average:
142.86
114.28
85.70
114.28
114.28
The resulting average of 114.28 percent of target provided for a payment equal to $1.1428 per performance unit
granted. As a result, the MPC Compensation Committee approved the following payment to Ms. Beall:
Name
Pamela K.M. Beall
Target Number of
Performance Shares
272,000
MPC Compensation
Committee Approved Payout
($)
310,842
The results of the 2014 performance unit grant were certified by the MPC Compensation Committee and settled
25 percent in full value MPC shares and 75 percent in cash.
MPC Performance Units Granted in 2015
Performance units granted by MPC in 2015 have a performance cycle of January 1, 2015, through December 31,
2017. They remain outstanding and are included for Ms. Beall in the “Outstanding Equity Awards at 2016 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 2016 Proxy Statement.
MPC Performance Units Granted in 2016
The MPC Compensation Committee made the decision to award performance unit grants in February 2016. The
MPC Compensation Committee approved the following peer group for performance unit awards granted in 2016:
• Chevron Corporation
• HollyFrontier Corporation
•
PBF Energy
• Valero Energy Corporation
•
Phillips 66
• Tesoro Corporation
•
S&P 500 Energy Index
The number of performance units granted to Ms. Beall can be found in the “Grants of Plan-Based Awards” table.
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MPC Stock Options
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,
dividend, or dividend equivalent rights on the underlying stock.
The number of options granted to Ms. Beall 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
stock and promote NEO retention.
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 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, its officials, 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 in the form of MPLX LP phantom units 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.
229
The primary use of corporate aircraft is for business purposes and must be authorized by MPC’s Chairman,
President and CEO or another executive officer designated by MPC’s Board or MPC’s Chairman, President 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 when space is available on business-related flights. When a
spouse’s or guest’s travel does not meet the Internal Revenue Service standard for business use, the cost of that
travel is imputed as income to the NEO.
Reportable values for these perquisite programs, based on the incremental costs to MPC, are included in the “All
Other Compensation” column of the 2016 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.
Unit Ownership Guidelines
In January 2013, the board of directors of our general partner met and 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 LP, the unit ownership guidelines were established as a fixed number of units instead of a value
representing a multiple of an executive officer’s annual salary. In February 2016, the board of directors of our
general partner revised the unit ownership guidelines to levels it deemed more reasonable given the market value
of MPLX LP common units. 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 units;
•
President—20,000 units;
• Executive Vice President—15,000 units;
•
Senior Vice President—10,000 units; and
• Vice President—5,000 units.
Executive officers are not permitted to sell any units received under the MPLX 2012 Plan unless their guideline
ownership levels are met and are maintained after the sale. Additionally, a one-year holding requirement prevents
executive officers from selling any phantom or performance units settled in MPLX LP common units for twelve
months from the time they are vested or earned. This requirement applies to units net of taxes at the time of
vesting or distribution.
Prohibition on Derivatives and Hedging
In order to ensure our executive officers, including our NEOs, bear the full risk of our 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. This plan
provides 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. All determinations with respect
230
to such benefits would be made by MPC without input from us or our general partner or its board of directors.
MPC would bear the full cost of any such payments to our NEOs and benefits and no portion of such payments
would be charged back to us under the provisions of the omnibus agreement.
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, the board of directors of our general
partner approved provisions in our 2015 grant agreements and thereafter that would provide for accelerated
vesting upon a qualified termination from service in connection with a change in control of MPLX LP.
If Messrs. Bromley or Floerke separate from service as a result of a forced relocation of their principal place of
employment to a location more than 50 miles from their current principal place of employment, their unvested
MPLX LP phantom units and MPC restricted stock received as part of their retention grants awarded in 2015 will
vest and become payable. The amount payable assuming such termination occurred on December 31, 2016,
based on the MPLX LP common unit and MPC stock closing prices as of that date, would have been as follows:
Mr. Bromley, $3,333,008; and Mr. Floerke, $2,873,843.
Additionally, upon 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 their retention grants awarded in
2015. The amount payable assuming such separation of service occurred on December 31, 2016, based on the
MPLX LP common unit closing price as of that date, would have been as follows: Mr. Bromley, $1,739,309; and
Mr. Floerke, $1,262,799.
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 2012 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 Partnership’s common units are listed for
trading.
231
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 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 2016 programs in February 2017. 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.
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)
($)
Stock
Awards(3)
($)
Option
Awards(3)
($)
Non-Equity
Incentive Plan
Compensation(4)
($)
2016 1,220,000 1,801,593
2015 1,220,000 2,239,071
2014 1,175,000 2,160,047
—
—
—
—
—
—
Change in
Pension Value
and
Nonqualified
Deferred
Compensation
Earnings(5)
($)
—
—
—
All Other
Compensation(6)
($)
Total
($)
— 3,021,593
— 3,459,071
— 3,335,047
Gary R. Heminger
Chairman of the Board
and Chief Executive
Officer
Pamela K.M. Beall
Executive Vice
President and Chief
Financial Officer
Nancy K. Buese
Former Executive Vice
President and Chief
Financial Officer
Donald C. Templin
President
C. Corwin Bromley
Executive Vice
President and
General Counsel
Gregory S. Floerke
Executive Vice
President and Chief
Operating Officer,
MarkWest
Operations
2016
2015
2014
499,667
234,375
225,000
530,482 170,008
—
173,033
—
183,603
550,000
262,500
—
226,408
56,514
—
86,067 2,062,632
765,704
39,282
— 408,603
—
—
71,037
—
75,762
536,382
— 4,226,487
1,170,000
217,355
—
—
450,000
—
—
—
90,448
—
134,794 3,470,502
— 1,023,906
— 950,212
61,251 1,062,949
— 3,559,626
425,000
—
62,847
—
55,179
958,026
— 3,123,261
2016
2015
389,583
—
34,615 4,191,872
2016
2015
2014
2016
2015
720,000 1,228,353
508,906
515,000
475,212
475,000
461,250
—
34,615 3,525,011
2016
2015
415,000
—
30,769 3,092,492
—
—
—
—
—
—
—
—
—
232
(1)
(2)
(3)
(4)
(5)
(6)
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 2016,
compensation amounts were allocated based on the relative percentage each NEO’s business time was
dedicated to MPLX LP’s business. For 2016, percentage allocations for each NEO were as follows:
Mr. Templin—90 percent; Mses. Beall and Buese and Messrs. Bromley and Floerke—100 percent.
The amounts shown in this column reflect the annualized fixed fee for Mr. Heminger for 2016, 2015, and
2014; for Mr. Templin for 2015 and 2014; and for Ms. Beall for 2014. The amounts shown for Messrs.
Bromley and Floerke for 2016 reflect three months at their January 1, 2016, annualized base salary and nine
months at their April 1, 2016, annualized base salary, respectively. The amount for Ms. Beall reflects three
months at her January 1, 2016, annualized base salary, her annualized base salary for the period from
April 1, 2016, until October 5, 2016, and her annualized base salary for the period from October 6, 2016,
until December 31, 2016. The amount shown for Ms. Buese for 2016 reflects three months at her January 1,
2016, annualized base salary and seven months at her April 1, 2016, annualized base salary.
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, 2016, 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 16 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, 2014, and Note 23 to MPC’s financial statements as reported on its Annual Report on Form
10-K for the year ended December 31, 2016, for amounts related to MPC equity. The maximum value of the
performance units reported in the “Unit Awards” column assuming the highest level of performance is
achieved for Ms. Beall and Messrs. Heminger and Templin for 2016 is $425,000, $2,200,000, and
$1,500,000, respectively; for Ms. Beall and Messrs. Heminger and Templin for 2015 is $170,000,
$2,200,000, and $500,000, respectively and for Ms. Beall and Messrs. Heminger and Templin for 2014 is
$170,000, $2,000,000 and $440,000, respectively.
The amounts shown in this column reflect the total value of ACB awards earned in the year indicated, which
were paid in the following year.
The amounts shown in this column reflect the annual change in actuarial present value of accumulated
benefits under the Marathon Petroleum retirement plans. See “Post-Employment Benefits for 2016” and
“Marathon Petroleum Retirement Plans” sections of the “Compensation Discussion and Analysis” for more
information regarding the defined benefit plans and the assumptions used in the calculation of these
amounts. There are no deferred compensation earnings reported in this column as the non-qualified deferred
compensation plans do not provide above-market or preferential earnings.
In connection with their employment with MPC, our NEOs are eligible for limited perquisites which,
together with contributions to defined contribution plans, comprise the amounts reported in the All Other
Compensation column. The amounts shown in this column are summarized below:
Name
Gary R. Heminger
Pamela K.M. Beall
Nancy K. Buese
Donald C. Templin
C. Corwin Bromley
Gregory S. Floerke
Personal
Use of
Company
Aircraft
($)
—
—
—
—
—
—
Company
Physicals(a)
($)
Tax &
Financial
Planning(b)
($)
Security
($)
Miscellaneous
Perks & Tax
Allowance
Gross Ups
($)
Company
Contributions to
Defined
Contribution
Plans(c)
($)
—
3,587
3,587
3,587
3,587
3,587
—
—
—
—
—
—
—
8,000
15,000
4,612
—
—
233
—
—
—
—
—
—
—
74,480
57,175
126,595
57,664
51,592
Total All Other
Compensation
($)
—
86,067
75,762
134,794
61,251
55,179
(a) 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 $15,000 per calendar year. For
information on this program refer to the “Perquisites” section of the “Compensation Discussion and
Analysis.”
The amounts shown in this column reflect amounts contributed by MPC under the tax-qualified Marathon
Petroleum Thrift Plan for Mses. Beall and Buese and Messrs. Templin, Bromley and Floerke, as well as
under related non-qualified deferred compensation plans. See “Post-Employment Benefits for 2016” and
“Marathon Petroleum Retirement Plans” sections of the “Compensation Discussion and Analysis” for more
information.
(b)
(c)
234
Grants of Plan-Based Awards in 2016
The following table provides information regarding all plan-based awards, including cash-based incentive awards
and equity-based awards (specifically stock options, restricted stock, phantom units and performance units)
granted to each of our NEOs in 2016 for the services each provided to our business.
Name
Gary R.
Heminger
Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards (2)
Estimated Future Payouts
Under Equity Incentive Plan
Awards (3)
Type of
Award
Grant
Date
Approval
Date(1)
Threshold
($)
Target
($)
Maximum
($)
Threshold
($)
Target
($)
Maximum
($)
MPLX LP
Phantom
Units
MPLX LP
Performance
Units
3/1/2016 2/23/2016
3/1/2016 2/23/2016
137,500 1,100,000 2,200,000
Pamela
K.M. Beall
MPC Stock
Options
3/1/2016 2/23/2016 N/A
MPC
Restricted
Stock
MPC
Performance
Units
MPC
Annual
Cash Bonus
MPLX LP
Phantom
Units
MPLX LP
Performance
Units
MPC
Annual
Cash Bonus
MPC
Annual
Cash Bonus
MPLX LP
Phantom
Units
MPLX LP
Performance
Units
MPC
Annual
Cash Bonus
MPC
Annual
Cash Bonus
Nancy K.
Buese
Donald C.
Templin
C. Corwin
Bromley
Gregory S.
Floerke
3/1/2016 2/23/2016
3/1/2016 2/23/2016
21,250
170,000
340,000
N/A
367,500
735,000
3/1/2016 2/23/2016
3/1/2016 2/23/2016
26,563
212,500
425,000
N/A
427,500
855,000
N/A
720,000 1,440,000
3/1/2016 2/23/2016
28,270
3/1/2016 2/23/2016
93,750
750,000 1,500,000
N/A
372,000
744,000
N/A
336,000
672,000
All
Other
Shares
of
Stock
or
Units
(#)
41,463
2,455
8,010
All Other
Option
Awards:
Underlying
Options
(#)
Exercise
or Base
Price of
Option
Awards
($)
Grant
Date And
Option
Awards(4)
($)
1,100,013
701,580
17,052
34.63
170,008
85,017
97,427
212,505
135,533
750,003
478,350
(1)
(2)
The MPC Compensation Committee and our Board approved the awards reported in the table above for
Ms. Beall and Messrs. Heminger and Templin on February 23, 2016, with a grant date of March 1, 2016.
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.
235
(3)
(4)
The target amounts shown in this column reflect the number of performance units granted to Ms. Beall and
Messrs. Heminger 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 2016 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 $9.97 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, 2016, grants of MPC restricted stock awards was $34.63 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 $0.5731 per unit as calculated using a Monte Carlo
valuation model. Assumptions used in the calculation of these amounts are included in Note 23 to MPC’s
financial statements as reported on its Annual Report on Form 10-K for the year ended December 31, 2016.
The price used for the March 1, 2016, grants of MPLX LP phantom unit awards was $26.53 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 grant date fair value of $0.6378 per unit as calculated using a
Monte Carlo valuation model. 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 with a grant date of March 1, 2016. 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 restricted stock awards to Ms. Beall with a grant date of March 1,
2016, which vest in one-third increments on the first, second and third anniversaries 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 our 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 performance units to Ms. Beall with a grant date of March 1, 2016.
Each performance unit has a target value of $1.00 and is designed to settle 25 percent in MPC common stock and
236
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, 2016, through
December 31, 2018, 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 one-half of the performance period
(18 months) for the 2015 grant or the completion of nine months of the performance period for the 2016 grant,
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. For the 2016 grant, if an NEO retires under MPC’s
mandatory retirement policy, outstanding performance units will fully vest, however payout will occur at the end
of the full 36-month performance cycle based on the certified results of the performance cycle. 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 for the 2015 grant
immediately vest at target levels. For the 2016 grant, 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 phantom unit awards to Ms. Beall and Messrs. Heminger and Templin with a grant
date of March 1, 2016. The phantom unit awards vest in one-third increments on the first, second and third
anniversaries 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 performance units to Ms. Beall and Messrs. Heminger and Templin with a grant date
of March 1, 2016. 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, 2016, through December 31, 2018, performance period. No cash distributions are paid and there are
no voting rights associated with unvested performance units. If an NEO retires following the completion of
one-half of the performance period (18 months) for the 2015 grant or the completion of nine months of the
performance period for the 2016 grant, 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. For the 2016 grant, if an NEO
237
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 for the 2015 grant immediately vest at
target levels. For the 2016 grant, unvested performance units will vest and be paid out based on MPLX LP’s
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 change in control to the end of
the performance cycle. If an NEO terminates employment under any other circumstance, unvested performance
units are forfeited.
Outstanding Equity Awards at 2016 Fiscal Year-End
The following table provides information regarding unvested MPLX LP phantom units, unvested MPLX LP
performance units, unvested MPC restricted stock and unvested MPC performance units held by each of our
NEOs as of December 31, 2016:
Number of
Securities
Underlying
Unexercised
Options
Exercisable
Number of
Securities
Underlying
Unexercised
Options
Unexercisable
(#)
Option
Exercise
Price
($)
Option
Expiration
Date
Grant
Date
Name
Gary R. Heminger
Pamela K.M. Beall
MPLX
LP
MPLX
LP
Market
Value of
Shares or
Units of
Stock
That
Have Not
Vested(3)
($)
Number of
Shares or
Units of
Stock
That Have
Not Vested(2)
(#)
Equity
Incentive
Plan Awards:
Number of
Unearned
Shares, Units
or Other
Rights that
Have Not
Vested(4)
(#)
Equity
Incentive
Plan Awards:
Market or
Payout Value
of Unearned
Shares, Units
or Other
Rights that
Have Not
Vested(5)
($)
57,223 1,981,060
2,200,000
1,350,030
9,282
321,343
297,500
168,071
3/1/2016 MPC
17,052(1)
34.63 3/1/2027
2,455
123,609
170,000
582,828
Donald C. Templin
C. Corwin Bromley
Gregory S. Floerke
MPLX
LP
MPLX
LP
MPC
MPLX
LP
MPC
31,803 1,101,020
1,000,000
556,825
67,389 2,333,007
19,861 1,000,001
54,126 1,873,842
19,861 1,000,001
(1)
(2)
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, 2017, March 1, 2018 and March 1, 2019.
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, 2016. 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.
238
Name
Grant Date
Number of Unvested Units
Vesting Dates
MPLX LP Phantom Units
Gary R. Heminger
Pamela K.M. Beall
Donald C. Templin
3/1/2014
3/1/2015
3/1/2016
3/1/2014
3/1/2015
3/1/2016
3/1/2014
3/1/2015
3/1/2016
C. Corwin Bromley
12/18/2015
Gregory S. Floerke
12/18/2015
3/1/2017
3/1/2017, 3/1/2018
3/1/2017, 3/1/2018, 3/1/2019
3/1/2017
3/1/2017, 3/1/2018
3/1/2017, 3/1/2018, 3/1/2019
3/1/2017
3/1/2017, 3/1/2018
3/1/2017, 3/1/2018, 3/1/2019
Upon termination without cause
12/18/2017, 12/18/2018
Upon termination without cause
12/18/2017, 12/18/2018
6,840
8,920
41,463
57,223
582
690
8,010
9,282
1,505
2,028
28,270
31,803
50,240
17,149
67,389
36,476
17,650
54,126
MPC Restricted Stock
Name
Grant Date
Number of Unvested Shares
Vesting Dates
Pamela K.M. Beall
C. Corwin Bromley
Gregory S. Floerke
3/1/2016
12/18/2015
12/18/2015
2,455
19,861
19,861
3/1/2017, 3/1/2018, 3/1/2019
12/18/2018
12/18/2018
(3)
(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, 2016, using the December 30, 2016,
MPLX LP common unit closing price of $34.62 per unit and MPC closing price of $50.35 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”
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 30, 2016, of $50.35 per share.
The amounts shown in this column reflect the number of unvested performance units held by Ms. Beall and
Messrs. Heminger and Templin on December 31, 2016. Performance unit grants awarded in 2016 have a
36-month performance cycle and are designed to settle 25 percent in MPLX LP common units/MPC 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 is tied to our TUR/TSR as compared to specified peer groups.
239
Name
Gary R. Heminger
Pamela K.M. Beall
Donald C. Templin
MPLX LP Performance Units
Grant Date
Number of Unvested Units
3/1/2015
3/1/2016
3/1/2015
3/1/2016
3/1/2015
3/1/2016
1,100,000
1,100,000
2,200,000
85,000
212,500
297,500
250,000
750,000
1,000,000
Performance Period
Ending Date
12/31/2017
12/31/2018
12/31/2017
12/31/2016
12/31/2017
12/31/2018
MPC Performance Units
Name
Pamela K.M. Beall
Grant Date
Number of Unvested Units
Performance Period
Ending Date
3/1/2016
170,000
12/31/2018
(5)
The amount shown in this column for MPC reflects the aggregate value of all performance units held by
Ms. Beall on December 31, 2016, assuming a payout of $1.1428 per unit for the March 1, 2015, grant and
$1.1428 per unit for the March 1, 2016, grant, which is the next higher performance achievement that exceeds
the performance for these grants’ performance period that ended December 31, 2016. The amounts shown in
this column for MPLX LP reflect the aggregate value of all performance units held by Ms. Beall and Messrs.
Heminger and Templin on December 31, 2016, assuming a payout of $0.7273 per unit for the March 1, 2015,
grant and $0.50 per unit for the March 1, 2016, grant, which is the next higher performance achievement that
exceeds the performance for these grants’ performance period that ended December 31, 2016.
Option Exercises and Units Vested in 2016
The following table provides information regarding phantom units and MPC restricted stock that vested in 2016.
Name
Gary R. Heminger
Pamela K.M. Beall
Donald C. Templin
C. Corwin Bromley
Gregory S. Floerke
Stock Awards
Number of Units/Shares
Acquired on Vesting (#)
Value Realized on Vesting(1)
($)
MPLX LP
MPLX LP
MPC
MPLX LP
MPLX LP
MPLX LP
20,398
1,456
2,938
4,642
8,574
8,825
529,253
37,803
101,281
120,432
276,340
284,430
(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 2016
Pension Benefits
MPC provides tax-qualified pension 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 $120,000 or more in 2016).
240
2016 Pension Benefits Table
Name
Pamela K.M. Beall
Donald C. Templin
C. Corwin Bromley
Gregory S. Floerke
Plan Name
Marathon Petroleum Retirement Plan
Marathon Petroleum Excess Benefit Plan
Marathon Petroleum Retirement Plan
Marathon Petroleum Excess Benefit Plan
Marathon Petroleum Retirement Plan
Marathon Petroleum Excess Benefit Plan
Marathon Petroleum Retirement Plan
Marathon Petroleum Excess Benefit Plan
Number of Years of
Credited Service(1)
Present Value of
Accumulated
Benefit(2)($)
Payments
During Last
Fiscal Year
14.67 years
14.67 years
5.50 years
5.50 years
1.0 year
1.0 year
1.0 year
1.0 year
716,871 —
1,348,690 —
121,068 —
720,749 —
28,577 —
61,871 —
22,179 —
40,668 —
(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 3.90 percent, the RP2000 mortality table for lump sums, a 96 percent lump sum
election rate and retirement at age 62 (or current age, if later). In accordance with the Marathon Petroleum
Retirement Plan provisions and actuarial assumptions, the discount rate for lump sum calculations varied
from 1.00 percent to 1.25 percent based on the anticipated year of retirement.
The 2016 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, 2016. 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.
241
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.
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
2016, Ms. Beall received pay credits equal to 11 percent of compensation, which is the highest level of pay credit
available under the plan. Mr. Templin received pay credits equal to nine percent of compensation. Mr. Bromley
received pay credits equal to 11 percent of compensation and Mr. Floerke 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 two 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
242
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. Templin, 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.
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 25 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 on or after January 1, 2016, 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, 2016, was 1.76 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.
243
2016 Non-Qualified Deferred Compensation
Name
Pamela K.M. Beall
Marathon Petroleum Excess Benefit Plan
Marathon Petroleum Deferred Compensation Plan
Donald C. Templin
Marathon Petroleum Deferred Compensation Plan
C. Corwin Bromley
Marathon Petroleum Deferred Compensation Plan
Gregory S. Floerke
Marathon Petroleum Deferred Compensation Plan
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
($)
—
—
—
—
—
— 2,685.00 —
55,877.00 30,135.00 —
133,053.00
725,976.00
109,852.20 39,194.10 —
545,989.50
39,061.00
3,105.00 —
42,166.00
32,989.00
2,366.00 —
35,354.00
(1)
The amounts shown in this column are also included in the “All Other Compensation” column of the 2016
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
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 in compliance with,
or 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.
244
Potential Payments Upon a Termination or Change In Control
The only situation in which an NEO would receive payment due to the accelerated vesting of our performance
units and phantom units, without the discretion of the board of directors of our general partner, would be upon a
termination from service in connection with the change in control of MPLX LP. The amount payable to each of
our NEOs, assuming such termination occurred on December 31, 2016, based on our MPLX LP common unit
closing price and MPC stock closing price as of that date and assuming our performance units settled at target,
would have been as follows: Mr. Heminger, $4,181,060; Ms. Beall, $618,843; Mr. Bromley, $3,333,008;
Mr. Floerke, $2,873,843; and Mr. Templin, $2,101,020.
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 $1,500 per meeting for each
conflicts committee meeting such member attends in a calendar year in excess of six meetings.
Further, each director is indemnified for his or her actions associated with being a director to the fullest extent
permitted under Delaware law and is reimbursed for all expenses incurred in attending to his or her duties as a
director.
245
2016 Director Compensation Table
Amounts reflected in the table below represent compensation earned by or paid to our general partner’s
non-employee directors for the year ended December 31, 2016.
Fees
Earned or
Paid in
Cash(1)
($)
75,000
75,000
90,000
75,000
90,000
12,432
75,000
90,000
Unit
Awards(2)
($)
Option
Awards
($)
Non-Equity
Incentive Plan
Compensation
($)
75,000 —
75,000 —
75,000 —
75,000 —
75,000 —
12,432 —
75,000 —
75,000 —
—
—
—
—
—
—
—
—
Change in
Pension Value
and Non-
Qualified
Deferred
Compensation
Earnings
($)
—
—
—
—
—
—
—
—
All Other
Compensation(3)
($)
—
—
10,000
—
10,000
—
—
—
Total
($)
150,000
150,000
175,000
150,000
175,000
24,864
150,000
165,000
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
(1)
(2)
(3)
The amounts shown in this column reflect the director cash retainers and committee chair and lead director
fees paid for service from January 1, 2016, through December 31, 2016.
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 2016. 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, 2016, for
each non-employee director is as follows: Messrs. Daberko, Helms, Sandman, Surma, and Wilson, 7,552;
Mr. Peiffer, 5,077; Mr. Beatty, 2,563; and Mr. Semple, 366.
The amounts shown in this column reflect contributions made on behalf of Messrs. Helms and Sandman to
educational institutions under our matching gifts program.
246
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, 2016 (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(2)
Marathon Petroleum Corporation(1)
86,619,313
24.2% 7,371,105
100%
25.5%
539 S. Main Street
Findlay, Ohio 45840
Tortoise Capital Advisors, L.L.C.(3)
11550 Ash Street, Suite 300
Leawood, Kansas 66211
ALPS Advisors, Inc.(4)
1290 Broadway, Suite 1100
Denver, Colorado 80203
Alerian MLP ETF(4)
1290 Broadway, Suite 1100
Denver, Colorado 80203
18,894,274(3)
5.4%(3)
—
—
5.1%
18,146,214(4)
5.2%(4)
—
—
4.9%
17,970,288(4)
5.2%(4)
—
—
4.9%
(1)
(2)
The 86,619,313 common units representing limited partner interests (“Common Units”) are directly held by
MPLX Logistics Holdings LLC and MPLX Holdings Inc. The 7,371,105 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 Common Units directly held by
MPLX Logistics Holdings LLC and MPLX Holdings Inc., and the general partner units directly owned 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
interest in MPC Investment LLC.
Percentages were calculated including the Class B units on an as-converted basis. All of the 3,990,878
Class B units currently outstanding are owned by M&R MWE Liberty LLC and will convert into
approximately 4.4 million Common Units on July 1, 2017.
(3) According to a Schedule 13G/A filed with the SEC on February 14, 2017, 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
247
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
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 18,894,274
Common Units or 5.4% of the Common Units outstanding, sole voting power over 344,682 of our Common
Units, shared voting power over 16,345,231 of our Common Units, sole dispositive power over 344,682 of
our Common Units and shared dispositive power over 18,549,592 of our Common Units.
(4) According to a Schedule 13G/A filed with the SEC on January 26, 2017, 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 18,146,214 Common Units or 5.21% of the Common Units outstanding, sole voting
power over none of our Common Units, shared voting power over 18,146,214 of our Common Units, sole
dispositive power over none of our Common Units and shared dispositive power over 18,146,214 of our
Common Units. Subject to the above, and according to the Schedule 13G/A, Alerian MLP ETF reported that
it has beneficial ownership of 17,970,288 Common Units or 5.16% of the Common Units outstanding, sole
voting power over none of our Common Units, shared voting power over 17,970,288 of our Common Units,
sole dispositive power over none of our Common Units and shared dispositive power over 17,970,288 of
our Common Units.
248
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, 2017,
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
Nancy K. Buese
David A. Daberko
Gregory S. Floerke
Timothy T. Griffith
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
Frank M. Semple
John P. Surma
Donald C. Templin
C. Richard Wilson
All Directors and Executive Officers as a group (18
reporting persons)
Amount and Nature of
Beneficial Ownership(1)
Percent of
Total
Outstanding
174,753(2)(5)(6)(7)
21,892(2)(5)(7)
30,554(2)(4)
118,314(2)(5)
76,830(2)(5)
19,843(2)(3)(4)
77,181(2)(5)
18,302(2)(5)(7)
19,173(2)(4)
37,395(4)(6)
52,173(2)(4)
577,461(2)(3)(4)(6)
17,343(2)(3)(4)
57,409(2)(5)(7)
18,173(2)(4)
1,553,318(2)(3)(4)(5)(6)(7)
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
(4)
(3)
(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,
2017, for each of Messrs. Daberko and Surma is 1,670; and Mr. Semple 180.
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 Non-Management Director
Compensation Policy and Director Equity Award Terms. The aggregate number of phantom unit awards
credited as of January 31, 2017, for the non-management directors of our general partner is as follows:
Messrs. Daberko, Helms, Sandman, Surma and Wilson, 8,173 each; Mr. Beatty, 3,184; Mr. Peiffer, 5,698;
and Mr. Semple, 987.
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, 2017, by each applicable director or named executive officer of our general partner is as
follows: Mr. Heminger, 26,750; Mr. Peiffer, 31,697; and Mr. Semple, 527,517.
Includes common units issued in settlement of performance units within sixty days of January 31, 2017.
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.
*
(6)
(7)
(5)
249
The following table sets forth the number of shares of MPC common stock beneficially owned as of January 31,
2017, 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
Nancy K. Buese
David A. Daberko
Gregory S. Floerke
Timothy T. Griffith
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
Frank M. Semple
John P. Surma
Donald C. Templin
C. Richard Wilson
All Directors and Executive Officers as a group (18
reporting persons)
Amount and Nature of
Beneficial Ownership(1)
Percent of
Total
Outstanding
2,589,729(2)(5)(6)(8)(9)(10)
138,293(2)(5)(9)(10)
—
19,861(5)
—
144,998(2)(3)
19,950(5)(6)
160,261(2)(5)(9)(10)
—
277,084(8)(9)
—
1,170(3)
37,375(3)(8)
482,296(2)(5)(9)(10)
—
4,161,343(2)(3)(4)(5)(6)(7)(8)(9)(10)
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
(1) None of the shares of common stock reported in this column are pledged as security.
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
*
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, 2017, is as follows: Mr. Daberko, 140,998;
Mr. Semple, 1,170; and Mr. Surma, 27,375.
Includes restricted stock unit awards granted pursuant to the Marathon Petroleum Corporation 2012
Incentive Compensation Plan, a portion of which may be forfeited under certain conditions.
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, 2017, 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, 2017, including 255,210 stock options
exercisable by the applicable directors and named executive officers but not in the money as of January 31,
2017.
Includes shares of common stock issued in settlement of performance units within sixty days of January 31,
2017.
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.
250
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 2016, 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)
1,277,354
—
1,277,354
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)
1,229,440
—
1,229,440
(1)
Includes the following:
(a) 1,173,411 phantom unit awards granted pursuant to the MPLX 2012 Plan for common units unissued
and not forfeited, cancelled or expired as of December 31, 2016.
(b) 103,943 units as the maximum potential number of common units that could be issued in settlement of
performance units outstanding as of December 31, 2016, pursuant to the MPLX 2012 Plan based on the
closing price of our common units on December 31, 2016, of $34.62 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 103,943 as the maximum potential number of common units that could be
issued in settlement of performance units outstanding as of December 31, 2016, pursuant to the MPLX 2012
Plan based on the closing price of our common units on December 31, 2016, of $34.62 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 14, 2016, the Partnership entered into a Membership
Interests Contribution Agreement (the “Contribution Agreement”) with MPLX GP, MPLX Logistics Holdings
LLC and MPC Investment LLC (“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.
The general partner units maintained MPC’s two percent general partner interest in the Partnership. The
acquisition closed on March 31, 2016. MPC waived distributions in the first quarter of 2016 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, 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 (MarkWest Hydrocarbon, Inc. prior to the
251
Class A Reorganization), were either distributed to or purchased by MPC in exchange for $84 million in cash and
a fixed number of MPLX LP common units and MPLX LP general partner units. Following these preparatory
transactions, all of the MPLX LP Class A units were exchanged on a one-for-one basis for newly issued common
units representing limited partner interests in MPLX LP. MPC also contributed $141 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. See Item 8. Financial Statements and Supplementary Data—Note 8 for more
information on this transaction.
As of February 13, 2017, MPC owned 86,619,313 common units. In addition, our general partner owned
7,372,419 general partner units as well as all of our incentive distribution rights. Our general partner manages our
operations and activities through its officers and directors. Messrs. Heminger, Templin, Nickerson and
Swearingen serve as executive officers 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, we make 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. If distributions exceed the minimum quarterly distribution and target distribution levels, the
general partner is entitled to increasing percentages of our distributions, up to 48 percent of our distributions
above the highest target distribution level. In 2016, we paid MPC $142 million in cash distributions with respect
to its common units, and $190 million in cash distributions with respect to its two percent general partner
interest.
Reimbursements paid to MPC
Pursuant to our third amended and restated agreement of limited partnership, we are required to reimburse our
general partner and its affiliates, including MPC, for all costs and expenses that 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 2016, we reimbursed our general
partner $7 million for costs and expenses incurred on our behalf.
Transportation and Storage Services Agreements
We are a party to long-term, fee-based transportation and storage services agreements with MPC. Under these
agreements, we provide transportation and storage services to MPC, and MPC provides us with minimum
quarterly throughput and storage volumes of crude oil and products and minimum storage volumes of butane.
These commercial agreements with MPC are described in more detail under Item 1. Business—Our
Transportation and Storage Services Agreements with MPC and Item 8. Financial Statements and Supplementary
Data—Note 6. We recorded aggregate revenues of $717 million for 2016 under these transportation and storage
services agreements.
Operating Service Agreements
We are a party to an operating services agreement with MPC, under which we operate various pipeline systems
owned by MPC. In addition, MPC is a party to operating services agreements with Marathon Pipe Line LLC (or
MPL), a wholly-owned subsidiary of Pipe Line Holdings. MPL operates various pipeline systems owned by
252
MPC. Under these operating services agreements, we receive an operating fee for operating the assets and are
reimbursed for all direct and indirect costs associated with operating the assets. Most of these agreements are
indexed for inflation. These agreements have terms ranging from one to five years and automatically renew
unless terminated by either party. The operating service agreements are described in Item 1. Business—
Operating and Management Services Agreements with MPC and Third Parties and Item 8. Financial Statements
and Supplementary Data—Note 6. We recorded other income of $22 million and were reimbursed for
$17 million of costs and expenses for 2016 under these operating services agreements.
Management Services Agreements
We are a party to two management services agreements with MPC, under which we provide certain management
services to MPC with respect to certain of MPC’s retained pipeline assets. MPC pays us a fixed annual fee under
the agreements for providing the management services, as adjusted for inflation and changes in the scope of
management services provided. These management services agreements are described in more detail under
Item 1. Business—Operating and Management Services Agreements with MPC and Third Parties, and Item 8.
Financial Statements and Supplementary Data—Note 6. We recorded other income of $22 million in fees for
2016 under these management services agreements.
Omnibus Agreement
We are a party to an omnibus agreement with MPC, under which we pay a fixed annual fee to MPC for the
provision by MPC of executive management services by certain executive officers of our general partner, as well
as certain general and administrative services and marketing and transportation engineering services. The
omnibus agreement also requires us to reimburse MPC for any out-of-pocket costs and expenses incurred by
MPC in providing these services. Also under the omnibus agreement, MPC has agreed to indemnify us for
certain matters, including environmental, title and tax matters. The omnibus agreement is described in more
detail under Item 1. Business—Other Agreements with MPC and Item 8. Financial Statements and
Supplementary Data—Note 6. We incurred service fees and expenses of $63 million under the omnibus
agreement for 2016.
Employee Services Agreements
We are a party to four employee services agreements with MPC, under which we reimburse MPC for the
provision of certain operational and management services in support of our facilities. The employee services
agreements are described in more detail under Item 1. Business—Other Agreements with MPC and Item 8.
Financial Statements and Supplementary Data—Note 6. We incurred aggregate expenses of $359 million under
the employee services agreements for 2016.
Licensing Agreement
MPL and MPC are parties to a license agreement with respect to a terminal property leased by MPL, pursuant to
which MPC has access to and operates the terminal. The agreement will remain in effect until February 1, 2020.
We recorded other income of $1 million in 2016 related to this agreement.
Loan Agreement
On December 4, 2015, the Partnership entered into a loan agreement with 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
253
unpaid interest and other amounts (if any), will 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. There was no outstanding balance on this loan as of
December 31, 2016.
Other Sales to MPC
We recorded aggregate revenues of $11 million in 2016 related to certain products MPC purchased from the
Partnership. For 2016, there was $46 million 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.
Time Sharing Agreement
We are a party to a time sharing agreement with MPC, under which we use certain aircraft leased and operated
by MPC. Under this agreement, we reimburse MPC for the costs associated with leasing and operating the
aircraft based on our actual use of the aircraft. The agreement will remain in effect until terminated by either
party. We incurred expenses of less than $1 million under the time sharing agreement for 2016.
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 or executive officer or more
than five percent owner. This procedure applies to any transaction, arrangement or relationship or 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 interest; provided that the following
transactions, arrangements or relationships will be deemed to have standing pre-clearance 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 arising 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;
254
•
•
•
the impact on a director’s independence in the event the related person is a director or an immediate
family member of a director;
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 or not 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, 2016, and December 31, 2015, are presented in the following table:
Fees(1)
(In millions)
Audit
Audit-Related
Tax
All Other
Total
2016
2015
$
4
—
1
—
$
4
—
1
—
$
5
$
5
(1)
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 2016 and 2015, 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 2016 or 2015.
The Audit fees for the years ended December 31, 2016, and December 31, 2015, 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 Tax fees for the year ended December 31, 2016, and December 31, 2015, were for professional services
rendered for the preparation of IRS Schedule K-1 tax forms for MPLX LP unit holders and for income tax
consultation services.
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
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
8-K
2.1
3/4/2014
001-35714
8-K
2.1
12/2/2014
001-35714
2.3† Agreement and Plan of Merger, dated as of
10-Q
2.1
8/3/2015
001-35714
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
Certificate of Limited Partnership of MPLX
LP
Amendment to the Certificate of Limited
Partnership of MPLX LP
Third Amended and Restated Agreement of
Limited Partnership of MPLX LP, dated as of
October 31, 2016
First Amendment to Third Amended and
Restated Agreement of Limited Partnership of
MPLX LP, dated as of February 23, 2017
Indenture, dated February 12, 2015, between
MPLX LP and The Bank of New York
Mellon Trust Company, N.A., as Trustee
2.4
2.5
2.6
3.1
3.2
3.3
3.4
4.1
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
S-1
3.1
7/2/2012 333-182500
S-1/A
3.2
10/9/2012 333-182500
10-Q
3.3 10/31/2016
001-35714
X
8-K
4.1
2/12/2015
001-35714
258
Exhibit
Number
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
10.1
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
8-K
4.2
2/12/2015
001-35714
8-K
4.1 12/22/2015
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
8-K
4.2
2/10/2017
001-35714
8-K 10.1 11/26/2014
001-35714
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)
Registration Rights Agreement dated as of
December 22, 2015 by and among MPLX LP,
MPLX GP LLC, and each of Citigroup Global
Markets Inc., J.P. Morgan Securities LLC and
Merrill Lynch, Pierce, Fenner & Smith
Incorporated
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
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
Credit Agreement, dated as of November 20,
2014, among MPLX LP, as borrower,
Citibank, N.A., as administrative agent, each
of Citigroup Global Markets Inc., Wells Fargo
Securities, LLC, Barclays Bank PLC, J.P.
Morgan Securities LLC, Merrill Lynch,
Pierce, Fenner & Smith Incorporate and RBS
Securities Inc., as joint lead arrangers and
joint bookrunners, Wells Fargo Bank, N.A., as
259
Exhibit
Number
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
syndication agent, and each of Bank of
America, N.A., Barclays Bank PLC,
JPMorgan Chase Bank, N.A., and The Royal
Bank of Scotland PLC, as documentation
agents, and the other lenders and issuing
banks that are parties thereto
10.2* MPLX LP 2012 Incentive Compensation Plan S-1/A 10.3
10/9/2012 333-182500
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
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
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)
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
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
260
Exhibit
Number
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Storage Services Agreement, dated effective
as of October 1, 2012, by and between
Marathon Pipe Line LLC and Marathon
Petroleum Company LP (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
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
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
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
261
Exhibit
Number
10.21
10.22
10.23
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Transportation Services Agreement (ORPL
Products System), dated as of October 31,
2012, between Marathon Petroleum Company
LP and Ohio River Pipe Line LLC
Transportation Services Agreement (Robinson
Products System), dated as of October 31,
2012, between Marathon Petroleum Company
LP and Marathon Pipe Line LLC
Transportation Services Agreement (Wood
River Barge Dock), dated as of October 31,
2012, between Marathon Petroleum Company
LP and Marathon Pipe Line LLC
8-K 10.10
11/6/2012
001-35714
8-K 10.11
11/6/2012
001-35714
8-K 10.12
11/6/2012
001-35714
10.24* MPC Non-Employee Director Phantom Unit
10-K 10.26
3/25/2013
001-35714
Award Policy
10.25* Form of MPLX LP Phantom Unit Award
10-Q 10.1
5/9/2013
001-35714
Agreement—Officer
10.26* Form of MPLX LP Performance Unit Award
Agreement—2013-2015 Performance Cycle
10.27* MPLX LP—Form of MPC Officer Phantom
Unit Agreement
10-Q 10.2
5/9/2013
001-35714
10-Q 10.3
5/9/2013
001-35714
10.28* MPLX LP—Form of MPC Officer
10-Q 10.4
5/9/2013
001-35714
Performance Unit Award Agreement—2013-
2015 Performance Cycle
10.29* Amendment to Outstanding Phantom Unit
10-K 10.31
2/28/2014
001-35714
Award Agreement of Garry L. Peiffer dated
November 18, 2013
10.30* MPLX GP LLC Amended and Restated
10.31
Non-Management Director Compensation
Policy and Equity Award Terms
First Amendment to Amended and Restated
Operating Agreement, dated as of January 1,
2015, between Marathon Petroleum Company
LP and Marathon Pipe Line LLC
10.33
10.32 Operating Agreement, dated as of January 1,
2015, between Hardin Street Transportation
LLC and Marathon Pipe Line LLC
Lock-Up Agreement, dated July 11, 2015, by
and among MPLX LP, MPLX GP LLC,
Sapphire Holdco LLC, MarkWest Energy
Partners, L.P., M&R MWE Liberty, LLC,
EMG Utica, LLC and EMG Utica
Condensate, 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
10.34
X
10-Q 10.2
5/4/2015
001-35714
10-Q 10.3
5/4/2015
001-35714
10-Q 10.2
8/3/2015
001-35714
8-K 10.1
6/17/2015
001-35714
262
Exhibit
Number
10.35
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
First Amendment to Storage Services
Agreement, dated as of September 17, 2015,
by and between Marathon Petroleum
Company LP and Marathon Pipe Line LLC
8-K 10.1
9/23/2015
001-35714
10.36 Amendment Agreement, dated as of
8-K 10.1
11/2/2015
001-35714
October 27, 2015, by and among MPLX LP,
Citibank, N.A., Wells Fargo Bank, National
Association, and the other institutions named
on the signature pages thereto
10.37
Loan Agreement, by and between MPLX LP
and MPC Investment LLC, dated December 4,
2015
8-K 10.1 12/10/2015
001-35714
10.38* Retention Agreement, by and between
8-K 10.2 12/10/2015
001-35714
Marathon Petroleum Company LP and Nancy
K. Buese, dated September 14, 2015
10.39* Retention Agreement, by and between
8-K 10.3 12/10/2015
001-35714
Marathon Petroleum Company LP and John
C. Mollenkopf, dated November 12, 2015
10.40* Letter Agreement, by and between Marathon
Petroleum Corporation and Paula L. Rosson,
dated October 6, 2015
8-K 10.4 12/10/2015
001-35714
10.41* Retention Agreement, by and between
10-K 10.41
2/26/2016
001-35714
Marathon Petroleum Company LP and Greg
S. Floerke, dated September 14, 2015
10.42* Retention Agreement, by and between
10-K 10.42
2/26/2016
001-35714
10.43
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
8-K 10.1
1/4/2016
001-35714
10.44* Executive Employment Agreement effective
8-K 10.1
9/11/2007
001-31239
September 5, 2007 between MarkWest
Hydrocarbon, Inc. and Frank Semple
10.45 Voting Agreement, dated July 11, 2015, by
10-Q 10.1
8/3/2015
001-35714
and among MPLX LP, MPLX GP LLC,
Sapphire Holdco LLC and M&R MWE
Liberty, LLC
10.46 Voting Agreement, dated as of November 16,
8-K 10.1 11/17/2015
001-35714
2015, by and among MPLX LP, MPLX GP
LLC, Sapphire Holdco LLC, Kayne Anderson
Capital Advisors, L.P. and KA Fund
Advisors, LLC
10.47 Voting Agreement, dated as of November 16,
8-K 10.2 11/17/2015
001-35714
2015, by and among MPLX LP, MPLX GP
LLC, Sapphire Holdco LLC, and Tortoise
Capital Advisors, L.L.C.
263
Exhibit
Number
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
10.48+ Second Amended and Restated Limited
10-K 10.48
2/26/2016
001-35714
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
10.49 Amended and Restated Transportation
8-K 10.1
4/6/2016
001-35714
10.50
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
8-K 10.2
4/6/2016
001-35714
10.51 Amended and Restated Management Services
8-K 10.3
4/6/2016
001-35714
10.52
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
10.53* Form of MPLX LP Performance Unit Award
Agreement—Marathon Petroleum
Corporation Officer
10.54* Form of MPLX LP Phantom Unit Award
Agreement—Marathon Petroleum
Corporation Officer
8-K 10.4
4/6/2016
001-35714
10-Q 10.6
5/2/2016
001-35714
10-Q 10.7
5/2/2016
001-35714
10.55* Form of MPLX LP Performance Unit Award
10-Q 10.8
5/2/2016
001-35714
Agreement
10.56* Form of MPLX LP Phantom Unit Award
10-Q 10.9
5/2/2016
001-35714
Agreement—Officer
10.57
Series A Preferred Unit Purchase Agreement,
dated as of April 27, 2016, by and among
MPLX LP and the Purchasers party thereto
10.58 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.
10.59
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
4/29/2016
001-35714
8-K 10.1
9/6/2016
001-35714
10-Q 10.2 10/31/2016
001-35714
264
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
Exhibit
Number
10.60
10.61
10.62
10.63
12.1
14.1
21.1
23.1
24.1
31.1
31.2
32.1
32.2
10-Q 10.1
8/3/2016
001-35714
10-Q 10.2
8/3/2016
001-35714
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)
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
265
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Exhibit
Number
Exhibit Description
Form Exhibit
Filing Date
SEC File No.
Filed
Herewith
Furnished
Herewith
Incorporated by Reference
101.CAL XBRL Taxonomy Extension Calculation
Linkbase
101.DEF XBRL Taxonomy Extension Definition
Linkbase
101.LAB XBRL Taxonomy Extension Label
Linkbase
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% 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.
266
Item 16. Form 10-K Summary
Not applicable.
267
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
February 24, 2017
MPLX LP
By: MPLX GP LLC
Its general partner
By: /s/ Paula L. Rosson
Paula L. Rosson
Senior Vice President and Chief Accounting
Officer of MPLX GP LLC
(the general partner of MPLX LP)
268
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on February 24, 2017 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/ Paula L. Rosson
Paula L. Rosson
*
Donald C. Templin
*
Michael L. Beatty
*
David A. Daberko
*
Timothy T. Griffith
*
Christopher A. Helms
*
Garry L. Peiffer
*
Dan D. Sandman
*
Frank M. Semple
*
John P. Surma
*
C. Richard Wilson
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)
Senior Vice President and Chief Accounting Officer
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 24, 2017
269
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COMPANY INFORMATION
Headquarters
200 East Hardin St.
Findlay, OH 45840
(419) 421-2414
Independent Accountants
PricewaterhouseCoopers LLP
406 Washington St., Suite 200
Toledo, OH 43604
MPLX LP Website
www.MPLX.com
Stock Exchange Listing
New York Stock Exchange
Investor Relations Office
539 South Main St.
Findlay, O H 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
Common Unit Symbol
MPLX
Principal Unit Transfer Agent
Computershare
250 Royall St.
Canton, MA 02021
(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 2016 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
PO 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
10/26/12
12/12
12/13
12/14
12/15
12/16
The above graph compares the cumulative total return, assuming the reinvestment of
distributions, of a $100 investment in our common units from Oct. 26, 2012 (the effective
date of our IPO), to Dec. 31, 2016, 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: Buckeye
Partners LP; Enbridge Energy Partners LP; Energy Transfer Partners LP; Enterprise Products
Partners LP; Magellan Midstream Partners LP; ONEOK Partners LP; Phillips 66 Partners LP;
Plains All American Pipeline LP; Sunoco Logistics Partners LP; Tesoro Logistics LP; Valero
Energy Partners LP; Western Gas Partners LP; and Williams Partners LP.
The above performance graph is not “soliciting material” and will not be deemed to be
fi led with the Securities and Exchange Commission (SEC) or incorporated 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.
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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 13 and in the MPLX Annual Report on Form 10-K for the year ended Dec. 31, 2016, 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 company. 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, 2016, 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.
®
MPLX LP
200 EAST HARDIN ST.
FINDLAY, OH 45840
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