Marathon Petroleum Annual Report 2015

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2015
Annual Report

2015 MARATHON PETROLEUM CORPORATION

Annual Report

WE ARE POSITIONED TO RESPOND TO

BOTH SHORT-TERM AND LONG-TERM

CHANGES IN CRUDE OIL SUPPLIES

AND REFINED PRODUCT DISTRIBUTION

NEEDS, PROVIDING COMPELLING

VALUE TO OUR INVESTORS AND THE

MARKETS WE SERVE.

On the cover, top to bottom: MPC’s Galveston
Bay refinery in Texas City, Texas; a new Speedway
store in Findlay, Ohio; MarkWest processing and
fractionation complex in Houston, Pa.

Marathon Petroleum Corporation 2015 Annual Report

2 Chairman's letter

We are positioned to help
meet the nation’s and the
world’s energy needs well
into the future.

4 CEO's letter

Our ongoing success is
attributable to our strategy
of maintaining flexibility
and optionality.

31 Financial and

Operational Highlights
Our integrated system,
strategically located assets
and operational excellence
give us a competitive
advantage.

32 Board of Directors
33 Corporate Officers

MarkWest operations in Hopedale, Ohio. In
December, MPC’s sponsored master limited
partnership, MPLX LP, acquired MarkWest.

DELIVERING FOR INVESTORS

From becoming an independent company July 1, 2011, to year-end 2015

MPC HAS RETURNED
AN AVERAGE OF

$5.7 Million
per day

TO SHAREHOLDERS

CUMULATIVE CAPITAL RETURN
TO SHAREHOLDERS
In Billions

$9.4

$7.8

$5.2

$1.9

2012

2013

2014

2015

Dividends

Share repurchases

28%

OF
SHARES
REPURCHASED

1 Marathon Petroleum Corporation 2015 Annual Report

From the Chairman

Fellow shareholders,

AT MARATHON PETROLEUM CORPORATION, WE LOOK BACK ON 2015 WITH
THE SAME SENSE OF ACCOMPLISHMENT AS WE HAVE EACH YEAR SINCE
2011, WHEN WE BECAME AN INDEPENDENT COMPANY. IT WAS ANOTHER
YEAR IN WHICH WE ENHANCED OUR ABILITY TO PROVIDE SOLID LONG-
TERM RETURNS TO OUR OWNERS. IT WAS ANOTHER YEAR IN WHICH WE
POSITIONED OURSELVES TO HELP MEET THE NATION’S AND THE WORLD’S
ENERGY NEEDS WELL INTO THE FUTURE.

Our dual focus on capital returns to shareholders and investing
strategically in the company’s growth has yielded excellent results.
During the year, we returned $1.6 billion to our owners. We intend
to continue a disciplined approach to resource allocation and
capital returns in 2016 and beyond.

We have continued to execute on our commitment to grow the
stable earnings from MPC’s retail and midstream businesses while
simultaneously improving margins in our refining and marketing
segment. We have accomplished this not just through strategic
transactions, but also through our ability to successfully integrate
new acquisitions into our structure.

We have implemented this transformative process repeatedly
across our value chain. We created MPLX LP as a midstream
master limited partnership, which benefits MPC shareholders
through MPC’s ownership interest in MPLX’s general partner.
We acquired the Galveston Bay refinery, significantly increasing
our refining capacity in the geographically critical U.S. Gulf
Coast region. We almost doubled Speedway’s marketing footprint
and have made tremendous progress converting the new stores
to the Speedway brand. And MPLX’s acquisition of MarkWest
Energy Partners, L.P. expands MPLX into the midstream natural
gas business.

These strategic transactions have increased our scale and
diversified our geography and operations. They make us a
stronger company and a better investment.

MPC has been in the energy business for almost 130 years, and
we have a long memory of what it takes to succeed. As we continue
to strengthen our long-term value proposition in the world’s energy
market, we thank you for sharing in our vision, and for contributing
to our success.

Sincerely,

Thomas J. Usher
Chairman

Marathon Petroleum Corporation 2015 Annual Report 2

MPC DELIVERING RESULTS

Earnings(2) ($ billion)

Dividend Increase

Share Repurchases ($ billion)

(1)Includes two quarters as an independent, publicly traded company
(2)Represents net income attributable to MPC

2011(1)
2.39

25%

2012
3.39

40%

1.35

2013
2.11

2014
2.52

2015
2.85

20%

19%

28%

2.79

2.13

0.96

$13
Billion

CUMULATIVE
NET INCOME
SINCE SPINOFF

29.5%

COMPOUND ANNUAL
GROWTH RATE
IN BASE DIVIDEND
SINCE SPINOFF

3 Marathon Petroleum Corporation 2015 Annual Report

From the President and CEO

Our earnings in 2015 were $2.85 billion, or $5.26 per
diluted share. We continued to share our success
with shareholders, paying approximately $600 million
in dividends and purchasing $1 billion of our shares
throughout the year. At the end of the year, there
was $2.76 billion remaining under the share
repurchase authorizations approved by our board
of directors. We will maintain discipline in capital
investments and returns to our shareholders as
we further optimize our capital structure, liquidity
position and strategic objectives.

Our ongoing success is attributable to our strategy of
maintaining flexibility and optionality. We have been
creating a diverse portfolio within our sector of the
energy industry, encompassing refining, marketing,
logistics and retail. While prioritizing capital returns
to shareholders, we have also been consistently
investing to grow cash flow from the more stable
retail and midstream segments of our business, as
well as continually improving the margins in our
refining and marketing segment.

Investors have continued to recognize the value of
owning our stock. At year-end 2015, MPC share
value had increased 150 percent since we became
an independent company in 2011. In fact, our share
price last year reached a point at which we declared
a two-for-one stock split, making shares more
affordable for a wider range of investors.

Continued ➛

Marathon Petroleum Corporation 2015 Annual Report 4

Fellow shareholders,MARATHON PETROLEUM CORPORATION’S INTEGRATED REFINING, MARKETING AND LOGISTICS SYSTEM CONTINUED TO YIELD EXCELLENT RESULTS DURING 2015. WE ARE POSITIONED TO RESPOND TO BOTH SHORT-TERM AND LONG-TERM CHANGES IN CRUDE OIL SUPPLIES AND REFINED PRODUCT DISTRIBUTION NEEDS, WHICH PROVIDES COMPELLING VALUE TO OUR INVESTORS AND THE MARKETS WE SERVE.REFINING AND MARKETING

ENHANCING MARGINS AT OUR REFINERIES CONTINUES TO BE A

PRIORITY, AND IN 2015 WE MADE SIGNIFICANT PROGRESS THROUGH

OPTIMIZATIONS AND CAPITALIZING ON STRATEGIC OPPORTUNITIES.

In the second quarter we
commissioned a 35,000 barrel-
per-day (bpd) condensate splitter
at our refinery in Catlettsburg, Ky.
Along with the 25,000 bpd splitter
at our Canton, Ohio, refinery that
was completed in late 2014, we
now have up to 60,000 bpd of
condensate processing capacity
in the prolific Utica and Marcellus
shale regions.

Throughout our refining system, we
continued implementing projects
that focus on technical excellence
and improving the performance
of process units. In addition to
the splitter projects, we have
also implemented hydrocracker
projects at our refinery in Garyville,
La., and our Galveston Bay refinery
in Texas City, Texas, as well as
expanded our refined product
export capacity. These investments
– about $900 million since 2013 –
have contributed approximately
$600 million of EBITDA in 2015
alone, a rate of return we
anticipate will be sustainable
in the years ahead.

System-wide, we have increased
our overall crude oil refining
capacity by 63,000 bpd, an
approximately 4 percent increase
over 2014. At our Galveston Bay
refinery in particular, we have
increased crude oil throughput
and reliability while reducing
environmental and safety incidents
since we acquired the facility in
2013. In the fourth quarter of last
year, we announced a program that
will fully integrate our Galveston
Bay and Texas City, Texas, plants

5 Marathon Petroleum Corporation 2015 Annual Report

Kerosene desulfurization unit at the
MPC refinery in Catlettsburg, Ky.

Fluid catalytic cracking unit at
our Canton, Ohio, refinery

Maintenance work at our Robinson, Ill., refinery

MPC’s Texas City, Texas, refinery, adjacent
to our Galveston Bay refinery

MPC’s refinery in Detroit, Mich.

Marathon Petroleum Corporation 2015 Annual Report 6

into a single, world-class refining
complex. These high-return,
staged investments – collectively
referred to as the South Texas Asset
Repositioning (STAR) program –
are designed to increase residual
oil processing, ultra-low-sulfur
diesel (ULSD) production capacity,
distillate and gas oil recovery,
increase our crude oil capacity,
and enhance reliability, among
other improvements.

We continue to identify projects
that enable us to capture additional
value from the growth in ULSD
demand. The planned increase
associated with the STAR program
comes on the heels of other
projects at our plants in Garyville,
Robinson, Ill., and an additional
project at Galveston Bay, all of
which have increased our distillate
hydrotreating capacity to about
35 percent of our crude
throughput. By 2020, we plan to
complete projects that bring this
total to more than 37 percent, an
industry-leading position.

Among the variety of other
margin-improvement projects
that are in progress and planned,
we have two fluid catalytic

7 Marathon Petroleum Corporation 2015 Annual Report

Storage tanks at MPC’s Texas City, Texas, refinery

Left to right: Rod Price,
Bryan Stephens,
Harrell Duff, Tom Hearn,
Brian Roark, Mike Rolen

TOTAL REFINERY
THROUGHPUTS
Million Barrels Per Day

1.80

1.81

1.89

1.36

MECHANICAL
AVAILABILITY*
Percentage of Combined
Unit Capacity

94.9

93.5

95.5

2013

2014

2015

2013

2014

2015

* Rated capacity of all MPC operations, less lost capacity due to planned and
unplanned outages, divided by rated capacity

STAR PROGRAM
TEAM

In the fourth quarter we

announced a program that will

fully integrate the Galveston

Bay refinery with our Texas

City refinery into a single,

world-class refining complex.

These high-return, staged

investments – collectively

referred to as the South Texas

Asset Repositioning (STAR)

program – are designed to

increase residual oil processing,

ultra-low-sulfur diesel (ULSD)

production capacity, distillate

and gas oil recovery, increase

our crude oil capacity, and

enhance reliability, among

other improvements.

Marathon Petroleum Corporation 2015 Annual Report 8

Robinson, Ill., refinery

INCREASING EXPORT CAPACITY
Thousand Barrels Per Day

510*

345

365

320

150

2012

2013

2014
*Estimated

2015

2019

cracker (FCC) projects that will
increase our production capacity
for alkylate and light products.
Our FCC project at Garyville is
slated for completion in 2016, while
we plan to bring a project on stream
at our Detroit refinery in 2018. We
anticipate the combined investment
of approximately $360 million
will contribute $130 million of
EBITDA annually.

Due to low natural gas prices and
low crude oil costs, we anticipate
MPC will have a sustained advantage
relative to refiners around the world,
and we have continued to increase
our refined product export capacity
accordingly. In 2015 we completed
a project to expand our Garyville
refinery’s gasoline export capacity,
and a distillate export capacity
increase is in progress at Galveston
Bay. By the end of 2015, we had
increased our finished-products
export capacity to 365,000 bpd. We
estimate that by year-end 2019, we
will reach 510,000 bpd of export
capacity, providing us with
additional flexibility to reach
higher value markets.

As we continue to evaluate projects
that enhance our refining margins, we
will maintain our focus on discipline:
allocating capital to the projects that
yield the best returns.

9 Marathon Petroleum Corporation 2015 Annual Report

Export dock on the Mississippi River at MPC’s refinery in Garyville, La.

Control room at the Galveston Bay refinery in Texas City, Texas

Marathon Petroleum Corporation 2015 Annual Report 10

SPEEDWAY

DURING 2015 WE MADE EXCELLENT PROGRESS ON OUR STRATEGY TO INCREASE

OUR RETAIL SEGMENT’S CONTRIBUTIONS TO STABLE CASH FLOW, DRIVEN IN LARGE

PART BY THE NEW LOCATIONS ACQUIRED IN 2014. THROUGH LIGHT-PRODUCT

SUPPLY AND LOGISTICS BENEFITS, MARKETING ENHANCEMENTS, AND REDUCTIONS

IN OUR OPERATING, GENERAL AND ADMINISTRATIVE EXPENSES, SPEEDWAY HAS

EXCEEDED THE $75 MILLION IN SYNERGIES WE EXPECTED FROM THE NEW STORES

IN 2015, ACHIEVING APPROXIMATELY $150 MILLION BY THE END OF THE YEAR.

Conversion of the new stores
was well ahead of our initial
plans at year-end, with almost
1,100 stores converted to
the Speedway brand and
technology platform. In
addition to being ahead of
schedule, we expect the store
conversions to be completed
under budget. Speedway also
remodeled 285 stores during the
year. The accelerated pace of
both conversions and remodels
provides a foundation for sales
uplift and merchandise margin
enhancements.

At the same time, we also
focused on organic growth in
existing markets. This includes
our legacy seven-state Midwest
footprint, as well as Pennsylvania
and Tennessee, where we began
opening new stores in 2013. By the
end of 2015, we had 55 projects in
these two states completed or in
progress, and by 2020 we expect
to have 130 complete. We have
also begun increasing our presence
in Georgia and South Carolina
to take advantage of expansion
opportunities in Speedway’s
existing marketing footprint in
those states.

Continued on Page 15

11 Marathon Petroleum Corporation 2015 Annual Report

Speedway stores

$150
Million

SYNERGIES ACHIEVED
IN 2015 BY
ACQUIRED STORES

SPEEDWAY
MERCHANDISE
SALES
$ Billion

SPEEDWAY
MERCHANDISE
GROSS MARGIN
$ Million

2013

2014

2015

2013

2014

2015

*Includes impact of acquisition, closed Sept. 30, 2014

New Speedway store in Findlay, Ohio

Marathon Petroleum Corporation 2015 Annual Report 12

Standing, left to right: John Kalian, Tony Carf,
Nathan Mackendrick, Joey Allen, Paul Ricci
Seated, left to right: Jim Phillips, Tony Hackathorne,
Jim Gabriel, Sarah Tyler

13 Marathon Petroleum Corporation 2015 Annual Report

New Speedway store in Beavercreek, Ohio

SPEEDWAY
CONVERSION TEAM

Conversion of the new stores we

acquired along the East Coast and

Southeast in 2014 was well ahead

of our initial plans at year-end.

The conversion was substantially

complete, with almost 1,100

stores converted to the Speedway

brand and technology platform.

In addition to being ahead of

schedule, we expect the store

conversions to be completed

under budget. The accelerated

pace of both conversions and

remodels provides a foundation

for sales uplift and merchandise

margin enhancements.

1,100

NEWLY ACQUIRED
STORES CONVERTED
TO THE
SPEEDWAY BRAND

Marathon Petroleum Corporation 2015 Annual Report 14

Speedway’s organic growth will not only enable us
to continue growing our stable cash flow, but also
complements our refining and distribution network.
Along with the network of approximately 5,600
independently owned Marathon brand stations,
our approximately 2,770 Speedway stations provide
assured sales for approximately 70 percent of
MPC’s gasoline production.

As our refineries continued to identify and
implement investments to capture additional
value from increasing diesel demand, Speedway
is capitalizing on this growth at the retail level and

working to provide greater volumes of assured
diesel sales. Trucking is expected to remain the
dominant mode of transportation in the U.S.
and freight volumes are projected to increase
over the next decade, with diesel demand
expected to outpace gasoline demand. Over
the last three years Speedway has increased
its commercial fueling lane locations, and at
year-end, we had 150 commercial fueling lane
locations built.

Speedway is able to generate stable cash
flow through its top-tier performance, and
performs at the top end of its peers on

4.7 MILLION

ACTIVE MEMBERS OF THE
SPEEDY REWARDS® PROGRAM IN 2015

15 Marathon Petroleum Corporation 2015 Annual Report

an EBITDA-per-store basis. Prior to the 2014
acquisition of our stores along the East Coast
and Southeast, our margins were comprised of
approximately 65 percent merchandise and
35 percent light petroleum products. The margin
mix in 2015, due to the acquisition, was about
55 percent merchandise and 45 percent light
products. Our objective is to continue focusing
on c-store growth at the acquired locations and
return to the approximately two-thirds merchandise
margin level, which results in more stable cash flow.

Right, a Speedway
store in Harrison, N.J.
Below, a Speedway
store in Findlay, Ohio

Marathon Petroleum Corporation 2015 Annual Report 16

MIDSTREAM

THROUGH MPC’S GENERAL PARTNER INTEREST IN MPLX LP, OUR SHAREHOLDERS HAVE

A POWERFUL DRIVER OF LONG-TERM VALUE. MPLX’S ACQUISITION IN DECEMBER OF

MARKWEST ENERGY PARTNERS, L.P. WAS A PIVOTAL DEVELOPMENT THAT FURTHER

STRENGTHENS THAT VALUE. PRIOR TO THE ACQUISITION, MPLX PRIMARILY SERVED

MPC’S EXTENSIVE CRUDE OIL AND REFINED PRODUCT LOGISTICS NEEDS. WITH

THE ADDITION OF MARKWEST’S SKILLED MANAGEMENT TEAM AND WORLD-CLASS

ASSETS, MPLX NOW INCLUDES A RESPECTED INDUSTRY LEADER IN NATURAL GAS AND

NATURAL GAS LIQUIDS (NGL) GATHERING, PROCESSING AND FRACTIONATION

IN SOME OF THE NATION’S MOST PROLIFIC AND PROMISING PRODUCTION AREAS.

This extends MPC’s strength across the hydrocarbon value chain.
MarkWest operations geographically complement MPC’s and MPLX’s
operations, creating natural advantages as the logistics and processing
build-out in gas-producing areas continues. This synergy is particularly
prominent in the Marcellus and Utica shale regions of western
Pennsylvania and eastern Ohio, where MarkWest has established itself
as the clear leader in gathering and processing, and where MPC refining
and MPLX logistics assets share the same geographic footprint.

Continued on Page 21

17 Marathon Petroleum Corporation 2015 Annual Report

Above and below: MarkWest’s Hopedale
fractionation complex in Harrison County, Ohio

Marathon Petroleum Corporation 2015 Annual Report 18

Left to right: Jason Stechschulte, David Loiseau,
Jeff McGhee, Scott Garner

19 Marathon Petroleum Corporation 2015 Annual Report

MarkWest employee at the Sherwood
processing complex in Bridgeport, W.Va.

MARKWEST-MPLX
COMMERCIAL
SYNERGIES TEAM

MarkWest operations

geographically complement

MPC’s and MPLX’s operations,

creating natural advantages as the

logistics and processing build-out

in gas-producing areas continues.

This synergy is particularly

prominent in the Marcellus and

Utica shale regions of western

Pennsylvania and eastern Ohio,

where MarkWest has established

itself as the clear leader in

gathering and processing, and

where MPC refining and MPLX

logistics assets share the same

geographic footprint.

Marathon Petroleum Corporation 2015 Annual Report 20

The peer-leading growth potential
of this master limited partnership
(MLP) is based on several factors,
including MPC’s inventory of MLP-
eligible assets that can be dropped
down to MPLX, MarkWest’s
backlog of organic projects, and
incremental joint investment
opportunities we have identified.

We are committed to supporting
MPLX’s growth over an extended
period of time through MPC’s
inventory of potential drop-downs.
These include pipelines, terminals,
railcars, fuels distribution and
marine assets, among others,
totaling approximately $1.6 billion
of annual EBITDA. We continue to
grow this inventory to support our
refining and marketing business.
Among other investments, this
ongoing growth includes a blue-
water marine tanker joint venture
formed last year.

MPLX growth will also be bolstered
by legacy organic investments,
including the Cornerstone Pipeline,
which will transport liquids
production from the Utica region
of eastern Ohio to MPC’s refinery
in Canton, Ohio. Cornerstone
and associated build-out projects
are being constructed to provide
an industry solution, including
opportunities to connect other
Midwest refineries to Utica
production, with the potential to
ultimately reach Chicago-area
refineries and pipelines that supply
diluent to western Canada.

Organic projects at MarkWest also
represent sources of growth for
the new partnership. We expect
approximately $7.5 billion of new
projects through 2020, primarily
in the Northeast, which include

21 Marathon Petroleum Corporation 2015 Annual Report

MPLX assets at Patoka, Ill.

The M/V Nashville loading at MPLX’s Wood River, Ill., facility

CREATING A MORE DIVERSIFIED PORTFOLIO
TO GROW STABLE CASH FLOWS

2015 EBITDA*

2020 EBITDA
(est.)

Railcars at MPC’s Canton, Ohio, terminal

MIDSTREAM

SPEEDWAY

REFINING & MARKETING

*Includes one month of MarkWest EBITDA

Marathon Petroleum Corporation 2015 Annual Report 22

expansion of gathering systems,
development of processing and
fractionation infrastructure and
expansion of NGL logistics. We
also see $6 billion to $9 billion
of potential synergistic capital
project opportunities in the
future that would leverage MPC,
MPLX and MarkWest positions
across the hydrocarbon value
chain with substantial incremental
combined opportunities.

MPLX is positioned as a midstream
leader, and MPC shareholders
continue to benefit from our general
partner interest in this high-quality,
large-cap MLP with its compelling
long-term growth opportunities.

MPC has identified
MLP-eligible sources
of midstream
annual EBITDA
of approximately

$1.6 Billion

Pipeline infrastructure at an MPLX facility in Wood River, Ill.

MPLX terminal on the Ohio River at Wellsville, Ohio

23 Marathon Petroleum Corporation 2015 Annual Report

The M/V Ohio, a medium-range light-product tanker, delivered via a new joint venture
between MPC and Crowley Petroleum Services

Loading terminal at the Canton, Ohio, refinery

Marathon Petroleum Corporation 2015 Annual Report 24

SUSTAINABLE COMPETITIVE ADVANTAGES

AS WE CLOSE THE BOOKS ON A SUCCESSFUL AND TRANSFORMATIVE 2015, MPC
SHAREHOLDERS HAVE MUCH CAUSE FOR OPTIMISM GOING FORWARD. DURING THE
PAST YEAR – AS WE HAVE DONE CONSISTENTLY SINCE BECOMING AN INDEPENDENT
COMPANY – MPC PROVED THAT ITS FULLY INTEGRATED SYSTEM, STRATEGICALLY
LOCATED ASSETS AND FOCUS ON OPERATIONAL EXCELLENCE PROVIDE IT WITH A
COMPETITIVE ADVANTAGE THAT IS SUSTAINABLE FOR THE LONG TERM.

We continue to invest in
growing our earnings from
the more stable cash-flow
segments of our business,
even as we consistently
provide capital returns to our
shareholders. This balanced
approach has produced strong
results and enduring value.
Since our formation as a
standalone company in mid-
2011, we have generated more
than $13 billion in net income.
We have increased our base
dividend at a 29.5 percent
compound annual growth rate
and acquired approximately
28 percent of our shares that
were outstanding at the time
of our formation.

With our world-class assets,
focused investment strategy
and excellent operational
strength, we are positioned to
remain a solid investment for
our shareholders. We thank you
for investing in MPC, and look
forward to sharing our success
with you over the long term.

Sincerely,

Gary R. Heminger
President and Chief Executive Officer

25 Marathon Petroleum Corporation 2015 Annual Report

OUR BENEFITS TO SOCIETY

By manufacturing, transporting and marketing
petroleum products, the refining industry helps make
virtually every aspect of modern life possible. Through
our use of ever-improving processes and technologies,
we do this critical work more cleanly and safely than
ever before.

And yet, despite our dedication and more than a
century of technological progress, our industry faces
significant challenges from those who harbor a radically
different vision of how our society should power itself.
Rather than using the most affordable, technologically
feasible and plentiful energy sources known to mankind,
advocates and regulators are seeking to artificially
inflate the cost of these fuels to make alternatives
appear more practical.

The Environmental Protection Agency’s “Clean Power
Plan” rule is a good example of this. By requiring a
32 percent reduction in greenhouse gas emissions from
U.S. power plants by 2030, the rule makes coal-fired
power – the most plentiful and affordable power source
– artificially expensive and therefore infeasible. If the
EPA rule withstands court challenges, power for most
U.S. consumers will be more expensive, and it will drive
price increases for consumer goods and services as
businesses also contend with higher power costs. The
refining industry, as a major consumer of electric power,
will certainly be affected.

Also of note is the federal Renewable Fuel Standard,
which requires refiners and others to blend specific
volumes of biofuels – like ethanol and biodiesel – into
the nation’s fuel supply. We are required to blend
increasing amounts of biofuels into petroleum fuels,
even if fuel demand overall goes down. This mandate
not only increases costs for consumers, it also risks
damaging automobile engines as the mandated amount
of ethanol exceeds 10 percent of total fuel demand.
Most of the U.S. vehicle fleet is unable to safely handle
fuel with more than 10 percent ethanol.

Our industry makes agriculture possible. We enable
businesses to move goods to where they are needed
by consumers most. We make it possible for people
to transport themselves to the places and events that
make their lives full. We make it possible to build the
structures around which our lives revolve. We make
disaster recovery quicker and safer.

We will continue to perform this critical work, and to do
so in a way that meets the needs of our shareholders,
our employees, and the millions of people who rely on
our products every day. And we will continue to work
on their behalf by advocating against rules and activism
that will increase costs, decrease efficiency and reduce
quality of life for ideological or political reasons.

Marathon Petroleum Corporation 2015 Annual Report 26

63Owned and

part-owned
light product
terminals

120Third-party

light product
terminals

18Owned

asphalt
terminals

2Third-party

asphalt
terminals

owns, leases or has ownership interest in

8,400 Approximate miles of pipeline that MPC
205 Owned
19 Inland
173Owned transport trucks 2,210Owned or leased railcars

14 Leased

waterway
towboats

barges

Marketing Area

MPC Refineries

Light Product Terminals

MPC Owned and Part-owned

Third Party

Asphalt/Heavy Oil Terminals

MPC Owned

Third Party

Water Supplied Terminals

Coastal

Inland

Pipelines

MPC Owned & Operated

MPC Interest: Operated by MPC

MPC Interest: Operated by Others

Pipelines Used by MPC

Ethanol Facility

Biodiesel Facility

Tank Farms

Pipelines

Butane Cavern

Barge Dock

MarkWest Assets

27 Marathon Petroleum Corporation 2015 Annual Report

Detroit refinery

Texas City, Texas, refinery

CRUDE OIL REFINING CAPACITY

BPCD NCI*

Galveston Bay
Garyville
Robinson
Detroit
Catlettsburg
Canton
Texas City
TOTAL

459,000
539,000
212,000
132,000
273,000
93,000
86,000
1,794,000

13.5
11.2
10.5
9.7
9.2
7.8
7.8
10.9**

* Nelson Complexity Index (NCI) calculated
per Oil & Gas Journal NCI formula
**Weighted Average NCI
BPCD: barrels per calendar day
Source: MPC Data

Loading dock at Wood River, Ill.

Marathon Petroleum Corporation 2015 Annual Report 28

MARATHON BRAND AND SPEEDWAY LOCATIONS
Extensive Retail Network

12
114
1

240

64
51

303
753

110
314

308
646

489
848

147
578

37
362

2
237

6
311

111
65

68
130

288
292

61
119

62
133

Speedway
Marathon Brand

247
632

As of Dec. 31, 2015

SPEEDWAY
~2,770 stores
22 states

located in

2015 gasoline and distillate sales of over

6 billion gallons

MARATHON BRAND
owned and operated by
independent
entrepreneurs

~5,600 branded
locations
located in

19 states

2015 gasoline and distillate sales of over

5 billion gallons

29 Marathon Petroleum Corporation 2015 Annual Report

SPEEDWAY
GASOLINE AND
DISTILLATE SALES
Billion Gallons

2013

2014

2015

* Includes impact of Hess
acquisition, closed Sept. 30, 2014

MARATHON BRAND
GASOLINE AND
DISTILLATE SALES
Billion Gallons

4.92

4.98

5.02

2013

2014

2015

53%

increase in
Speedway gasoline
and distillate sales

Marathon Petroleum Corporation 2015 Annual Report 30

FINANCIAL AND OPERATIONAL HIGHLIGHTS

mm = millions
mbpd = thousand barrels per day

Revenues ($mm)

Income from operations ($mm)

Net income attributable to MPC ($mm)

Per-common-share data(a)

Net income attributable to MPC – basic ($)

Net income attributable to MPC – diluted ($)

Dividends ($)

Weighted average shares outstanding – basic(b) (mm)

Weighted average shares outstanding – diluted(b) (mm)

Cash and cash equivalents ($mm)

Total debt(c) ($mm)

Equity ($mm)

Capital expenditures and investments(d) ($mm)

Refinery throughput (crude oil – mbpd)

Refinery throughput (other charge and blendstocks – mbpd)

Total refinery throughput (mbpd)

Refined product yields (mbpd)

Gasoline

Distillates

Propane

Feedstocks and special products

Heavy fuel oil

Asphalt

Total refined product yields

R&M refined product sales volume(e) (mbpd)

R&M gross margin(f) ($/barrel)

Number of outlets (Marathon brand)

Number of convenience stores at year-end (Speedway)

Speedway gasoline and distillate sales (mm gallons)

2015

2014

2013

72,051

97,817

100,160

4,692

2,852

5.29

5.26

1.14

538

542

1,127

11,925

19,675

16,283

1,711

177

1,888

913

603

281

1,919

2,289

15.25

5,607

2,766

6,038

4,051

2,524

4.42

4.39

0.92

570

574

1,494

6,602

11,390

4,738

1,622

184

1,806

869

580

276

1,839

2,125

15.05

5,455

2,746

3,942

3,425

2,112

3.34

3.32

0.77

630

634

2,292

3,378

11,332

2,789

1,589

213

1,802

921

572

221

1,836

2,075

13.24

5,166

1,478

3,146

Speedway gasoline and distillate gross margin(g) ($/gallon)

0.1823

0.1775

0.1441

Speedway merchandise sales ($mm)

Speedway merchandise gross margin ($mm)

Crude oil and refined product pipeline throughput (mbpd)

Gathering system throughput (mm cubic feet/day)(h)

4,879

1,368

2,191

3,075

3,611

975

2,119

3,135

825

2,204

Natural gas processed (mm cubic feet/day)(h) 5,468

C2+ NGLs fractionated (mbpd)(h)

307

Number of employees

45,440

45,340

29,865

(a) Share data has been restated to reflect the stock split effected in 2015. (b) The number of weighted average shares for 2015, 2014
and 2013 reflect the impact of shares received under our share repurchase program. (c) Includes long-term debt due within one year.
We adopted the updated FASB debt issuance cost standard as of June 30, 2015, and applied the changes retrospectively to the
prior period presented. We reclassified unamortized debt issuance costs from other noncurrent assets to long-term debt. (d) Capital
expenditures and investments include acquisitions, changes in capital accruals and capitalized interest. (e) Includes intersegment
sales. (f) Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs. Excludes the lower
of cost or market adjustment. (g) The price paid by consumers less the cost of refined products, including transportation, consumer
excise taxes and bankcard processing fees, divided by gasoline and distillate sales volumes. Excludes the lower of cost or market
adjustment. (h) Includes amounts related to unconsolidated equity method investments. Includes the MarkWest results beginning on
the Dec. 4, 2015, merger date.

31 Marathon Petroleum Corporation 2015 Annual Report

Both BOD and Officers need to be retouched and outlined

BOARD OF DIRECTORS

Standing (left to right):

William L. Davis
Retired Chairman,
President and CEO,
R.R. Donnelley & Sons
Company. Prior to R.R.
Donnelley & Sons,
Mr. Davis was president
of Emerson Electric Co.
subsidiaries Appleton
Electric Co. and Skil
Corporation.

Steven A. Davis
Former Chairman and
CEO, Bob Evans Farms
Inc. Mr. Davis previously
served as president
of Long John Silver’s
and A&W All-American
Food Restaurants, and
held executive and
operational positions
in Yum! Brands’ Pizza
Hut division and Kraft
General Foods.

Evan Bayh
Senior Advisor, Apollo
Global Management and
Partner, McGuireWoods
LLP. Sen. Bayh was
U.S. senator from, and
governor of, Indiana.
Sen. Bayh served on
numerous Senate
committees, holding
key leadership roles on
several of them.

David A. Daberko
Retired Chairman and
CEO, National City
Corporation. Prior to
being chairman and
CEO, Mr. Daberko was
deputy chairman of
the corporation and
president of National
City Bank in Cleveland.

Charles E. Bunch
Executive Chairman,
PPG Industries. Mr. Bunch
joined PPG in 1979 and
held various positions of
increasing responsibility
before being appointed
president, chief operating
officer and board member
in 2002, and chairman
and CEO in 2005.

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 &
Accounting, president
of Speedway
SuperAmerica LLC,
and president of
Marathon Ashland
Petroleum LLC.

Frank M. Semple
Vice Chairman and
Director, MPLX GP LLC.
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.

Seated (left to right):

James E. Rohr
Retired Executive Chairman
and CEO, The PNC Financial
Services Group Inc. Mr. Rohr
joined PNC in 1972, serving in
various capacities of increasing
responsibility. He was named
CEO in 2000 and oversaw record
growth for PNC before stepping
down as CEO in 2013.

John W. Snow
Non-executive Chairman,
Cerberus Capital Management
LP. Prior to Cerberus Capital,
Mr. Snow was U.S. secretary
of the Treasury during the
George W. Bush administration.
He also was chairman and
CEO of CSX Corporation and
held several high-ranking
positions in the Department
of Transportation during the
Ford administration.

Thomas J. Usher
Non-executive Chairman of the
Board, Marathon Petroleum
Corporation. Mr. Usher held
a number of leadership
positions at United States Steel
Corporation (later named USX
Corp.) prior to his retirement,
including executive vice
president of Heavy Products,
president of U. S. Steel Group
and director of USX, president
and chief operating officer of
USX, and chairman of the board
and CEO.

Gary R. Heminger
President and CEO, Marathon
Petroleum Corporation.
Mr. Heminger joined Marathon
Oil Company in 1975 and has
held various leadership positions
during his more than 40 years
with the company. Prior to his
current position, Mr. Heminger
was head of Marathon’s
downstream operations
beginning in 2001.

Donna A. James
Managing Director, Lardon &
Associates LLC. Before joining
Lardon & Associates, Ms. James
was president of Nationwide
Strategic Investments. Prior to
being president, Ms. James
held various executive positions
at Nationwide. Ms. James is
founder and chair of The Center
for Healthy Families and is the
former chair of the National
Women’s Business Council.

Marathon Petroleum Corporation 2015 Annual Report 32

Both BOD and Officers need to be retouched and outlined

CORPORATE OFFICERS

Standing (left to right):

J. Michael Wilder
Vice President, General
Counsel and Secretary

Randy S. Nickerson
Executive Vice President,
Corporate Strategy

John J. Quaid
Vice President and
Controller

Thomas Kaczynski
Vice President,
Finance and
Treasurer

Seated (left to right):

Pamela K.M. Beall
Senior Vice President,
Corporate Planning,
Government and
Public Affairs

John R. Haley
Vice President, Tax

James P. Heintschel II
Vice President, Business
Development

Rodney P. Nichols
Senior Vice President,
Human Resources and
Administrative Services

Donald W. Wehrly
Vice President and Chief
Information Officer

Thomas M. Kelley
Senior Vice President,
Marketing

John S. Swearingen
Senior Vice President,
Transportation and Logistics

Anthony R. Kenney
President, Speedway LLC

Donald C. Templin
Executive Vice President

Gary R. Heminger
President and Chief
Executive Officer

Timothy T. Griffith
Senior Vice President and
Chief Financial Officer

Richard D. Bedell
Senior Vice President,
Refining

C. Michael Palmer
Senior Vice President,
Supply, Distribution and
Planning

In memoriam
1959 - 2016

George P. Shaffner
Senior Vice President,
Health, Environment,
Safety and Security

33 Marathon Petroleum Corporation 2015 Annual Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2015

Commission file number 001-35054
Marathon Petroleum Corporation
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of incorporation or organization)

27-1284632
(I.R.S. Employer Identification No.)

539 South Main Street, Findlay, OH 45840-3229
(Address of principal executive offices)
(419) 422-2121
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act

Title of Each Class
Common Stock, par value $.01

Name of Each Exchange on Which Registered
New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes Í 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 Í

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 and (2) has been subject to such filing requirements for the
past 90 days. Yes Í 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 Í No ‘

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. Í

Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, a non-accelerated filer, or a smaller
reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule
12b-2 of the Exchange Act. (Check one):
Large accelerated filer Í Accelerated filer ‘ Non-accelerated filer ‘ Smaller reporting company ‘
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ‘ No Í

The aggregate market value of Common Stock held by non-affiliates as of June 30, 2015 was approximately $28.0 billion.
This amount is based on the closing price of the registrant’s Common Stock on the New York Stock Exchange on June 30,
2015. Shares of Common Stock held by executive officers and directors of the registrant are not included in the computation.
The registrant, solely for the purpose of this required presentation, has deemed its directors and executive officers to be
affiliates.

There were 529,227,453 shares of Marathon Petroleum Corporation Common Stock outstanding as of February 12, 2016.

Documents Incorporated By Reference

Portions of the registrant’s proxy statement relating to its 2016 Annual Meeting of Shareholders, to be filed with the Securities
and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934, are incorporated by
reference to the extent set forth in Part III, Items 10-14 of this Report.

Unless otherwise stated or the context otherwise indicates, all references in this Annual Report on Form 10-K to “MPC,” “us,”
“our,” “we” or “the Company” mean Marathon Petroleum Corporation and its consolidated subsidiaries.

MARATHON PETROLEUM CORPORATION

Table of Contents

PART I

PART II

Item 1.

Business

Item 1A. Risk Factors

Item 1B. Unresolved Staff Comments

Item 2.

Item 3.

Properties

Legal Proceedings

Item 4. Mine Safety Disclosures

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and

Issuer Purchases of Equity Securities

Item 6.

Selected Financial Data

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of

Operations

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Item 8.

Item 9.

Financial Statements and Supplementary Data

Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure

Item 9A. Controls and Procedures

Item 9B. Other Information

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

Item 15. Exhibits and Financial Statement Schedules

SIGNATURES

PART III

PART IV

Page

101

172

173

174

175

176

182

Throughout this report, the following company or industry specific terms and abbreviations are used:

GLOSSARY OF TERMS

ASR
barrel

DEI
EBITDA (a non-GAAP financial measure)
EIA
EPA
FASB
FCC
FERC
IDR
IRS
LIBO Rate
LIFO
LLS
mbpd
mbpcd
Mcf
mmbpcd
MMcf/d
MMBtu
NYMEX
NYSE
NGL

PADD
OPEC
OSHA
OTC
ppb
ppm
RFS2

RINs
ROUX
SEC
SMR

STAR
ULSD
ULSK
US GAAP
USGC
USTs
VIE
VPP
WTI

Accelerated share repurchase
One stock tank barrel, or 42 United States gallons liquid volume,
used in reference to crude oil or other liquid hydrocarbons.
Designated Environmental Incidents
Earnings Before Interest, Tax, Depreciation and Amortization
United States Energy Information Administration
United States Environmental Protection Agency
Financial Accounting Standards Board
Fluid Catalytic Cracking
Federal Energy Regulatory Commission
Incentive Distribution Rights
Internal Revenue Service
London Interbank Offered Rate
Last in, first out
Louisiana Light Sweet crude oil, an oil index benchmark price
Thousand barrels per day
Thousand barrels per calender day
One thousand cubic feet of natural gas
Million barrels per calender day
One million cubic feet of natural gas per day
One million British thermal units per day
New York Mercantile Exchange
New York Stock Exchange
Natural gas liquids, such as ethane, propane, butanes and natural
gasoline
Petroleum Administration for Defense District
Organization of Petroleum Exporting Countries
United States Occupational Safety and Health Administration
Over-the-Counter
Parts per billion
Parts per million
Revised Renewable Fuel Standard program, as required by the
Energy Independence and Security Act of 2007
Renewable Identification Numbers
Residual Oil Upgrader Expansion
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
South Texas Asset Repositioning
Ultra-low sulfur diesel
Ultra-low sulfur kerosene
Accounting principles generally accepted in the United States
U.S. Gulf Coast
Underground storage tanks
Variable interest entity
Voluntary Protection Program
West Texas Intermediate crude oil, an oil index benchmark price

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,” “potential,”
“estimate,” “expect,” “forecast,” “goal,” “intend,” “plan,” “predict,” “project,” “seek,” “target,” “could,” “may,”
“should,” “will,” “would” or other similar expressions that convey the uncertainty of future events or outcomes.
In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these
statements are accompanied by cautionary language identifying important factors, though not necessarily all such
factors, that could cause future outcomes to differ materially from those set forth in the forward-looking
statements.

Forward-looking statements include, but are not limited to, statements that relate to, or statements that are subject
to risks, contingencies or uncertainties that relate to:

•

future levels of revenues, refining and marketing gross margins, operating costs, retail gasoline and
distillate gross margins, merchandise margins, income from operations, net income or earnings per
share;

anticipated volumes of feedstock, throughput, sales or shipments of refined products;

anticipated levels of regional, national and worldwide prices of crude oil, natural gas, NGLs and
refined products;

anticipated levels of crude oil and refined product inventories;

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;

business strategies, growth opportunities and expected investments,
investments in pipeline projects;

including planned equity

expectations regarding the acquisition or divestiture of assets;

our share repurchase authorizations,
repurchases;

including the timing and amounts of any common stock

the adequacy of our capital resources and liquidity, including but not limited to, availability of
sufficient cash flow to execute our business plan;

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; 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 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
risks, contingencies and
subject
uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, our

to significant business, economic, competitive,

regulatory and other

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:

•

volatility or degradation in general economic, market, industry or business conditions;

the effects of lifting the U.S. crude oil export ban;

availability and pricing of domestic and foreign supplies of natural gas, NGLs and crude oil and other
feedstocks;

the ability of the members of the OPEC to agree on and to influence crude oil price and production
controls;

availability and pricing of domestic and foreign supplies of refined products such as gasoline, diesel
fuel, jet fuel, home heating oil and petrochemicals;

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

refining industry overcapacity or under capacity;

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

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

changes to the expected construction costs and timing of pipeline projects;

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

fluctuations in consumer demand for refined products, natural gas and NGLs, including seasonal
fluctuations;

political and economic conditions in nations that consume refined products, natural gas and NGLs,
including the United States, and in crude oil producing regions, including the Middle East, Africa,
Canada and South America;

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

completion of pipeline projects within the U.S.;

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;

• modifications to MPLX LP earnings and distribution growth objectives;

•

the ability to successfully implement growth opportunities;

the risk that the synergies from the MarkWest Merger (defined below) may not be fully realized or may
take longer to realize than expected;

risks and uncertainties associated with intangible assets, including any future goodwill or intangible
assets impairment charges;

the ability to realize the strategic benefits of joint venture opportunities;

•

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

unusual weather conditions and natural disasters, which can unforeseeably affect
availability of crude oil and other feedstocks and refined products;

the price or

acts of war, terrorism or civil unrest that could impair our ability to produce refined products, receive
feedstocks or to gather, process, fractionate or transport crude oil, natural gas, NGLs or refined
products;

state and federal environmental, economic, health and safety, energy and other policies and regulations,
including the cost of compliance with the renewable fuel standard program;

rulings, judgments or settlements and related expenses in litigation or other legal, tax or regulatory
matters, including unexpected environmental remediation costs, in excess of any reserves or insurance
coverage;

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

labor and material shortages;

the maintenance of satisfactory relationships with labor unions and joint venture partners;

the ability and willingness of parties with whom we have material relationships to perform their
obligations to us;

the market price of our common stock and its impact on our share repurchase authorizations;

changes in the credit ratings assigned to our debt securities and trade credit, changes in the availability
of unsecured credit and changes affecting the credit markets generally;

capital market conditions and our ability to raise adequate capital to execute our business plan; 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.

PART I

Item 1. Business

Overview

Marathon Petroleum Corporation (“MPC”) has 128 years of experience in the energy business with roots tracing
back to the formation of the Ohio Oil Company in 1887. We are one of the largest independent petroleum
product refining, marketing, retail and transportation businesses in the United States and the largest east of the
Mississippi. With the merger of MPLX LP (“MPLX”), the midstream master limited partnership sponsored by
MPC, and MarkWest Energy Partners, L.P. (“MarkWest”) effective December 4, 2015 (the “MarkWest
Merger”), we believe we are one of the largest natural gas processors in the United States and the largest
processor and fractionator in the Marcellus and Utica shale regions. Our operations consist of three reportable
operating segments: Refining & Marketing; Speedway; and Midstream. Each of these segments is organized and
managed based upon the nature of the products and services it offers.

• Refining & Marketing – refines crude oil and other feedstocks at our seven refineries in the Gulf Coast
and Midwest regions of the United States, purchases refined products and ethanol for resale and
distributes refined products through various means, including barges, terminals and trucks that we own
or operate. We sell
to wholesale marketing customers domestically and
internationally, buyers on the spot market, our Speedway® business segment and to independent
entrepreneurs who operate Marathon® retail outlets.

refined products

•

Speedway – sells transportation fuels and convenience products in the retail market in the Midwest,
East Coast and Southeast.

• Midstream – includes the operations of MPLX and certain other related operations. Following the
MarkWest Merger, we changed the name of this segment from Pipeline Transportation to Midstream to
reflect its expanded business activities. There were no changes to the historical financial information
reported for this segment. The Midstream segment gathers, processes and transports natural gas;
gathers, transports, fractionates, stores and markets natural gas liquids and transports and stores crude
oil and refined products.

See Item 8. Financial Statements and Supplementary Data – Note 10 for operating segment and geographic
financial information, which is incorporated herein by reference.

Corporate History and Structure

MPC was incorporated in Delaware on November 9, 2009 in connection with an internal restructuring of
Marathon Oil Corporation (“Marathon Oil”). On May 25, 2011, the Marathon Oil board of directors approved the
spinoff of its Refining, Marketing & Transportation Business (“RM&T Business”) into an independent, publicly
traded company, MPC, through the distribution of MPC common stock to the stockholders of Marathon Oil
common stock on June 30, 2011 (the “Spinoff”). Following the Spinoff, Marathon Oil retained no ownership
interest in MPC, and each company has separate public ownership, boards of directors and management. All
subsidiaries and equity method investments not contributed by Marathon Oil to MPC remained with Marathon
Oil and, together with Marathon Oil, are referred to as the “Marathon Oil Companies.” On July 1, 2011, our
common stock began trading “regular-way” on the NYSE under the ticker symbol “MPC.”

Recent Developments

On December 4, 2015, a wholly-owned subsidiary of MPLX, the midstream master limited partnership sponsored
by MPC, merged with MarkWest, whereby MarkWest became a wholly-owned subsidiary of MPLX. 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 of MPLX representing limited partner interests
in MPLX, plus a one-time cash payment of $6.20 per unit. Each Class B unit of MarkWest outstanding
immediately prior to the merger was converted into the right to receive one Class B unit of MPLX having
substantially similar rights, including conversion and registration rights, and obligations that the Class B units of
MarkWest had immediately prior to the merger. At closing, we contributed $1.23 billion in cash to MPLX to pay
the cash consideration to MarkWest common unitholders. We will contribute an additional total of $50 million in
cash to MPLX for the cash consideration to be paid upon the conversion of the MPLX Class B units to MPLX
common units in equal installments in July 2016 and July 2017, respectively. These contributions are with
respect to MPC’s existing interests in MPLX (including IDRs) and not in consideration of new units or other
equity interest in MPLX. Our financial results and operating statistics reflect the results of MarkWest from the
date of the acquisition.

Consistent with our strategy to grow our midstream business, the MarkWest Merger combines one of the nation’s
largest processors of natural gas and the largest processor and fractionator in the Marcellus and Utica shale
regions with a rapidly growing crude oil and refined products logistics partnership sponsored by MPC. The
complementary aspects of the highly diverse asset base of MarkWest, MPLX and MPC provide significant
additional opportunities across multiple segments of the hydrocarbon value chain. The combined entity will
further MarkWest’s leading midstream presence in the Marcellus and Utica shales by allowing it to pursue
additional midstream projects, which should allow producer customers to achieve superior value for their
growing production in these important shale regions. In addition, the combination provides significant vertical
integration opportunities, as MPC is a large consumer of NGLs.

In September 2015, we acquired a 50 percent ownership interest in a new joint venture with Crowley Maritime
Corporation through our investment in Crowley Ocean Partners LLC (“Crowley Ocean Partners”), which is
included in our Refining & Marketing segment. The joint venture will operate and charter four new Jones Act
product tankers, most of which will be leased to MPC. Contributions to the joint venture with respect to each
vessel will occur at the vessel’s delivery. During 2015, we contributed $72 million in connection with delivery of
the first two vessels. The remaining two vessels are expected to be delivered by the third quarter of 2016. We
account for our ownership interest in Crowley Ocean Partners as an equity method investment. See Item 8.
Financial Statements and Supplementary Data – Note 25 for information on our conditional guarantee of the
indebtedness of the joint venture and future contributions to Crowley Ocean Partners.

On September 30, 2014, we acquired from Hess Corporation (“Hess”) all of its retail locations, transport
operations and shipper history on various pipelines, including approximately 40 mbpd on Colonial Pipeline, for
$2.82 billion. We refer to these assets as “Hess’ Retail Operations and Related Assets” and substantially all of
these assets are part of our Speedway segment. This acquisition significantly expands our Speedway presence
from nine to 22 states throughout the East Coast and Southeast and is aligned with our strategy to grow higher-
valued, stable cash flow businesses. This acquisition also enables us to further leverage our integrated refining
and transportation operations, providing an outlet for incremental assured sales from our refining system. The
transaction was funded with a combination of debt and available cash. Our financial results and operating
statistics reflect the results of Hess’ Retail Operations and Related Assets from the date of the acquisition.

In July 2014, we exercised our option to acquire a 35 percent ownership interest in Enbridge Inc.’s Southern
Access Extension (“SAX”) pipeline which runs from Flanagan, Illinois to Patoka, Illinois. This option resulted
from our agreement to be the anchor shipper on the SAX pipeline and our commitment to the Sandpiper pipeline
project as discussed below. During 2015, we made contributions of $147 million to Illinois Extension Pipeline
Company, LLC (“Illinois Extension Pipeline”) to fund our portion of the construction costs for the SAX project.
We have contributed $267 million since project inception. The pipeline became operational in December 2015.
Our investment in the pipeline is included in our Midstream segment.

On April 1, 2014, we purchased a facility in Cincinnati, Ohio from Felda Iffco Sdn Bhd, Malaysia for $40
million. The plant currently produces biodiesel, glycerin and other by-products. The capacity of the plant is
approximately 60 million gallons per year.

In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional seven percent interest
in Explorer Pipeline Company (“Explorer”) for $77 million, bringing our ownership interest to 25 percent.
Explorer owns approximately 1,900 miles of refined products pipeline from Lake Charles, Louisiana to
Hammond, Indiana.

In November 2013, we agreed with Enbridge Energy Partners L.P. (“Enbridge Energy Partners”) to serve as an
anchor shipper for the Sandpiper pipeline, which will run from Beaver Lodge, North Dakota to Superior,
Wisconsin. We also agreed to fund 37.5 percent of the construction of the Sandpiper pipeline project, which is
currently estimated to cost $2.6 billion, of which approximately $1.0 billion is our share. We made contributions
of $71 million during 2015 and have contributed $287 million since project inception, which are included in our
Midstream segment. In exchange for our commitment to be an anchor shipper and our investment in the project,
we will earn an approximate 27 percent equity interest in Enbridge Energy Partners’ North Dakota System when
the Sandpiper pipeline is placed into service. The anticipated in-service date for the pipeline is likely to be
delayed to early 2019. The project schedule and cost estimates remain under review. Enbridge Energy Partners’
North Dakota System currently includes approximately 240 miles of crude oil gathering pipelines connected to a
transportation pipeline that is approximately 730 miles long. We will also have the option to increase our
ownership interest to approximately 30 percent through additional investments in future system improvements.

On August 1, 2013, we acquired from Mitsui & Co. (U.S.A.), Inc. its interests in three ethanol companies for $75
million. Under the purchase agreement, we acquired an additional 24 percent interest in The Andersons Clymers
Ethanol LLC (“TACE”), bringing our ownership interest to 60 percent; a 34 percent interest in The Andersons
Ethanol Investment LLC (“TAEI”), which holds a 50 percent ownership in The Andersons Marathon Ethanol
LLC (“TAME”), bringing our direct and indirect ownership interest in TAME to 67 percent; and a 40 percent
interest in The Andersons Albion Ethanol LLC (“TAAE”), which owns an ethanol production facility in Albion,
Michigan. On October 1, 2013, our ownership interest in TAAE increased to 43 percent as a result of TAAE
acquiring one of the owner’s interest.

On February 1, 2013, we acquired from BP Products North America Inc. and BP Pipelines (North America) Inc.
(collectively, “BP”) the 451,000 barrel per calendar day refinery in Texas City, Texas, three intrastate natural gas
liquid pipelines originating at the refinery, four light product terminals, branded-jobber marketing contract
assignments for the supply of approximately 1,200 branded sites, a 1,040 megawatt electric cogeneration facility
and a 50 mbpd allocation of space on the Colonial Pipeline. We refer to these assets as the “Galveston Bay
Refinery and Related Assets.” We paid $1.49 billion for these assets, which included $935 million for inventory.
Pursuant to the purchase and sale agreement, we may also be required to pay BP a contingent earnout of up to an
additional $700 million over six years, subject to certain conditions. Through the end of 2015, we have paid BP
$369 million pursuant to the contingent earnout provisions of the agreement. The Galveston Bay Refinery and
Related Assets are part of our Refining & Marketing and Midstream segments.

See Item 8. Financial Statements and Supplementary Data – Note 5 for additional
information on these
acquisitions and investments. See Item 8. Financial Statements and Supplementary Data – Note 25 for
information regarding our future contributions to the Sandpiper pipeline project.

MPLX LP

ownership interest in MPLX was 20.4 percent, including our two percent general partner interest. Due to our
general partner interest, we have determined that we control MPLX and therefore we consolidate MPLX and
record a noncontrolling interest for the 79.6 percent interest owned by the public.

Upon completion of the MarkWest Merger, MPLX assumed an aggregate principal amount of $4.1 billion in
senior notes issued by MarkWest and MarkWest Energy Finance Corporation (the “MarkWest Senior Notes”).
On December 22, 2015, MPLX completed offers to exchange any and all outstanding MarkWest Senior Notes
for (1) up to $4.1 billion aggregate principal amount of new notes issued by MPLX having the same maturity and
interest rates as the MarkWest Senior Notes and (2) cash of $1 for each $1,000 of principal amount exchanged.
As of December 31, 2015, the exchange was completed on all the MarkWest Senior Notes except for 1.6 percent,
or $63 million.

MPLX’s initial assets consisted of a 51 percent general partner interest in MPLX Pipe Line Holdings LLC (“Pipe
Line Holdings”), which owns a network of common carrier crude oil and product pipeline systems and associated
storage assets in the Midwest and Gulf Coast regions of the United States, and a 100 percent interest in a butane
storage cavern in West Virginia. We originally retained a 49 percent limited partner interest in Pipe Line
Holdings.

On May 1, 2013, we sold a five percent interest in Pipe Line Holdings to MPLX for $100 million, which was
financed by MPLX with cash on-hand.

On March 1, 2014, we sold a 13 percent interest in Pipe Line Holdings to MPLX for $310 million. MPLX
financed this transaction with $40 million of cash on-hand and $270 million of borrowings on its bank revolving
credit facility.

On December 1, 2014, we sold and contributed interests in Pipe Line Holdings totaling 30.5 percent to MPLX for
$600 million in cash and 2.9 million MPLX common units valued at $200 million. MPLX financed the sales
portion of this transaction with $600 million of borrowings on its bank revolving credit facility.

On December 8, 2014, MPLX completed a public offering of 3.5 million common units at a price to the public of
$66.68 per MPLX common unit, with net proceeds of $221 million. MPLX used the net proceeds from this
offering to repay borrowings under its bank revolving credit facility and for general partnership purposes. On
December 10, 2014, we exercised our right to maintain our two percent general partner interest in MPLX by
purchasing 130 thousand general partner units for $9 million.

On February 12, 2015, MPLX completed an underwritten public offering of $500 million aggregate principal
amount of four percent unsecured senior notes due February 15, 2025 (the “Senior Notes”). The Senior Notes
were offered at a price to the public of 99.64 percent of par. The net proceeds of this offering were used to repay
the amounts outstanding under its bank revolving credit facility, as well as for general partnership purposes.

On December 4, 2015, we sold our remaining 0.5 percent interest in Pipe Line Holdings to MPLX for $12
million. As a result, MPLX now owns 100 percent of Pipe Line Holdings.

See Item 8. Financial Statements and Supplementary Data – Note 4 for additional information on MPLX.

Our Competitive Strengths

High Quality Refining, Gathering and Processing Assets

We believe we are the largest crude oil refiner in the Midwest and the fourth largest in the United States based on
crude oil refining capacity. We own a seven-plant refinery network, with approximately 1.8 mmbpcd of crude oil
throughput capacity. Our refineries process a wide range of crude oils, feedstocks and condensate, including

heavy and sour crude oils, which can generally be purchased at a discount to sweet crude oil, and produce
transportation fuels such as gasoline and distillates, specialty chemicals and other refined products. While we
have historically processed significant quantities of heavy and sour crude oils, our refineries have the ability to
process approximately 65 percent to 70 percent light sweet crude oils.

Strategic Locations

The geographic locations of our refineries provide us with strategic advantages. Located in PADD II and PADD
III, which consist of states in the Midwest and the Gulf Coast regions of the United States, our refineries have the
ability to procure crude oil from a variety of supply sources, including domestic, Canadian and other foreign
sources, which provides us with flexibility to optimize crude supply costs. For example, geographic proximity to
various United States shale oil regions and Canadian crude oil supply sources allows our refineries access to
price-advantaged crude oils and lower transportation costs than certain of our competitors. Our refinery locations
and midstream distribution system also allow us to access refined product export markets and to serve a broad
range of key end-user markets across the United States quickly and cost-effectively.

Our Midstream segment assets are similarly located in the Midwest and Gulf Coast regions of the United States,
which collectively comprised approximately 73 percent of total United States crude distillation capacity and
approximately 53 percent of total United States finished products demand for the year ended December 31, 2015,
according to the EIA. MPLX, through MarkWest, its wholly-owned subsidiary, is the largest processor and
fractionator in the Marcellus and Utica shale regions. This significantly compliments and creates strategic
opportunities for our Refining & Marketing segment and MPLX’s logistic assets in the same geographic
footprint.

* As of December 31, 2015

Extensive Midstream Distribution Networks

Our assets give us extensive flexibility and optionality to respond promptly to dynamic market conditions,
including weather-related and marketplace disruptions. We believe the relative scale of our transportation and
distribution assets and operations distinguishes us from other refining and marketing companies. We currently
own, lease or have ownership interests in approximately 8,400 miles of crude oil and products pipelines.
Additionally, we have over 5,000 miles of natural gas and NGL pipelines. We also own one of the largest private
domestic fleets of inland petroleum product barges and one of the largest terminal operations in the United
States, as well as trucking and rail assets. We operate this system in coordination with our refining and marketing
network, which enables us to optimize feedstock and other raw material supplies and refined product distribution,
and further allows for important economies of scale across our system.

General Partner and Sponsor of MPLX

Our investment in MPLX should allow us to enhance our share price through our limited partner and general
partner interests which tend to receive higher market multiples. MPLX also provides us an efficient vehicle to
invest in organic projects and pursue acquisitions of midstream assets. MPLX’s liquidity and access to the capital
markets should provide us a strong foundation to execute our strategy for growing our midstream business. Our
role as the general partner allows us to maintain strategic control of the assets so we can continue to optimize our
refinery feedstock and distribution networks.

We have an extensive portfolio of midstream assets that can potentially be sold and/or contributed to MPLX at
valuations that are supportive to the partnership’s growth, providing MPLX with a competitive advantage. As of
December 31, 2015, these assets included:

•

approximately 5,400 miles of crude oil and products pipelines that MPC owns, leases or which it has an
ownership interest;

ownership interest in SAX pipeline;

19 owned or leased inland towboats and 219 owned or leased inland barges;

ownership interest in a blue water joint venture with Crowley Maritime Corporation;

61 owned and operated light product terminals with approximately 20 million barrels of storage
capacity and 187 loading lanes;

18 owned and operated asphalt terminals with approximately 4 million barrels of storage capacity and
68 loading lanes;

one leased and two non-operated, partially-owned light product terminals;

2,210 owned or leased railcars;

59 million barrels of tank and cavern storage capacity at our refineries;

25 rail and 26 truck loading racks at our refineries;

seven owned and 11 non-owned docks at our refineries;

condensate splitters at our Canton and Catlettsburg refineries; and

approximately 20 billion gallons of fuels distribution.

We continue to focus resources on growing this portfolio of midstream assets, including investments in the
Sandpiper pipeline project, the recently completed SAX pipeline and our new marine joint venture, Crowley
Ocean Partners. We broadly estimate these assets and growth projects can generate annual EBITDA of $1.6
billion. In addition to this growing portfolio by which we can also incubate projects for MPLX, we also have the
ability to provide additional financial flexibility to the partnership through intercompany debt and equity
financing, commercial arrangements, IDR give-backs and other alternatives. See Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations for additional information on these
midstream assets.

Competitively Positioned Marketing Operations

We are one of the largest wholesale suppliers of gasoline and distillates to resellers within our market area. We
have two strong retail brands: Speedway® and Marathon®. We believe Speedway LLC, a wholly-owned
subsidiary, operates the second largest chain of company-owned and operated retail gasoline and convenience
stores in the United States, with approximately 2,770 convenience stores in 22 states throughout the Midwest,
East Coast and Southeast. The Marathon brand is an established motor fuel brand primarily in the Midwest and
Southeast regions of the United States, comprised of approximately 5,600 retail outlets operated by independent
entrepreneurs in 19 states as of December 31, 2015. In addition, as part of the acquisition of the Galveston Bay
Refinery and Related Assets in 2013 and Hess’ Retail Operations and Related Assets in 2014, we obtained retail
marketing contracts that provide us with the opportunity to convert the associated retail outlets to the Marathon
brand. As of December 31, 2015, we had outstanding retail marketing contract assignments for approximately
300 retail outlets. We believe our distribution system allows us to maximize the sales value of our products and
minimize cost.

Attractive Growth Opportunities

We believe we have attractive growth opportunities across all of our business segments.

We recently announced a $2 billion multi-year project we are undertaking in our Refining & Marketing segment
which will fully integrate our Galveston Bay and Texas City refineries, increase residual oil processing, revamp a
crude unit to increase our overall crude processing capacity, increase our distillate and gas oil recovery, improve
the unit’s reliability and install a new ULSD hydrotreater allowing the refinery to produce 100% ULSD and
ULSK. We refer to this group of projects as the South Texas Asset Repositioning (“STAR”) program. Our
Refining & Marketing segment is also investing in the midstream through our ocean vessel equity affiliate, which
is constructing additional Jones Act product tankers to move finished products from our refineries to the coastal
market.

Our Speedway segment is focused on store remodels to enhance profitability, particularly for its acquired stores
along the East Coast, building new locations in Speedway’s core market and fully integrating Hess’ Retail
Operations and Related Assets.

MPLX, which is included in the Midstream segment, is focused on organic growth opportunities for natural gas
gathering and processing and NGL gathering and fractionation in the Marcellus and Utica shale formations
among other regions. MPLX also remains focused on the Cornerstone pipeline project and related Utica build out
projects. The Cornerstone project is the building block for the other projects that will become a critical solution
for the industry to move condensate and NGLs out of the Utica region into refining centers in northwest Ohio and
into Canada. Our Midstream segment’s investments also include an investment in an equity interest in the
Sandpiper pipeline project that will transport crude oil from growing North American hydrocarbon production
regions to our refineries.

In connection with the MarkWest Merger, we have also identified a portfolio of potential projects totaling $6
billion to $9 billion of incremental investment opportunities for our Midstream segment over the next several
years. These investment opportunities are in the early stages of feasibility analysis and include projects in the
Utica and Marcellus shale regions that could leverage our respective capabilities and pursue natural commercial
synergies and transportation solutions to open new markets for producers’ products in these shale regions.

Established Track Record of Profitability and Diversified Income Stream

We have demonstrated an ability to achieve positive financial results throughout all stages of the refining cycle.
We believe our business mix and strategies position us well to continue to achieve competitive financial results.
Income generated by our Speedway segment, which was significantly expanded with the acquisition of Hess’
Retail Operations and Related Assets, is less sensitive to business cycles and income from our Midstream
segment, which was significantly expanded through the MarkWest Merger, is more stable due to its long-term
fee based contracts, while our Refining & Marketing segment enables us to generate significant income and cash
flow when market conditions are more favorable.

Strong Financial Position

As of December 31, 2015, we had $1.13 billion in cash and cash equivalents and $3.17 billion in unused
committed borrowing facilities, excluding MPLX’s credit facilities. We had $11.93 billion of debt at year-end,
which represented 38 percent of our total capitalization. This combination of strong liquidity and manageable
leverage provides financial flexibility to fund our growth projects and to pursue our business strategies.

Our Business Strategies

Maintain Top-Tier Safety and Environmental Performance

We remain committed to operating our assets in a safe and reliable manner and targeting continuous
improvement in our safety record across all of our operations. We have a history of safe and reliable operations,
which was demonstrated again in 2015 with a solid performance compared to the industry average. Four of our
refineries and five additional facilities have earned designation as an OSHA VPP Star site. In addition, we remain
committed to environmental stewardship by continuing to improve the efficiency and reliability of our
operations. We proactively address our regulatory requirements and encourage our operations to improve their
environmental performance through our DEI program. The results of the 2015 DEI program show a 16 percent
reduction over 2014 in regards to significant environmental incidents across MPC, which includes our major
operating components.

Grow Higher Valued, Stable Cash Flow Businesses

We intend to continue allocating significant capital to grow our midstream and retail businesses, exclusive of
acquisitions. These businesses typically have more predictable and stable income and cash flows compared to our
refining operations and we believe investors assign a higher value to businesses with stable cash flows.

MPLX is an important part of the MPC strategy to grow its higher valued, stable cash flow midstream businesses
and the MarkWest Merger significantly expanded its midstream activities to include natural gas gathering,
processing and transportation and NGL gathering, transportation, fractionation, storage and marketing. MPLX
will evaluate organic growth projects within its geographic footprint, including the Marcellus and Utica shale
regions, Oklahoma and Texas, as well as in new areas, that provide attractive returns and cash flows. MPLX may
pursue these opportunities as standalone projects, with MPC or other parties.

We significantly expanded Speedway’s presence along the East Coast and Southeast through our acquisition of
Hess’ Retail Operations and Related Assets towards the end of 2014. We intend to continue growing Speedway’s
sales and profitability by focusing on the conversion and integration of these acquired locations, from which we
expect to realize increased merchandise sales and other synergies. We also remain focused on organic growth
through remodeling stores, constructing new stores, rebuilding old stores, acquiring high quality stores through
opportunistic acquisitions and improving margins at our existing operations. We have identified numerous
opportunities for new convenience stores or store rebuilds in our existing market, Pennsylvania and Tennessee, as
well as growth opportunities in Georgia, South Carolina and the Florida panhandle. We also plan to capitalize on
diesel demand growth by building out our commercial fueling lane network. In addition, our highly successful
Speedy Rewards® customer loyalty program, which averaged more than 4.7 million active members in 2015,
provides us with a unique competitive advantage and opportunity to increase our Speedway customer base with
existing and new Speedway locations, including the stores acquired from Hess.

Maintain Long-Term Integrated Relationships with Our Producer Customers

MPLX’s MarkWest subsidiary has developed long-term integrated relationships with its producer customers.
These relationships are characterized by an intense focus on customer service and a deep understanding of
producer customers’ requirements coupled with the ability to increase the level of our midstream services in
response to their midstream requirements. Through collaborative planning, MPLX continues to construct high-
quality midstream infrastructure and provide unique solutions that are critical to the ongoing success of producer
customers’ development plans. As a result of delivering high-quality midstream services, MarkWest has been the
top-rated midstream service provider since 2006, as determined by an independent research provider.

Deliver Top Quartile Refining Performance

Our refineries are well positioned to benefit from the growing crude oil and condensate production in North
America, including the Bakken, Eagle Ford and Utica shale regions, along with the Canadian oil sands. We are
also well positioned to export distillates, gasoline and other products.

We intend to enhance our margins in the Refining & Marketing segment by realizing benefits of continuous
process improvements, investing in and optimizing operations at our Galveston Bay and Texas City refineries,
increasing distillate yield and conversion capacity and growing refined product export capacity. For example, we
completed condensate splitter projects at our Canton and Catlettsburg refineries to increase our condensate
capacity, we increased distillate production at our Galveston Bay and Robinson refineries and expanded our
export capacity at our Galveston Bay and Garyville refineries. We intend to create a world-class refining
complex by investing $2 billion in our Galveston Bay refinery over the next five years. The group of projects
included in this investment will enable us to produce 100 percent ULSD and ULSK, increase our overall crude
increase our distillate and gas oil recovery and improve the refinery’s reliability.
processing capacity,
Furthermore, this investment program will fully integrate our Galveston Bay and Texas City refineries. In 2016,
we intend to increase our capacity to produce high value products such as alkylate and light products by making
investments in the FCC units at our Garyville and Detroit refineries. We also intend to further increase distillate
production at our Garyville refinery and to further expand the export capacity at our Galveston Bay refinery.

Sustain Focus on Shareholder Returns

We intend to continue our focus on the return of capital to shareholders in the form of a strong and growing base
dividend, supplemented by share repurchases. Since becoming a stand-alone company in June 2011, our dividend
has increased by a 29.5 percent compound annual growth rate and our board of directors has authorized share
repurchases totaling $10 billion. Through open market purchases and two ASR programs, we repurchased
198 million shares of our common stock for approximately $7.24 billion, representing approximately 28 percent
of our outstanding common shares when we became a stand-alone company in June 2011. After the effects of
these repurchases, $2.76 billion of the $10 billion total authorization was available for future repurchases as of
December 31, 2015.

Increase Assured Sales Volumes at our Marathon Brand and Speedway Locations

We consider assured sales as those sales we make to Marathon brand customers, our Speedway operations and to
our wholesale customers with whom we have required minimum volume sales contracts. We believe having
assured sales brings ratability to our distribution systems, provides a solid base to enhance our overall supply
reliability and allows us to efficiently and effectively optimize our operations between our refineries, pipelines
and terminals. The Marathon brand has been a vehicle for sales volume growth in existing and contiguous
markets. Our Speedway operations have also enabled us to further leverage our integrated refining and
transportation operations with its expansion from nine to 22 states throughout the East Coast and Southeast in
2014.

Utilize and Enhance our High Quality Employee Workforce

We utilize our high quality employee workforce, which was augmented with the addition of MarkWest’s
employees to MPC, by continuing to leverage our commercial skills. In addition, we continue to enhance our
workforce through selective hiring practices and effective training programs on safety, environmental
stewardship and other professional and technical skills.

The above discussion contains forward-looking statements with respect to our competitive strengths and business
strategies, including our expected investments, the adequacy of our capital resources and liquidity and MPLX’s
access to capital markets, share repurchase authorizations, growth opportunities as well as the earnings potential
of our portfolio of midstream assets and growth projects that can potentially be sold and/or contributed to MPLX.
There can be no assurance that we will be successful, in whole or in part, in carrying out our business strategies,
including our expected investments, share repurchase authorizations and other growth opportunities, or that our
portfolio of midstream assets and growth projects that can potentially be sold and/or contributed to MPLX will
achieve expected earnings. Factors that could affect our expected investments include, but are not limited to, the
actual amounts invested, which could differ materially from those estimated, and our success in making such
investments. Factors that could affect the share repurchase authorizations and the timing of any repurchases

include, but are not limited to, business conditions, availability of liquidity and the market price of our common
stock. Factors that could affect the pursuit of growth opportunities include, but are not limited to, our ability to
implement and realize the benefits and synergies of our strategic initiatives, availability of liquidity, actions taken
by competitors, regulatory approvals and operating performance. Factors that could affect the earnings of our
portfolio of midstream assets and growth projects that can potentially be sold and/or contributed to MPLX
include, but are not limited to, the timing and extent of changes in commodity prices and demand for crude oil,
refined products, feedstocks or other hydrocarbon-based products and volatility in and/or degradation of market
and industry conditions. Factors that could affect the adequacy of our capital resources and liquidity and MPLX’s
access to capital markets include, but are not limited to, modifications to MPLX earnings and distribution growth
objectives, the risk that synergies from the MarkWest Merger may not be fully realized or may take longer to
realize than expected, failure to realize the benefits projected for capital projects and volatility or degradation in
general economic, market, industry or business conditions. 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.

Refining & Marketing

Refineries

We currently own and operate seven refineries in the Gulf Coast and Midwest regions of the United States with
an aggregate crude oil refining capacity of 1,794 mbpcd. During 2015, our refineries processed 1,711 mbpd of
crude oil and 177 mbpd of other charge and blendstocks. During 2014, our refineries processed 1,622 mbpd of
crude oil and 184 mbpd of other charge and blendstocks. The table below sets forth the location, crude oil
refining capacity, tank storage capacity and number of tanks for each of our refineries as of December 31, 2015.

Refinery

Garyville, Louisiana

Galveston Bay, Texas City, Texas

Catlettsburg, Kentucky

Robinson, Illinois

Detroit, Michigan

Canton, Ohio

Texas City, Texas

Total

Crude Oil Refining
Capacity (mbpcd)(a)

Tank Storage
Capacity
(million barrels)

Number
of Tanks

539

459

273

212

132

1,794

16.8

16.3

5.3

6.2

6.5

3.1

4.6

58.8

156

114

665

(a) Refining throughput can exceed crude oil capacity due to the processing of other charge and blendstocks in addition to crude oil and the

timing of planned turnaround and major maintenance activity.

Our refineries include crude oil atmospheric and vacuum distillation, fluid catalytic cracking, hydrocracking,
catalytic reforming, coking, desulfurization and sulfur recovery units. The refineries process a wide variety of
condensate, light and heavy crude oils purchased from various domestic and foreign suppliers. We produce
numerous refined products, ranging from transportation fuels, such as reformulated gasolines, blend-grade
gasolines intended for blending with ethanol and ULSD fuel, to heavy fuel oil and asphalt. Additionally, we
manufacture aromatics, propane, propylene and sulfur. See the Refined Product Marketing section for further
information about the products we produce.

terminals and barges to maximize operating
Our refineries are integrated with each other via pipelines,
efficiency. The transportation links that connect our refineries allow the movement of intermediate products

between refineries to optimize operations, produce higher margin products and efficiently utilize our processing
capacity. For example, naphtha may be moved from Texas City to Robinson where excess reforming capacity is
available. Also, shipping intermediate products between facilities during partial refinery shutdowns allows us to
utilize processing capacity that is not directly affected by the shutdown work.

Garyville, Louisiana Refinery. Our Garyville, Louisiana refinery is located along the Mississippi River in
southeastern Louisiana between New Orleans and Baton Rouge. The Garyville refinery is configured to process a
wide variety of crude oils into gasoline, distillates, fuel-grade coke, asphalt, polymer-grade propylene, propane,
slurry, sulfur and dry gas. The refinery has access to the export market and multiple options to sell refined
products. A major expansion project was completed in 2009 that increased Garyville’s crude oil refining
capacity, making it one of the largest refineries in the U.S. Our Garyville refinery has earned designation as an
OSHA VPP Star site.

Galveston Bay, Texas City, Texas Refinery. Our Galveston Bay refinery, which we acquired on February 1, 2013,
is located on the Texas Gulf Coast approximately 30 miles southeast of Houston, Texas. The refinery can process
a wide variety of crude oils into gasoline, distillates, aromatics, heavy fuel oil, fuel-grade coke, refinery-grade
propylene, sulfur and dry gas. The refinery has access to the export market and multiple options to sell refined
products. Our cogeneration facility, which supplies the Galveston Bay refinery, currently has 1,055 megawatts of
electrical production capacity and can produce 4.3 million pounds of steam per hour. Approximately 46 percent
of the power generated in 2015 was used at the refinery, with the remaining electricity being sold into the
electricity grid.

Catlettsburg, Kentucky Refinery. Our Catlettsburg, Kentucky refinery is located in northeastern Kentucky on the
western bank of the Big Sandy River, near the confluence with the Ohio River. The Catlettsburg refinery
processes sweet and sour crude oils into gasoline, distillates, asphalt, aromatics, refinery-grade propylene and
propane. In the second quarter of 2015, we completed construction of a condensate splitter at our Catlettsburg
refinery, which increased our capacity to process condensate from the Utica shale region.

Robinson, Illinois Refinery. Our Robinson, Illinois refinery is located in southeastern Illinois. The Robinson
refinery processes sweet and sour crude oils into gasoline, distillates, propane, anode-grade coke, aromatics and
slurry. The Robinson refinery has earned designation as an OSHA VPP Star site.

Detroit, Michigan Refinery. Our Detroit, Michigan refinery is located in southwest Detroit. It is the only
petroleum refinery currently operating in Michigan. The Detroit refinery processes sweet and heavy sour crude
oils into gasoline, distillates, asphalt, fuel-grade coke, chemical-grade propylene, propane, slurry and sulfur. Our
Detroit refinery earned designation as a OSHA VPP Star site in 2010. In the fourth quarter of 2012, we
completed a heavy oil upgrading and expansion project that enabled the refinery to process up to an additional 80
mbpd of heavy sour crude oils, including Canadian crude oils.

Canton, Ohio Refinery. Our Canton, Ohio refinery is located approximately 60 miles south of Cleveland, Ohio.
The Canton refinery processes sweet and sour crude oils, including production from the nearby Utica Shale, into
gasoline, distillates, asphalt, roofing flux, refinery-grade propylene, propane and slurry. In December 2014, we
completed construction of a condensate splitter at our Canton refinery, which increased our capacity to process
condensate from the Utica shale region.

Texas City, Texas Refinery. Our Texas City, Texas refinery is located on the Texas Gulf Coast adjacent to our
Galveston Bay refinery, approximately 30 miles southeast of Houston, Texas. The refinery processes light sweet
crude oils into gasoline, chemical-grade propylene, propane, aromatics, slurry and dry gas. Our Texas City
refinery earned designation as an OSHA VPP Star site in 2012.

As of December 31, 2015, our refineries had 25 rail loading racks and 26 truck loading racks and four of our
refineries had a total of seven owned and 11 non-owned docks. Total throughput in 2015 was 88 mbpd for the
refinery loading racks and 920 mbpd for the refinery docks.

Planned maintenance activities, or turnarounds, requiring temporary shutdown of certain refinery operating units,
are periodically performed at each refinery. See Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations for additional detail.

Refined Product Yields

The following table sets forth our refinery production by product group for each of the last three years.

Refined Product Yields (mbpd)

2015

2014

2013

Gasoline

Distillates

Propane

Feedstocks and special products

Heavy fuel oil

Asphalt

Total

Crude Oil Supply

913

603

281

869

580

276

921

572

221

1,919

1,839

1,836

We obtain the crude oil we refine through negotiated term contracts and purchases or exchanges on the spot
market. Our term contracts generally have market-related pricing provisions. The following table provides
information on our sources of crude oil for each of the last three years. The crude oil sourced outside of North
America was acquired from various foreign national oil companies, production companies and trading
companies.

Sources of Crude Oil Refined (mbpd)

2015

2014

2013

United States

Canada

Middle East and other international

Total

1,138

244

329

1,711

1,120

223

279

1,622

946

255

388

1,589

Our refineries receive crude oil and other feedstocks and distribute our refined products through a variety of
channels, including pipelines, trucks, railcars, ships and barges.

Renewable Fuels

We currently own a biofuel production facility in Cincinnati, Ohio that produces biodiesel, glycerin and other by-
products. The capacity of the plant is approximately 60 million gallons per year.

We hold interests in ethanol production facilities in Albion, Michigan; Clymers, Indiana and Greenville, Ohio.
These plants have a combined ethanol production capacity of 275 million gallons per year (18 mbpd) and are
managed by a co-owner.

Refined Product Marketing

We believe we are one of the largest wholesale suppliers of gasoline and distillates to resellers and consumers
within our 19-state market area. Independent retailers, wholesale customers, our Marathon brand jobbers and
Speedway brand convenience stores, airlines, transportation companies and utilities comprise the core of our

customer base. In addition, we sell gasoline, distillates and asphalt for export, primarily out of our Garyville and
Galveston Bay refineries. The following table sets forth our refined product sales destined for export by product
group for the past three years.

Refined Product Sales Destined for Export (mbpd)

2015

2014

2013

Gasoline

Distillates

Asphalt

Other

Total

101

214

191

173

319

275

218

The following table sets forth, as a percentage of total refined product sales volume, the sales of refined products
to our different customer types for the past three years.

Refined Product Sales by Customer Type

Private-brand marketers, commercial and industrial customers, including spot market

Marathon-branded independent entrepreneurs

Speedway® convenience stores

2015

2014

2013

69%

14%

17%

73%

15%

12%

75%

16%

The following table sets forth the approximate number of retail outlets by state where independent entrepreneurs
maintain Marathon-branded retail outlets, as of December 31, 2015.

State

Alabama

Florida

Georgia

Illinois

Indiana

Kentucky

Louisiana

Maryland

Michigan

Minnesota

Mississippi

North Carolina

Ohio

Pennsylvania

South Carolina

Tennessee

Virginia

West Virginia

Wisconsin

Total

Approximate Number of
Marathon® Retail Outlets

237

632

311

314

646

578

753

292

848

133

362

130

119

5,607

As of December 31, 2015, we also had branded marketing contract assignments for retail outlets, primarily in
Florida, Mississippi, Tennessee and Alabama and branded lessee dealer marketing contract assignments,
primarily in Connecticut, Maryland and New York, which we acquired as either part of the Galveston Bay
Refinery and Related Assets acquisition in 2013 or the acquisition of Hess’ Retail Operations and Related Assets
in 2014. As of December 31, 2015, we had outstanding retail marketing contract assignments for approximately
300 retail outlets.

The following table sets forth our refined product sales volumes by product group for each of the last three years.

Refined Product Sales by Product Group (mbpd)

2015

2014

2013

Gasoline

Distillates

Propane

Feedstocks and special products

Heavy fuel oil

Asphalt

Total

1,241

1,116

1,126

667

258

623

268

615

214

2,289

2,125

2,075

Gasoline and Distillates. We sell gasoline, gasoline blendstocks and distillates (including No. 1 and No. 2 fuel
oils, jet fuel, kerosene and diesel fuel) to wholesale customers, Marathon-branded independent entrepreneurs and
our Speedway® convenience stores and on the spot market. In addition, we sell diesel fuel and gasoline for export
to international customers. We sold 50 percent of our gasoline sales volumes and 87 percent of our distillates
sales volumes on a wholesale or spot market basis in 2015. The demand for gasoline and distillates is seasonal in
many of our markets, with demand typically at its highest levels during the summer months.

We have blended ethanol into gasoline for more than 20 years and began expanding our blending program in
2007, in part due to federal regulations that require us to use specified volumes of renewable fuels. Ethanol
volumes sold in blended gasoline were 85 mbpd in 2015, 78 mbpd in 2014 and 74 mbpd in 2013. We sell
reformulated gasoline, which is also blended with ethanol, in 12 states in our marketing area. We also sell
biodiesel-blended diesel fuel in 16 states in our marketing area. The future expansion or contraction of our
ethanol and biodiesel blending programs will be driven by market economics and government regulations.

Propane. We produce propane at most of our refineries. Propane is primarily used for home heating and cooking,
as a feedstock within the petrochemical industry, for grain drying and as a fuel for trucks and other vehicles. Our
propane sales are typically split evenly between the home heating market and industrial consumers.

Feedstocks and Special Products. We are a producer and marketer of feedstocks and specialty products. Product
availability varies by refinery and includes platformate, alkylate, FCC unit gas, naptha, dry gas, propylene,
raffinate, butane, benzene, xylene, molten sulfur, cumene and toluene. We market these products domestically to
customers in the chemical, agricultural and fuel-blending industries. In addition, we produce fuel-grade coke at
our Garyville, Detroit and Galveston Bay refineries, which is used for power generation and in miscellaneous
industrial applications, and anode-grade coke at our Robinson refinery, which is used to make carbon anodes for
the aluminum smelting industry. Our feedstocks and special products sales decreased to 258 mbpd in 2015 from
268 mbpd in 2014 and increased in 2014 from 214 mbpd in 2013. The decrease in 2015 was primarily due to
higher turnaround activity in 2014 resulting in more available feedstocks, more feedstocks used in production
versus selling them on the spot market and market conditions in 2015. The increase in 2014 was primarily due to
our Galveston Bay refinery.

Heavy Fuel Oil. We produce and market heavy residual fuel oil or related components, including slurry, at all of
our refineries. Heavy residual fuel oil is primarily used in the utility and ship bunkering (fuel) industries, though
there are other more specialized uses of the product.

Asphalt. We have refinery-based asphalt production capacity of up to 101 mbpcd, which includes asphalt
cements, polymer-modified asphalt, emulsified asphalt, industrial asphalts and roofing flux. We have a broad
customer base, including asphalt-paving contractors, government entities (states, counties, cities and townships)
and asphalt roofing shingle manufacturers. We sell asphalt in the domestic and export wholesale markets via rail,
barge and vessel.

Terminals

As of December 31, 2015, we owned and operated 61 light product and 18 asphalt terminals. Our light product
and asphalt terminals averaged 1,410 mbpd and 32 mbpd of throughput in 2015, respectively. In addition, we
distribute refined products through one leased light product terminal, two light product terminals in which we
have partial ownership interests but do not operate and approximately 120 third-party light product and two third-
party asphalt terminals in our market area. The following table sets forth additional details about our owned and
operated terminals at December 31, 2015.

Owned and Operated Terminals

Light Product Terminals:

Number of
Terminals

Tank Storage
Capacity
(million barrels)

Number
of Tanks

Number of
Loading
Lanes

Alabama

Florida

Georgia

Illinois

Indiana

Kentucky

Louisiana

Michigan

North Carolina

Ohio

Pennsylvania

South Carolina

Tennessee

West Virginia

Wisconsin

Subtotal light product terminals

Asphalt Terminals:

Florida

Illinois

Indiana

Kentucky

Louisiana

Michigan

Ohio

Pennsylvania

Tennessee

Subtotal asphalt terminals

Total owned and operated terminals

0.4

2.6

0.9

1.1

2.9

2.3

0.1

2.1

1.2

3.8

0.3

1.0

0.3

150

19.6

714

187

0.2

0.1

0.5

0.1

2.0

0.5

4.4

24.0

270

984

255

Transportation – Marine, Truck and Rail

As of December 31, 2015, our marine transportation operations included 18 owned and one leased towboat, as
well as 205 owned and 14 leased barges that transport refined products and crude oil on the Ohio, Mississippi
and Illinois rivers and their tributaries and inter-coastal waterways. We also have a 50 percent ownership interest
in a joint venture with Crowley Maritime Corporation through our investment in Crowley Ocean Partners to
operate and charter four new Jones Act product tankers, most of which will be leased to MPC. As of
December 31, 2015, two of the four vessels were delivered with the remaining two vessels expected to be
delivered by the third quarter of 2016. The following table sets forth additional details about our tankers, barges
and towboats.

Class of Equipment

Jones Act product tankers(a)

Inland tank barges:(b)

Less than 25,000 barrels

25,000 barrels and over

Total

Inland towboats:

Less than 2,000 horsepower

2,000 horsepower and over

Total

Number
in Class

Capacity
(thousand barrels)

660

995

4,453

5,448

152

219

(a) Represents ownership through our investment in Crowley Ocean Partners.
(b) All of our barges are double-hulled.

As of December 31, 2015, we owned 173 transport trucks and 174 trailers with an aggregate capacity of
1.6 million gallons for the movement of refined products and crude oil. In addition, we had 2,189 leased and 21
owned railcars of various sizes and capacities for movement and storage of refined products. The following table
sets forth additional details about our railcars.

Class of Equipment

General service tank cars

High pressure tank cars

Open-top hoppers

Speedway

Number of Railcars

Owned

Leased

Total

Capacity per Railcar

793

1,102

294

2,189

793

1,102

315

2,210

20,000-30,000 gallons

33,500 gallons

4,000 cubic feet

Our Speedway segment sells gasoline, diesel and merchandise through convenience stores that it owns and
operates under the Speedway brand. We are substantially complete with the conversion of the remaining
convenience stores acquired from Hess to the Speedway brand and plan to complete this process by the end of
the second quarter of 2016. Speedway convenience stores offer a wide variety of merchandise, including
prepared foods, beverages and non-food items. Speedway’s Speedy Rewards® loyalty program has been a highly
successful loyalty program since its inception in 2004, with a consistently growing base which averaged more
than 4.7 million active members in 2015. Due to Speedway’s ability to capture and analyze member-specific
transactional data, Speedway is able to offer the Speedy Rewards® members discounts and promotions specific to
their buying behavior. We believe Speedy Rewards® is a key reason customers choose Speedway over
competitors and it continues to drive significant value for both Speedway and our Speedy Rewards® members.

The demand for gasoline is seasonal, with the highest demand usually occurring during the summer driving
season. Margins from the sale of merchandise tend to be less volatile than margins from the retail sale of gasoline
and diesel fuel. Merchandise margin as a percent of total gross margin for Speedway decreased in 2015,
primarily due to higher light product margins during the year and the effects of the convenience stores acquired
from Hess. The following table sets forth Speedway merchandise statistics for the past three years.

Speedway Merchandise Statistics

Merchandise sales (in millions)

Merchandise gross margin (in millions)

Merchandise as a percent of total gross margin

2015

2014

2013

$ 4,879

$ 3,611

$ 3,135

1,368

54%

975

57%

825

65%

As of December 31, 2015, Speedway had 2,766 convenience stores in 22 states. The following table sets forth the
number of convenience stores by state owned by our Speedway segment as of December 31, 2015.

State

Alabama

Connecticut

Delaware

Florida

Georgia

Illinois

Indiana

Kentucky

Massachusetts

Michigan

New Hampshire

New Jersey

New York

North Carolina

Ohio

Pennsylvania

Rhode Island

South Carolina

Tennessee

Virginia

West Virginia

Wisconsin

Total

Number of
Convenience Stores(a)

247

110

308

147

114

303

240

288

489

111

2,766

(a)

Includes travel centers and stores with commercial fueling lanes.

As of December 31, 2015, Speedway owned 105 transport trucks and 83 trailers for the movement of gasoline
and distillate.

Midstream

Following the MarkWest Merger, we changed the name of our Pipeline Transportation segment to the Midstream
segment to reflect its expanded business activities. The Midstream segment includes the operations of MPLX,
which transports crude oil and other feedstocks to our refineries and other locations, delivers refined products to
wholesale and retail market areas, gathers, processes and transports natural gas, and transports, fractionates,
stores and markets NGLs. As of December 31, 2015, we owned,
leased or had ownership interests in
approximately 8,400 miles of crude oil and products pipelines, of which approximately 2,900 miles are owned
through our investments in MPLX. Also through our investments in MPLX, we own 5,000 miles of gas gathering
and NGL pipelines and have ownership interests in over 50 gas processing plants, over 10 NGL fractionation
facilities and one condensate stabilization facility.

MPLX

MPLX is a publicly traded master limited partnership formed by us to own, operate, develop and acquire
pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and
other hydrocarbon-based products. On December 4, 2015, MPLX merged with MarkWest, whereby MarkWest
became a wholly-owned subsidiary of MPLX. Prior to the MarkWest Merger, we owned a 71.5 percent interest
in MPLX, which included our two percent general partner interest. As of December 31, 2015, our ownership
interest in MPLX was 20.4 percent, including our two percent general partner interest.

As of December 31, 2015, MPLX assets, through its combination with MarkWest, included approximately 5,400
MMcf/d of gathering capacity, 7,100 MMcf/d of natural gas processing capacity and 500 mbpd of NGL
fractionation capacity and more than 5,000 miles of gas gathering and NGL pipelines.

MPLX assets as of December 31, 2015 also included 100 percent ownership of common carrier pipeline systems
through Marathon Pipe Line LLC (“MPL”) and Ohio River Pipe Line LLC (“ORPL”), and a one million barrel
butane storage cavern in West Virginia. MPLX, through MPL and ORPL, owned or leased and operated 1,008
miles of common carrier crude oil lines and 1,900 miles of common carrier products lines located in nine states
and four tank farms in Illinois and Indiana with available storage capacity of 4.53 million barrels that is
committed to MPC. In 2015, third parties generated 17 percent of the crude oil and refined product shipments on
MPLX’s common carrier pipelines, excluding volumes shipped by MPC under joint tariffs with third parties.
These common carrier pipelines transported the volumes shown in the MPLX Pipeline Throughput information
in the table below for each of the last three years.

MPC-Retained Assets and Investments

We retained ownership interests in several crude oil and products pipeline systems and pipeline companies. MPC
consolidated volumes transported through our common carrier pipelines, which include MPLX and our
undivided joint interests, are shown in the MPC Consolidated Pipeline Throughput information in the following
table for each of the last three years.

The following table shows operating statistics for our Midstream segment.

Midstream Operating Statistics

2015

2014

2013

MPC Consolidated Pipeline Throughput (mbpd)

Crude oil pipelines

Refined products pipelines

Total

MPLX Pipeline Throughput (mbpd)(a)(b)

Crude oil pipelines

Refined products pipelines

Total

Gathering system throughput (MMcf/d)(c)

Natural gas processed (MMcf/d)(c)

C2 (ethane) + NGLs fractionated (mbpd)(c)

1,241

878

2,119

1,041

878

1,919

1,293

911

2,204

1,075

911

1,986

1,277

914

2,191

1,061

914

1,975

3,075

5,468

307

(a) MPLX predecessor volumes reported in MPLX’s filings include our undivided joint interest crude oil pipeline systems for periods prior
to MPLX’s initial public offering, which were not contributed to MPLX. The undivided joint interest volumes are not included above.

(b) Volumes represent 100 percent of the throughput through these pipelines.

The locations and detailed information about our midstream assets are included under Item 2. Properties and are
incorporated herein by reference.

Competition, Market Conditions and Seasonality

The downstream petroleum business is highly competitive, particularly with regard to accessing crude oil and
other feedstock supply and the marketing of refined products. We compete with a large number of other
companies to acquire crude oil for refinery processing and in the distribution and marketing of a full array of
petroleum products. Based upon the “The Oil & Gas Journal 2015 Worldwide Refinery Survey,” we ranked
fourth among U.S. petroleum companies on the basis of U.S. crude oil refining capacity as of December 31,
2015. We compete in four distinct markets for the sale of refined products – wholesale, spot, branded and retail
distribution. We believe we compete with about 55 companies in the sale of refined products to wholesale
marketing customers, including private-brand marketers and large commercial and industrial consumers; about
100 companies in the sale of refined products in the spot market; 12 refiners or marketers in the supply of refined
products to refiner-branded independent entrepreneurs; and approximately 890 retailers in the retail sale of
refined products. In addition, we compete with producers and marketers in other industries that supply alternative
forms of energy and fuels to satisfy the requirements of our industrial, commercial and retail consumers. We do
not produce any of the crude oil we refine.

We also face strong competition for sales of retail gasoline, diesel fuel and merchandise. Our competitors include
service stations and convenience stores operated by fully integrated major oil companies and their independent
entrepreneurs and other well-recognized national or regional convenience stores and travel centers, often selling
gasoline, diesel fuel and merchandise at competitive prices. Non-traditional retailers, such as supermarkets, club
stores and mass merchants, have affected the convenience store industry with their entrance into sales of retail
gasoline and diesel fuel. Energy Analysts International, Inc. estimated such retailers had approximately 13
percent of the U.S. gasoline market in mid-2015.

Our Midstream operations face competition for natural gas gathering, crude oil transportation 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 facilities 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. In addition,
certain of our Midstream operations are highly regulated, which affects the rates that our common carrier
pipelines can charge for transportation services and the return we obtain from such pipelines.

Market conditions in the oil and gas industry are cyclical and subject to global economic and political events and
new and changing governmental regulations. Our operating results are affected by price changes in crude oil,
natural gas and refined products, as well as changes in competitive conditions in the markets we serve. Price
differentials between sweet and sour crude oils, WTI and LLS crude oils and other market structure differentials
also affect our operating results.

Demand for gasoline, diesel fuel and asphalt is higher during the spring and summer months than during the
winter months in most of our markets, primarily due to seasonal increases in highway traffic and construction. As
a result, the operating results for each of our segments for the first and fourth quarters may be lower than for
those in the second and third quarters of each calendar year.

Our Midstream 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. In the northeast region, we could be particularly
impacted by seasonality as the majority of its revenues are generated by NGL sales. 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 northeast 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.

Environmental Matters

Our management is responsible for ensuring that our operating organizations maintain environmental compliance
systems that support and foster our compliance with applicable laws and regulations, and for reviewing our
overall environmental performance. We also have a Corporate Emergency Response Team that oversees our
response to any major environmental or other emergency incident involving us or any of our facilities.

We believe it is likely that the scientific and political attention to issues concerning the extent and causes of
climate change will continue, with the potential for further regulations that could affect our operations. Currently,
legislative and regulatory measures to address greenhouse gases are in various phases of review, discussion or
implementation. The cost to comply with these laws and regulations cannot be estimated at this time, but could
be significant. For additional
information, see Item 1A. Risk Factors. We estimate and publicly report
greenhouse gas emissions from our operations and products. Additionally, we continuously strive to improve
operational and energy efficiencies through resource and energy conservation where practicable.

Our operations are subject to numerous other laws and regulations relating to the protection of the environment.
Such laws and regulations include, among others, the Clean Air Act (“CAA”) with respect to air emissions, the
Clean Water Act (“CWA”) with respect to water discharges, the Resource Conservation and Recovery Act
(“RCRA”) with respect to solid and hazardous waste treatment, storage and disposal, the Comprehensive
Environmental Response, Compensation, and Liability Act
to releases and
remediation of hazardous substances and the Oil Pollution Act of 1990 (“OPA-90”) with respect to oil pollution
and response. In addition, many states where we operate have similar laws. New laws are being enacted and
regulations are being adopted on a continuing basis, and the costs of compliance with such new laws and
regulations are very difficult to estimate until finalized.

(“CERCLA”) with respect

For a discussion of environmental capital expenditures and costs of compliance for air, water, solid waste and
remediation, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations-Environmental Matters and Compliance Costs.

Air

We are subject to many requirements in connection with air emissions from our operations. Internationally and
domestically, emphasis has been placed on reducing greenhouse gas emissions. The U.S. pledge in 2009, as part
of the Copenhagen Accord, to reduce greenhouse gas emissions 17 percent below 2005 levels by 2020 remains in
effect and was reaffirmed in the President’s 2013 Climate Action Plan. The 2015 Paris Agreement on Climate
Change does not legally require parties to the Agreement to reduce greenhouse gas emissions, but the United
States’ future activities in response to the Paris Agreement are unknown. In 2009,
the EPA issued an
“endangerment finding” that greenhouse gas emissions contribute to air pollution that endangers public health
and welfare. Related to the endangerment finding, in April 2010, the EPA finalized a greenhouse gas emission
standard for mobile sources (cars and other light duty vehicles). The endangerment finding, the mobile source
standard and the EPA’s determination that greenhouse gases are subject to regulation under the Clean Air Act
resulted in permitting of greenhouse gas emissions at stationary sources, but as a result of the EPA’s “tailoring
rule,” permit applicability was limited to larger sources such as refineries. Legal challenges were filed against
these EPA actions. In June 2014, the United States Supreme Court ruled that the Clean Air Act Prevention of
Significant Deterioration program for new and modified stationary sources is not triggered by greenhouse gas
emissions alone. The United States Supreme Court did, however, uphold the requirement for new or modified
stationary sources that will also emit a criteria pollutant to control greenhouse gas emissions through Best
Available Control Technology. Implementing Best Available Control Technology may result in increased costs
to our operations. A few MPC projects triggered greenhouse gas permitting requirements but any additional
capital spending will likely not be significant.

The EPA has finalized Source Performance Standards for greenhouse gas emissions for new and existing electric
utility generating units. These standards could impact electric and natural gas rates for all our operations. Legal
challenges have been filed by several states and by industry groups seeking to overturn the final rules. Congress
may again also consider legislation on greenhouse gas emissions or a carbon tax. Private parties have sued
utilities and other emitters of greenhouse gas emissions, but such suits have been largely unsuccessful. We have
not been named in any of those lawsuits. Private parties have also sued federal and certain state governmental
entities seeking additional greenhouse gas emission reductions beyond those currently being undertaken. In sum,
requiring reductions in greenhouse gas emissions could result in increased costs to (i) operate and maintain our
facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any greenhouse gas
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. The extent and magnitude of the impact from greenhouse gas regulation or
legislation cannot be reasonably estimated due to the uncertainty regarding the additional measures and how they
will be implemented.

In 2013, the Obama administration made changes to the social cost of carbon (“SCC”) estimate. The SCC was
first issued in 2010. The SCC is to be used by the EPA and other federal agencies in regulatory cost-benefit
analyses to take into account alleged broad economic consequences associated with changes to emissions of
greenhouse gases. In 2013, the Obama administration significantly increased the estimate to $36 per ton. In
response to the regulated community and Congress’ critiques of how the SCC was developed, the Office of
Management and Budget provided an opportunity to comment on the SCC, but ultimately did not make any
significant revisions. In December 2014, the White House Council on Environmental Quality issued new draft
guidance for assessing greenhouse gas emissions under the National Environmental Policy Act, adding for the
first time language that requires the analyses to also include the impact of climate change on projects, including
using the SCC when analyzing costs and benefits of a project. While the impact of a higher SCC in future
regulations is not known at this time, it may result in increased costs to our operations.

In 2015, the EPA finalized a revision to the National Ambient Air Quality Standards (“NAAQS”) for ozone. The
EPA lowered the primary ozone NAAQS from 75 ppb to 70 ppb. This revision initiates a multi-year process in
which nonattainment designations will be made based on more recent ozone measurements that includes data
from 2016. States will then propose and adopt, as necessary, new rules reducing emissions to meet the new
standard. Currently, the EPA is in the process of implementing the 75 ppb ozone standard that the EPA had
promulgated in March 2008. The impact of a stricter standard cannot be accurately estimated due to the present
uncertainty regarding area nonattainment designations and the additional requirements that states may impose.
Additionally, legal petitions challenging the revised ozone standard have been filed with the court adding
uncertainty to the revised standard.

On September 29, 2015, the EPA signed the final regulations revising existing refinery air emissions standards.
The revised regulations were published in the Federal Register on December 1, 2015. The revised rule requires
additional controls, lower emission standards and ambient air monitoring. We do not anticipate that MPC’s costs
to comply with the revised regulations will be material to our results of operations or cash flows.

Water

We maintain numerous discharge permits as required under the National Pollutant Discharge Elimination System
program of the CWA and have implemented systems to oversee our compliance with these permits. In addition,
we are regulated under OPA-90, which among other things, requires the owner or operator of a tank vessel or a
facility to maintain an emergency plan to respond to releases of oil or hazardous substances. 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 have
implemented emergency oil response plans for all of our components and facilities covered by OPA-90 and we
have established Spill Prevention, Control and Countermeasures plans for all facilities subject
to such
requirements.

Additionally, OPA-90 requires that new tank vessels entering or operating in U.S. waters be double-hulled and
that existing tank vessels that are not double-hulled be retrofitted or removed from U.S. service. All barges used
for river transport of our raw materials and refined products meet the double-hulled requirements of OPA-90. We
operate facilities at which spills of oil and hazardous substances could occur. Some coastal states in which we
operate have passed state laws similar to OPA-90, but with expanded liability provisions, that include provisions
for cargo owner responsibility as well as ship owner and operator responsibility.

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 CWA.
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 2016.

In 2015, the EPA issued its intent to review the CWA categorical effluent limitation guidelines (“ELG”) for the
petroleum refining sector. During 2016, the EPA will prepare and request significant wastewater and treatment
process details for our refining operations. The EPA has indicated they believe there have been significant
changes in the characteristics of wastewaters generated within refining operations that warrant the review.
Specific targets for the review are the impacts of processing heavier crude oils and the transfer of air pollutants to
wastewater when air pollution abatement devices are in use. A similar project, initiated in 2007 for steam power
generation with similar attributes, resulted in a significant change in the treatment requirements for coal fired
power plants. The refining sector ELG review has the potential to result in a similar impact. We are actively

engaged in the planning process for the 2016 information request and engaged with API and AFPM on this
matter. The typical life-cycle for an ELG review from the intent to review to issuance of a final rule that would
require upgrades is seven years.

Solid Waste

We continue to seek methods to minimize the generation of hazardous wastes in our operations. RCRA
establishes standards for the management of solid and hazardous wastes. Besides affecting waste disposal
practices, RCRA also addresses the environmental effects of certain past waste disposal operations, the recycling
of wastes and the regulation of USTs containing regulated substances. We have ongoing RCRA treatment and
disposal operations at two of our facilities and primarily utilize offsite third-party treatment and disposal
facilities. Ongoing RCRA-related costs, however, are not expected to be material to our results of operations or
cash flows.

Remediation

We own or operate, or have owned or operated, certain convenience stores and other locations where, during the
normal course of operations, releases of refined products from USTs have occurred. Federal and state laws
require that contamination caused by such releases at these sites be assessed and remediated to meet applicable
standards. The enforcement of the UST regulations under RCRA has been delegated to the states, which
administer their own UST programs. Our obligation to remediate such contamination varies, depending on the
extent of the releases and the stringency of the applicable state laws and regulations. A portion of these
remediation costs may be recoverable from the appropriate state UST reimbursement funds once the applicable
deductibles have been satisfied. We also have ongoing remediation projects at a number of our current and
former refinery, terminal and pipeline locations. Penalties or other sanctions may be imposed for noncompliance.

Claims under CERCLA and similar state acts have been raised with respect to the clean-up of various waste
disposal and other sites. CERCLA is intended to facilitate the clean-up of hazardous substances without regard to
fault. Potentially responsible parties for each site include present and former owners and operators of,
transporters to and generators of the hazardous substances at the site. Liability is strict and can be joint and
several. Because of various factors including the difficulty of identifying the responsible parties for any particular
site, the complexity of determining the relative liability among them, the uncertainty as to the most desirable
remediation techniques and the amount of damages and clean-up costs and the time period during which such
costs may be incurred, we are unable to reasonably estimate our ultimate cost of compliance with CERCLA;
however, we do not believe such costs will be material to our business, financial condition, results of operations
or cash flows.

Mileage Standards, Renewable Fuels and Other Fuels Requirements

In 2007, the U.S. Congress passed the Energy Independence and Security Act (“EISA”), which, among other
things, set a target of 35 miles per gallon for the combined fleet of cars and light trucks in the United States by
model year 2020, and contains the RFS2. In August 2012, the EPA and the National Highway Traffic Safety
Administration jointly adopted regulations that establish average industry fleet fuel economy standards for
passenger cars and light trucks of up to 41 miles per gallon by model year 2021 and average fleet fuel economy
standards of up to 49.7 miles per gallon by model year 2025 (the standards from 2022 to 2025 are the
government’s current estimate but will require further rulemaking). New or alternative transportation fuels such
as compressed natural gas could also pose a competitive threat to our operations.

The RFS2 required the total volume of renewable transportation fuels sold or introduced annually in the U.S. to
reach 18.15 billion gallons in 2014, 20.5 billion gallons in 2015, 22.25 billion gallons in 2016 and increase to
36.0 billion gallons by 2022. Within the total volume of renewable fuel, EISA established an advanced biofuel
volume of 3.75 billion gallons in 2014, 5.5 billion gallons in 2015, 7.25 billion gallons in 2016, and increasing to
21.0 billion gallons in 2022. Subsets within the advanced biofuel volume include biomass-based diesel, which

was set as at least 1.0 billion gallons in 2014 through 2022 (to be determined by the EPA through rulemaking),
and cellulosic biofuel, which was set at 1.75 billion gallons in 2014, 3.0 billion gallons in 2015, 4.25 billion
gallons in 2016, and increasing to 16.0 billion gallons in 2022.

On November 30, 2015, the EPA finalized the renewable fuel standards for the years of 2014, 2015 and 2016 as
well as the biomass based diesel standard for 2017. Because the EPA missed the statutory deadlines for
establishing the standards for 2014 and 2015, the EPA set the standards using actual consumption data obtained
from EPA’s tracking system, EMTS. The volumes in billions of gallons that were finalized are as follows:

EPA Renewable Fuel Standards (billions of gallons)

2014

2015

2016

Cellulosic Ethanol

Biomass Based Diesel

Advanced Biofuel

Total Renewable

0.033

1.630

2.670

0.123

1.730

2.880

0.230

1.900

3.610

16.280

16.930

18.110

These volumes, with the exception of biomass based diesel, represent a reduction from the statutory volumes. In
the near term, the RFS2 will be satisfied primarily with ethanol blended into gasoline. Vehicle, regulatory and
infrastructure constraints limit the blending of significantly more than 10 percent ethanol into gasoline (“E10”).
The volumes for 2016 result in the ethanol content of gasoline exceeding the E10 blendwall, which will require
obligated parties to either sell E15 or FlexFuel at levels that exceed historical levels. Neither E15 nor FlexFuel
has been readily accepted by the consumer. There are numerous issues, including state and federal regulatory
issues, which need to be addressed before E15 can be marketed for use in traditional gasoline engines.

With potentially uncertain supplies, the advanced biofuels programs may present specific challenges in that we
may have to enter into arrangements with other parties or purchase credits from the EPA to meet our obligations
to use advanced biofuels, including biomass-based diesel and cellulosic biofuel.

We made investments in infrastructure capable of expanding biodiesel blending capability to help comply with
the biodiesel RFS2 requirement by buying and blending biodiesel into our refined diesel product, and by buying
needed biodiesel RINs in the EPA-created biodiesel RINs market. On April 1, 2014, we purchased a facility in
Cincinnati, Ohio, which currently produces biodiesel, glycerin and other by-products. The capacity of the plant is
approximately 60 million gallons per year. As a producer of biodiesel, we now generate RINs, thereby reducing
our reliance on the external RIN market.

On October 13, 2010, the EPA issued a partial waiver decision under the CAA to allow for an increase in the
amount of ethanol permitted to be blended into gasoline from E10 to E15 for 2007 and newer light-duty motor
vehicles. On January 21, 2011, the EPA issued a second waiver for the use of E15 in vehicles model year 2001-
2006. There are numerous issues, including state and federal regulatory issues, which need to be addressed before
E15 can be marketed for use in traditional gasoline engines.

There will be costs and uncertainties regarding how we will comply with the various requirements contained in
EISA and related regulations. The RFS2 has required, and may in the future continue to require, additional
capital expenditures or expenses by us to accommodate increased renewable fuels use. We may experience a
decrease in demand for refined petroleum products due to an increase in combined fleet mileage or due to refined
petroleum products being replaced by renewable fuels.

On March 3, 2014, the EPA signed the final Tier 3 fuel standards. The final Tier 3 fuel standards require, among
other things, a lower annual average sulfur level in gasoline to no more than 10 ppm beginning in calendar year
2017. In addition, gasoline refiners and importers may not exceed a maximum per-gallon sulfur standard of 80
ppm while retailers may not exceed a maximum per-gallon sulfur standard of 95 ppm. We anticipate that we will
spend an estimated $750 million to $1 billion between 2014 and 2019 for capital expenditures necessary to
comply with these standards, a majority of which is expected to be spent in the years of 2017 through 2019.

Trademarks, Patents and Licenses

Our Marathon trademark is material to the conduct of our refining and marketing operations, and our Speedway
trademark is material to the conduct of our retail marketing operations. We currently hold a number of U.S. and
foreign patents and have various pending patent applications. Although in the aggregate our patents and licenses
are important to us, we do not regard any single patent or license or group of related patents or licenses as critical
or essential to our business as a whole. In general, we depend on our technological capabilities and the
application of know-how rather than patents and licenses in the conduct of our operations.

Employees

We had approximately 45,440 regular employees as of December 31, 2015, which includes approximately
33,820 employees of Speedway.

Certain hourly employees at our Canton, Catlettsburg, Galveston Bay and Texas City refineries are represented
by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers
Union under labor agreements that are due to expire in 2019. The International Brotherhood of Teamsters
represents certain hourly employees at our Detroit refinery under a labor agreement that is also scheduled to
expire in 2019. In addition, they represent certain hourly employees at Speedway under agreements that cover
certain outlets in New York and New Jersey that expire on March 14, 2016 and June 30, 2016.

Executive and Corporate Officers of the Registrant

The executive and corporate officers of MPC and their ages as of January 31, 2016, are as follows:

Name

Age

Position with MPC

Gary R. Heminger

Richard D. Bedell

Timothy T. Griffith

John R. Haley(a)

James P. Heintschel(a)

Thomas Kaczynski

Thomas M. Kelley

Anthony R. Kenney

Rodney P. Nichols

Randy S. Nickerson

C. Michael Palmer

John J. Quaid

John S. Swearingen

Donald C. Templin

Donald W. Wehrly(a)

David L. Whikehart(a)

J. Michael Wilder

(a) Corporate officer.

President and Chief Executive Officer

Senior Vice President, Refining

Senior Vice President and Chief Financial Officer

Vice President, Tax

Vice President, Business Development

Vice President, Finance and Treasurer

Senior Vice President, Marketing

President, Speedway LLC

Senior Vice President, Human Resources and Administrative Services

Executive Vice President, Corporate Strategy

Senior Vice President, Supply, Distribution and Planning

Vice President and Controller

Senior Vice President, Transportation and Logistics

Executive Vice President

Vice President and Chief Information Officer

Vice President, Corporate Planning, Government and Public Affairs

Vice President, General Counsel and Secretary

Mr. Heminger was appointed president and chief executive officer effective June 30, 2011. Prior to this
appointment, Mr. Heminger was president of Marathon Petroleum Company LP (formerly known as Marathon
Ashland Petroleum LLC and Marathon Petroleum Company LLC), currently a wholly-owned subsidiary of MPC
and prior to the Spinoff, a wholly-owned subsidiary of Marathon Oil. He assumed responsibility as president of
Marathon Petroleum Company LP in September 2001.

Mr. Bedell was appointed senior vice president, Refining effective June 30, 2011. Prior to this appointment,
Mr. Bedell served in the same capacity for Marathon Petroleum Company LP beginning in June 2010 and as
manager, Louisiana Refining Division beginning in 2001. Mr. Bedell has elected to retire effective March 1,
2016.

Mr. Griffith was appointed senior vice president and chief financial officer effective March 3, 2015. Prior to this
appointment, Mr. Griffith served as vice president, Finance and Investor Relations, and treasurer beginning in
January 2014. He was vice president of Finance and treasurer beginning in August 2011. Previously, Mr. Griffith
was vice president Investor Relations and treasurer of Smurfit-Stone Container Corporation, a packaging
manufacturer, in St. Louis, Missouri, from 2008 to 2011.

Mr. Haley was appointed vice president, Tax effective June 1, 2013. Prior to this appointment, Mr. Haley served
as director of Tax beginning in July 2011 and as a tax manager for Marathon Oil Company beginning in 1996.

Mr. Heintschel was appointed vice president, Business Development effective March 3, 2015. Prior to this
appointment, Mr. Heintschel served as director of Business Development beginning in December 2009.
Previously, he served as Special Products Marketing manager beginning in 2002.

Mr. Kaczynski was appointed vice president, Finance and treasurer effective August 31, 2015. Prior to this
appointment, Mr. Kaczynski was vice president and treasurer of Goodyear Tire and Rubber Company beginning
in 2014. Previously, he served as vice president, Investor Relations, of Goodyear Tire and Rubber Company
beginning in 2013, vice president and corporate treasurer of Affinia Group Inc. beginning in 2005, and director
of affiliate finance and of capital markets and bank relations of Visteon Corporation beginning in 2000.

Mr. Kelley was appointed senior vice president, Marketing effective June 30, 2011. Prior to this appointment,
Mr. Kelley served in the same capacity for Marathon Petroleum Company LP beginning in January 2010.
Previously, he served as director of Crude Supply and Logistics for Marathon Petroleum Company LP beginning
in January 2008, and as a Brand Marketing manager for eight years prior to that.

Mr. Kenney has served as president of Speedway LLC since August 2005.

Mr. Nichols was appointed senior vice president, Human Resources and Administrative Services effective
March 1, 2012. Prior to this appointment, Mr. Nichols served as vice president, Human Resources and
Administrative Services beginning on June 30, 2011 and served in the same capacity for Marathon Petroleum
Company LP beginning in April 1998.

Mr. Nickerson was appointed executive vice president, Corporate Strategy effective December 4, 2015 at the
time of the MarkWest Merger. Prior to this appointment, Mr. Nickerson served as chief commercial officer of
MarkWest beginning in 2006 and senior vice president, Corporate Development beginning in 2003.

Mr. Palmer was appointed senior vice president, Supply, Distribution and Planning effective June 30, 2011. Prior
to this appointment, Mr. Palmer served as vice president, Supply, Distribution and Planning for Marathon
Petroleum Company LP beginning in June 2010. He served as Crude Supply and Logistics director for Marathon
Petroleum Company LP beginning in February 2010, and as senior vice president, Oil Sands Operations and
Commercial Activities for Marathon Oil Canada Corporation beginning in 2007.

Mr. Quaid was appointed vice president and controller effective June 23, 2014. Prior to this appointment,
Mr. Quaid was vice president of Iron Ore at United States Steel Corporation (“U. S. Steel”), an integrated steel
producer, beginning in January 2014. Previously, Mr. Quaid served in various leadership positions at U. S. Steel
since February 2002, including vice president and treasurer beginning in August 2011, controller, North
American Flat-Rolled Operations beginning in July 2010 and assistant corporate controller beginning in 2008.

Mr. Swearingen was appointed senior vice president, Transportation and Logistics effective March 3, 2015. Prior
to this appointment, Mr. Swearingen served as vice president of Health, Environmental, Safety & Security
beginning June 30, 2011. Previously, he was president of Marathon Pipe Line LLC beginning in 2009 and the
Illinois Refining Division manager beginning in November 2001.

Mr. Templin was appointed executive vice president effective January 1, 2016. Prior to this appointment,
Mr. Templin served as executive vice president, Supply, Transportation and Marketing beginning March 3, 2015
and senior vice president and chief financial officer beginning on June 30, 2011. Previously, he was a partner at
PricewaterhouseCoopers LLP, an audit, tax and advisory services provider, with various audit and management
responsibilities beginning in 1996.

Mr. Wehrly was appointed vice president and chief information officer effective June 30, 2011. Prior to this
appointment, Mr. Wehrly was the manager of Information Technology Services for Marathon Petroleum
Company LP beginning in 2003.

Mr. Whikehart was appointed vice president, Corporate Planning, Government & Public Affairs effective
January 1, 2016. Prior to this appointment, Mr. Whikehart was the director, Product Supply and Optimization
beginning in March 2011. Previously, Mr. Whikehart served as director, Climate Change and Carbon
Management beginning in 2010 and director, Business Development beginning in 2008. Effective February 29,
2016, Mr. Whikehart was appointed vice president, Environmental, Safety and Corporate Affairs.

Mr. Wilder was appointed vice president, general counsel and secretary effective June 30, 2011. Prior to this
appointment, Mr. Wilder was associate general counsel of Marathon Oil Company beginning in 2010 and general
counsel and secretary of Marathon Petroleum Company LP beginning in 1997. Mr. Wilder has elected to retire
effective March 1, 2016.

Pamela K.M. Beall was appointed executive vice president, Corporate Planning and Strategy of MPLX effective
January 1, 2016. Prior to this appointment, Ms. Beall was senior vice president, Corporate Planning,
Government & Public Affairs beginning in January 2014, vice president, Investor Relations and Government &
Public Affairs beginning in 2011, vice president, Products Supply and Optimization of Marathon Petroleum
Company LP beginning in 2010 and vice president of Global Procurement for Marathon Oil Company beginning
in 2007.

Raymond L. Brooks, general manager, Galveston Bay refinery, was appointed senior vice president, Refining
effective March 1, 2016. Prior to this appointment, Mr. Brooks was general manager, Galveston Bay refinery
beginning in February 2013, general manager, Robinson refinery beginning in 2010 and general manager, St.
Paul Park, Minnesota refinery (no longer owned by MPC) beginning in 2006.

Suzanne Gagle, assistant general counsel, litigation and Human Resources, was appointed vice president and
general counsel effective March 1, 2016. Prior to this appointment, Ms. Gagle was assistant general counsel,
litigation and Human Resources beginning in April 2011, senior group counsel, downstream operations
beginning in 2010 and group counsel, litigation, beginning in 2003.

Molly R. Benson, assistant general counsel, corporate and finance was appointed vice president, corporate
secretary and chief compliance officer effective March 1, 2016. Prior to this appointment, Ms. Benson was
assistant general counsel, corporate and finance beginning in April 2012, group counsel, corporate and finance
beginning in 2011, group counsel, North American production for Marathon Oil Company beginning in 2010 and
senior attorney, downstream business beginning in 2006.

Available Information

information about MPC,

General
Committee, Compensation Committee and Corporate Governance and Nominating Committee, can be found at
http://ir.marathonpetroleum.com. In addition, our Code of Business Conduct and Code of Ethics for Senior
Financial Officers are also available in this same location.

including Corporate Governance Principles and Charters for the Audit

MPC uses its website, www.marathonpetroleum.com, as a channel for routine distribution of important
information, including news releases, analyst presentations, financial information and market data. 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.

Item 1A. Risk Factors

You should carefully consider each of the following risks and all of the other information contained in this
Annual Report on Form 10-K in evaluating us and our common stock. Some of these risks relate principally to
our business and the industry in which we operate, while others relate to the ownership of our common stock.

Our business, financial condition, results of operations or cash flows could be materially and adversely affected
by any of these risks, and, as a result, the trading price of our common stock could decline.

Risks Relating to our Business

A substantial or extended decline in refining and marketing gross margins would reduce our operating
results and cash flows and could materially and adversely impact our future rate of growth, the carrying
value of our assets and our ability to execute share repurchases and continue the payment of our base
dividend.

Our operating results, cash flows, future rate of growth, the carrying value of our assets and our ability to execute
share repurchases and continue the payment of our base dividend are highly dependent on the margins we realize
on our refined products. The measure of the difference between market prices for refined products and crude oil,
or crack spread, is commonly used by the industry as a proxy for refining and marketing gross margins.
Historically, refining and marketing gross margins have been volatile, and we believe they will continue to be
volatile. Our margins from the sale of gasoline and other refined products are influenced by a number of
conditions, including the price of crude oil. We do not produce crude oil and must purchase all of the crude oil
we refine. The price of crude oil and the price at which we can sell our refined products may fluctuate
independently due to a variety of regional and global market conditions. Any overall change in crack spreads will
impact our refining and marketing gross margins. Many of the factors influencing a change in crack spreads and
refining and marketing gross margins are beyond our control. These factors include:

• worldwide and domestic supplies of and demand for crude oil and refined products;

•

the cost of crude oil and other feedstocks to be manufactured into refined products;

the prices realized for refined products;

utilization rates of refineries;

natural gas and electricity supply costs incurred by refineries;

the ability of the members of OPEC to agree to and maintain production controls;

political instability or armed conflict in oil and natural gas producing regions;

local weather conditions;

seasonality of demand in our marketing area due to increased highway traffic in the spring and summer
months;

natural disasters such as hurricanes and tornadoes;

the price and availability of alternative and competing forms of energy;

domestic and foreign governmental regulations and taxes; and

local, regional, national and worldwide economic conditions.

Some of these factors can vary by region and may change quickly, adding to market volatility, while others may
have longer-term effects. The longer-term effects of these and other factors on refining and marketing gross
margins are uncertain. We purchase our crude oil and other refinery feedstocks weeks before we refine them and
sell the refined products. Price level changes during the period between purchasing feedstocks and selling the
refined products from these feedstocks could have a significant effect on our financial results. We also purchase

refined products manufactured by others for resale to our customers. Price changes during the periods between
purchasing and reselling those refined products also could have a material adverse effect on our business,
financial condition, results of operations and cash flows.

Lower refining and marketing gross margins may reduce the amount of refined products we produce, which may
reduce our revenues, income from operations and cash flows. Significant reductions in refining and marketing
gross margins could require us to reduce our capital expenditures, impair the carrying value of our assets (such as
property, plant and equipment, inventory or goodwill), decrease or eliminate our share repurchase activity and
our base dividend.

Our operations are subject to business interruptions and casualty losses. Failure to manage risks
associated with business interruptions could adversely impact our operations, financial condition, results
of operations and cash flows.

Our operations are subject
to business interruptions due to scheduled refinery turnarounds, unplanned
maintenance or unplanned events such as explosions, fires, refinery or pipeline releases or other incidents, power
outages, severe weather, labor disputes, or other natural or man-made disasters, such as acts of terrorism. For
example, pipelines provide a nearly-exclusive form of transportation of crude oil to, or refined products from,
some of our refineries. In such instances, a prolonged interruption in service of such a pipeline could materially
and adversely affect the operations, profitability and cash flows of the impacted refinery.

Explosions, fires, refinery or pipeline releases or other incidents involving our assets or operations could result in
serious personal injury or loss of human life, significant damage to property and equipment, environmental
pollution, impairment of operations and substantial losses to us. Damages resulting from an incident involving
any of our assets or operations may result in our being named as a defendant in one or more lawsuits asserting
potentially substantial claims or in our being assessed potentially substantial fines by governmental authorities.

We do not insure against all potential losses, and, therefore, our business, financial condition, results of
operations and cash flows could be adversely affected by unexpected liabilities and increased costs.

We maintain insurance coverage in amounts we believe to be prudent against many, but not all, potential
liabilities arising from operating hazards. Uninsured liabilities arising from operating hazards, including but not
limited to, explosions, fires, refinery or pipeline releases or other incidents involving our assets or operations,
could reduce the funds available to us for capital and investment spending and could have a material adverse
effect on our business, financial condition, results of operations and cash flows. Historically, we also have
maintained insurance coverage for physical damage and resulting business interruption to our major facilities,
with significant self-insured retentions. In the future, we may not be able to maintain insurance of the types and
amounts we desire at reasonable rates.

We rely on the performance of our information technology systems, the failure of which could have an
adverse effect on our business, financial condition, results of operations and cash flows.

We are heavily dependent on our information technology systems and network infrastructure and maintain and
rely upon certain critical information systems for the effective operation of our business. These information
systems involve data network and telecommunications, Internet access and website functionality, and various
computer hardware equipment and software applications, including those that are critical to the safe operation of
our business. These systems and infrastructure are subject to damage or interruption from a number of potential
sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other
events. We also face various other cyber-security threats, including threats to gain unauthorized access to
sensitive information or to render data or systems unusable. To protect against such attempts of unauthorized
access or attack, we have implemented infrastructure protection technologies and disaster recovery plans. There
can be no guarantee such plans, to the extent they are in place, will be effective.

The retail market is diverse and highly competitive, and very aggressive competition could adversely
impact our business.

We face strong competition in the market for the sale of retail gasoline, diesel fuel and merchandise. Our
competitors include outlets owned or operated by fully integrated major oil companies or their dealers or jobbers,
and other well-recognized national or regional retail outlets, often selling gasoline or merchandise at very
competitive prices. Several non-traditional retailers such as supermarkets, club stores and mass merchants are in
the retail business. These non-traditional gasoline retailers have obtained a significant share of the transportation
fuels market and we expect their market share to grow. Because of their diversity, integration of operations,
experienced management and greater financial resources, these companies may be better able to withstand
volatile market conditions or levels of low or no profitability in the retail segment of the market. In addition,
these retailers may use promotional pricing or discounts, both at the pump and in the store, to encourage in-store
merchandise sales. These activities by our competitors could pressure us to offer similar discounts, adversely
affecting our profit margins. Additionally, the loss of market share by our convenience stores to these and other
retailers relating to either gasoline or merchandise could have a material adverse effect on our business, financial
condition, results of operations and cash flows.

The development, availability and marketing of alternative and competing fuels in the retail market could
adversely impact our business. We compete with other industries that provide alternative means to satisfy the
energy and fuel needs of our consumers. Increased competition from these alternatives as a result of
governmental regulations, technological advances and consumer demand could have an impact on pricing and
demand for our products and our profitability.

We are subject to interruptions of supply and increased costs as a result of our reliance on third-party
transportation of crude oil and refined products.

We utilize the services of third parties to transport crude oil and refined products to and from our refineries. In
addition to our own operational risks discussed above, we could experience interruptions of supply or increases
in costs to deliver refined products to market if the ability of the pipelines, railways or vessels to transport crude
oil or refined products is disrupted because of weather events, accidents, governmental regulations or third-party
actions. A prolonged disruption of the ability of the pipelines, railways or vessels to transport crude oil or refined
products to or from one or more of our refineries could have a material adverse effect on our business, financial
condition, results of operations and cash flows.

We may incur losses to our business as a result of our forward-contract activities and derivative
transactions.

We currently use commodity derivative instruments, and we expect to enter into these types of transactions in the
future. A failure of a futures commission merchant or counterparty to perform would affect these transactions. To
the extent the instruments we utilize to manage these exposures are not effective, we may incur losses related to
the ineffective portion of the derivative transaction or costs related to moving the derivative positions to another
futures commission merchant or counterparty once a failure has occurred.

We have significant debt obligations; therefore, our business, financial condition, results of operations and
cash flows could be harmed by a deterioration of our credit profile, a decrease in debt capacity or
unsecured commercial credit available to us, or by factors adversely affecting credit markets generally.

At December 31, 2015, our total debt obligations for borrowed money and capital lease obligations were $12.5
billion, including $5.7 billion of obligations of MPLX. We may incur substantial additional debt obligations in
the future.

Our indebtedness may impose various restrictions and covenants on us that could have material adverse
consequences, including:

•

increasing our vulnerability to changing economic, regulatory and industry conditions;

•

limiting our ability to compete and our flexibility in planning for, or reacting to, changes in our
business and the industry;

limiting our ability to pay dividends to our stockholders;

limiting our ability to borrow additional funds; and

requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt,
thereby reducing funds available for working capital, capital expenditures, acquisitions, share
repurchases, dividends and other purposes.

A decrease in our debt or commercial credit capacity, including unsecured credit extended by third-party
suppliers, or a deterioration in our credit profile could increase our costs of borrowing money and/or limit our
access to the capital markets and commercial credit, which could materially and adversely affect our business,
financial condition, results of operations and cash flows.

We have a trade receivables securitization facility that provides liquidity of up to $1.0 billion depending on the
amount of eligible domestic trade accounts receivables. In periods of lower prices, we may not have sufficient
eligible accounts receivables to support full availability of this facility.

Historic or current operations could subject us to significant legal liability or restrict our ability to
operate.

We currently are defending litigation and anticipate we will be required to defend new litigation in the future.
Our operations, including liabilities assumed by MPLX in the MarkWest Merger, and those of our predecessors
could expose us to litigation and civil claims by private plaintiffs for alleged damages related to contamination of
the environment or personal injuries caused by releases of hazardous substances from our facilities, products
liability, consumer credit or privacy laws, product pricing or antitrust laws or any other laws or regulations that
apply to our operations. While an adverse outcome in most litigation matters would not be expected to be
material to us, in class-action litigation, large classes of plaintiffs may allege damages relating to extended
periods of time or other alleged facts and circumstances that could increase the amount of potential damages.
Attorneys general and other government officials may pursue litigation in which they seek to recover civil
damages from companies on behalf of a state or its citizens for a variety of claims, including violation of
consumer protection and product pricing laws or natural resources damages. We are defending litigation of that
type and anticipate that we will be required to defend new litigation of that type in the future. If we are not able
to successfully defend such litigation, it may result in liability to our company that could materially and
adversely affect our business, financial condition, results of operations and cash flows. We do not have insurance
covering all of these potential liabilities. In addition to substantial liability, plaintiffs in litigation may also seek
injunctive relief which, if imposed, could have a material adverse effect on our future business, financial
condition, results of operations and cash flows.

A portion of our workforce is unionized, and we may face labor disruptions that could materially and
adversely affect our business, financial condition, results of operations and cash flows.

Approximately 36 percent of our refining employees are covered by collective bargaining agreements. Certain
hourly employees at our Canton, Catlettsburg, Galveston Bay and Texas City refineries are represented by the
United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers Union
under labor agreements that are due to expire in 2019. The International Brotherhood of Teamsters represents
certain hourly employees at our Detroit refinery under a labor agreement that is also scheduled to expire in 2019.
In addition, they represent certain hourly employees at Speedway under agreements that cover certain outlets in
New York and New Jersey that expire between on March 14, 2016 and June 30, 2016. These contracts may be
renewed at an increased cost to us. In addition, we have experienced, or may experience, work stoppages as a
result of labor disagreements. Any prolonged work stoppages disrupting operations could have a material adverse
effect on our business, financial condition, results of operations and cash flows.

One of our subsidiaries acts as the general partner of a publicly traded master limited partnership,
MPLX, which may involve a greater exposure to certain legal liabilities than existed under our historic
business operations.

One of our subsidiaries acts as the general partner of MPLX, a publicly traded master limited partnership. Our
control of the general partner of MPLX may increase the possibility of claims of breach of fiduciary duties
including claims of conflicts of interest related to MPLX. Any liability resulting from such claims could have a
material adverse effect on our future business, financial condition, results of operations and cash flows.

If foreign ownership of our stock 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, corporations 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.

We are subject to certain continuing contingent liabilities of Marathon Oil relating to taxes and other
matters and to potential liabilities pursuant to the tax sharing agreement we entered into with Marathon
Oil that could materially and adversely affect our business, financial condition, results of operations and
cash flows.

Although the Spinoff occurred in mid-2011, certain liabilities of Marathon Oil could become our obligations. For
example, under the Internal Revenue Code of 1986 (the “Code”) and related rules and regulations, each
corporation that was a member of the Marathon Oil consolidated tax reporting group during any taxable period or
portion of any taxable period ending on or before the effective time of the Spinoff is jointly and severally liable
for the federal income tax liability of the entire Marathon Oil consolidated tax reporting group for that taxable
period. In connection with the Spinoff, we entered into a tax sharing agreement with Marathon Oil that allocates
the responsibility for prior period taxes of the Marathon Oil consolidated tax reporting group between us and
Marathon Oil. However, if Marathon Oil is unable to pay any prior period taxes for which it is responsible, we
could be required to pay the entire amount of such taxes. Other provisions of federal law establish similar
liability for other matters, including laws governing tax-qualified pension plans as well as other contingent
liabilities.

Also pursuant to the tax sharing agreement, following the Spinoff we are responsible generally for all taxes
attributable to us or any of our subsidiaries, whether accruing before, on or after the Spinoff. We also agreed to
be responsible for, and indemnify Marathon Oil with respect to, all taxes arising as a result of the Spinoff (or
certain internal restructuring transactions) failing to qualify as transactions under Sections 368(a) and 355 of the
Code for U.S. federal income tax purposes to the extent such tax liability arises as a result of any breach of any
representation, warranty, covenant or other obligation by us or certain affiliates made in connection with the
issuance of the private letter ruling relating to the Spinoff or in the tax sharing agreement. In addition, we agreed
to indemnify Marathon Oil for specified tax-related liabilities associated with our 2005 acquisition of the
minority interest in our refining joint venture from Ashland Inc. Our indemnification obligations to Marathon Oil
and its subsidiaries, officers and directors are not limited or subject to any cap. If we are required to indemnify
Marathon Oil and its subsidiaries and their respective officers and directors under the tax sharing agreement, we
may be subject to substantial liabilities. At this time, we cannot precisely quantify the amount of these liabilities
that have been assumed pursuant to the tax sharing agreement, and there can be no assurances as to their final
amounts. The tax liabilities described in this paragraph could have a material adverse effect on our business,
financial condition, results of operation and cash flows.

The Spinoff could be determined not to qualify as a tax-free transaction, and Marathon Oil and its
stockholders could be subject to material amounts of taxes and, in certain circumstances, we could be
required to indemnify Marathon Oil for material taxes pursuant to indemnification obligations under the
tax sharing agreement.

Marathon Oil received a private letter ruling from the IRS, to the effect that, among other things, the distribution
of shares of MPC common stock in the Spinoff qualifies as tax-free to Marathon Oil, us and Marathon Oil
stockholders for U.S. federal income tax purposes under Sections 355 and 368(a) and related provisions of the
Code. If the factual assumptions or representations made in the private letter ruling request are inaccurate or
incomplete in any material respect, then Marathon Oil would not be able to continue to rely on the ruling. We are
not aware of any facts or circumstances that would cause the assumptions or representations that were relied on
in the private letter ruling to be inaccurate or incomplete in any material respect. If, notwithstanding receipt of
the private letter ruling, the Spinoff were determined not to qualify under Section 355 of the Code, Marathon Oil
would be subject to tax as if it had sold its shares of common stock of our company in a taxable sale for their fair
market value and would recognize a taxable gain in an amount equal to the excess of the fair market value of
such shares over its tax basis in such shares.

With respect to taxes and other liabilities that could be imposed on Marathon Oil in connection with the Spinoff
(and certain related transactions) as a result of a final determination that is inconsistent with the anticipated tax
consequences as set forth in the private letter ruling, we would be liable to Marathon Oil under the tax sharing
agreement for any such taxes or liabilities attributable to actions taken by or with respect to us, any of our
affiliates, or any person that, after the Spinoff, is our affiliate. We may be similarly liable if we breach specified
representations or covenants set forth in the tax sharing agreement. If we are required to indemnify Marathon Oil
for taxes incurred as a result of the Spinoff (or certain related transactions) being taxable to Marathon Oil, it
would have a material adverse effect on our business, financial condition, results of operations and cash flows.

We have potential liabilities pursuant to the separation and distribution agreement we entered into with
Marathon Oil in connection with the Spinoff that could materially and adversely affect our business,
financial condition, results of operations and cash flows.

In connection with the Spinoff, we entered into a separation and distribution agreement with Marathon Oil that
provides for, among other things, the principal corporate transactions that were required to affect the Spinoff,
certain conditions to the Spinoff and provisions governing the relationship between our company and Marathon
Oil with respect to and resulting from the Spinoff. Among other things, the separation and distribution agreement
provides for indemnification obligations designed to make us financially responsible for substantially all
liabilities that may exist relating to our downstream business activities, whether incurred prior to or after the
Spinoff, as well as certain obligations of Marathon Oil assumed by us. Our obligations to indemnify Marathon
Oil under the circumstances set forth in the separation and distribution agreement could subject us to substantial
liabilities. Marathon Oil also agreed to indemnify us for certain liabilities. However, third parties could seek to
hold us responsible for any of the liabilities retained by Marathon Oil, and there can be no assurance that the
indemnity from Marathon Oil will be sufficient to protect us against the full amount of such liabilities, that
Marathon Oil will be able to fully satisfy its indemnification obligations or that Marathon Oil’s insurers will
cover us for liabilities associated with occurrences prior to the Spinoff. Moreover, even if we ultimately succeed
in recovering from Marathon Oil or its insurers any amounts for which we are held liable, we may be temporarily
required to bear these losses ourselves. If Marathon Oil is unable to satisfy its indemnification obligations, the
underlying liabilities could have a material adverse effect on our business, financial condition, results of
operations and cash flows.

We may not realize the growth opportunities and commercial synergies that are anticipated from the
MarkWest Merger.

The benefits that are expected to result from the MarkWest Merger will depend, in part, on MPLX’s ability to
realize the anticipated growth opportunities and commercial synergies as a result of the MarkWest Merger.

MPLX’s success in realizing these growth opportunities and commercial synergies, and the timing of this
realization, depends on the successful integration of MPLX and MarkWest. There is a significant degree of
difficulty and management distraction inherent
in the process of integrating an acquisition as sizable as
MarkWest. The process of integrating operations could cause an interruption of, or loss of momentum in, the
activities of MPLX and MarkWest. Members of our senior management may be required to devote considerable
amounts of time to this integration process, which will decrease the time they will have to manage our company,
maintain relationships with employees, customers or suppliers, attract new customers and develop new strategies.
If senior management is not able to effectively manage the integration process, or if any significant business
activities are interrupted as a result of the integration process, our business could suffer. There can be no
assurance that MPLX will successfully or cost-effectively integrate MarkWest. The failure to do so could have a
material adverse effect on our business, financial condition, and results of operations.

Even if MPLX is able to integrate MarkWest successfully, this integration may not result in the realization of the
full benefits of the growth opportunities and commercial synergies that we currently expect from this integration,
and we cannot guarantee that these benefits will be achieved within anticipated time frames or at all. For
example, MPLX may not be able to eliminate duplicative costs. Moreover, MPLX may incur substantial
expenses in connection with the integration of MarkWest. While it is anticipated that certain expenses will be
incurred to achieve commercial synergies, such expenses are difficult to estimate accurately, and may exceed
current estimates. Accordingly, the benefits from the MarkWest Merger may be offset by costs incurred to, or
delays in, integrating the businesses.

Significant acquisitions in the future will involve the integration of new assets or businesses and present
substantial risks that could adversely affect our business, financial conditions, results of operations and
cash flows.

In addition to the MarkWest Merger, significant future transactions involving the addition of new assets or
businesses will present potential risks, which may include, among others:

•

Inaccurate assumptions about future synergies, revenues, capital expenditures and operating costs;

• An inability to successfully integrate assets or businesses we acquire;

• A decrease in our liquidity resulting from using a portion of our available cash or borrowing capacity

under our revolving credit agreement to finance transactions;

• A significant increase in our interest expense or financial leverage if we incur additional debt to finance

transactions;

• The assumption of unknown environmental and other liabilities, losses or costs for which we are not

indemnified or for which our indemnity is inadequate;

• The diversion of management’s attention from other business concerns; and

• The incurrence of other significant charges, such as impairment of goodwill or other intangible assets,

asset devaluation or restructuring charges.

A significant decrease or delay in oil and natural gas production in MPLX’s areas of operation, whether
due to sustained declines in oil, natural gas and NGL prices, natural declines in well production, or
otherwise, may adversely affect MPLX’s business, results of operations and financial condition, and could
reduce MPLX’s ability to make distributions to us.

A significant portion of MPLX’s operations are dependent upon production from oil and natural gas reserves and
wells, which will naturally decline over time, which means that MPLX’s cash flows associated with these wells
will also decline over time. To maintain or increase throughput levels and the utilization rate of MPLX’s
facilities, MPLX must continually obtain new oil, natural gas, NGL and refined product supplies, which depends
in part on the level of successful drilling activity near its facilities.

We have no control over the level of drilling activity in the areas of MPLX’s 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
the level of reserves, geological considerations, governmental regulations and the
downstream markets,
availability and cost of capital. Because of these factors, even if new oil or natural gas reserves are discovered in
areas served by MPLX assets, producers may choose not to develop those reserves. If MPLX is not able to obtain
new supplies of oil or natural gas to replace the natural decline in volumes from existing wells, throughput on
MPLX pipelines and the utilization rates of MPLX facilities would decline, which could have a material adverse
effect on MPLX’s business, results of operations and financial condition and could reduce MPLX’s ability to
make distributions to us.

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 MPLX’s facilities and adversely affect
MPLX’s revenues and cash available for distribution to us. This impact may also be exacerbated due to the extent
of MPLX’s commodity-based contracts, which are more directly impacted by changes in gas and NGL prices
than its 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, MPLX’s purchase and resale
of gas and NGLs in the ordinary course exposes MPLX 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 MPLX’s production
processes. The significant fluctuation and decline in natural gas, NGL and oil prices currently occurring has
adversely impacted MPLX’s unit price, thereby increasing its distribution yield and cost of capital. Such impacts
could adversely impact MPLX’s ability to execute its long-term organic growth projects, satisfy obligations to its
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.

Risks Relating to Our Industry

Changes in environmental or other laws or regulations may reduce our refining and marketing gross
margin and may result in substantial capital expenditures and operating costs that could materially and
adversely affect our business, financial condition, results of operations and cash flows.

Various laws and regulations are expected to impose increasingly stringent and costly requirements on our
operations, which may reduce our refining and marketing gross margin. Laws and regulations expected to
become more stringent relate to the following:

•

the emission or discharge of materials into the environment,

solid and hazardous waste management,

pollution prevention,

greenhouse gas emissions,

characteristics and composition of gasoline and diesel fuels,

public and employee safety and health, and

facility security.

The specific impact of laws and regulations on us and our competitors may vary depending on a number of
factors, including the age and location of operating facilities, marketing areas, crude oil and feedstock sources
and production processes. We may be required to make expenditures to modify operations, install pollution
control equipment, perform site cleanups or curtail operations that could materially and adversely affect our
business, financial condition, results of operations and cash flows.

Because the issue of climate change continues to receive scientific and political attention, there is the potential
for further laws and regulations that could affect our operations. The U.S. pledge in 2009, as part of the
Copenhagen Accord, to reduce greenhouse gas emissions 17 percent below 2005 levels by 2020 remains in effect
and was reaffirmed in the President’s 2013 Climate Action Plan. The 2015 Paris UN Climate Change Conference
Agreement aims to hold the increase in the global average temperature to well below two degrees Celsius above
pre-industrial levels. The Paris Agreement does not legally require parties to the Agreement to reduce greenhouse
gas emissions, but the U.S.’s future activities in response to the Paris Agreement may result in regulations to
further reduce greenhouse gas emissions.

In October 2015,
the EPA finalized regulations to reduce carbon emissions from new, modified, and
reconstructed power plants (new source performance standards) and from existing power plants (existing source
performance standards; also known as the Clean Power Plan). Through the regulations, the EPA is requiring a
reduction in nationwide carbon emissions from the power generation sector by 32 percent below 2005 levels.
These standards could increase our electricity costs and potentially reduce the reliability of our electricity supply.
In February 2016, the U.S. Supreme Court stayed implementation of the Clean Power Plan until the legal
challenge filed by several states and industry could be heard by the courts.

The Obama administration has also developed the social cost of carbon (“SCC”), which is to be used by the EPA
and other federal agencies in regulatory cost-benefit analyses to take into account alleged broad economic
consequences associated with changes to emissions of greenhouse gases. The SCC was first issued in 2010. In
2013, the Obama administration significantly increased the estimate to $36 per ton. In response to the regulated
community and Congress’ critiques of how the SCC was developed, the Office of Management and Budget
(“OMB”) provided an opportunity to comment on the SCC. In July 2015, the OMB issued a response to
comments and a revised technical support document explaining adjustments to the SCC calculations.
Additionally, in December 2014, the White House Council on Environmental Quality issued new draft guidance
for assessing greenhouse gas emissions under the National Environmental Policy Act, adding for the first time
language that requires that analyses also include the impact of climate change on projects, including using the
SCC when analyzing costs and benefits of a project. While the impact of a higher SCC in future regulations is not
known at this time, it may result in increased costs to our operations.

An article on the social cost of methane has also been published and was used by the EPA in its regulatory
impact analysis of the proposed emission standards for new and modified sources in the oil and natural gas
sector. These regulations were proposed pursuant to President Obama’s Strategy to Reduce Methane Emissions
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. The finalization of these regulations could directly impact MPLX by creating
delays in the construction and installation of new facilities due to more stringent permitting requirements,
increasing costs to reduce GHG emissions or requiring aggregation of emissions from separate facilities for
permitting purposes. These regulations may also impact us by increasing the costs of domestic crude supplies.

In the future, Congress may again consider legislation on greenhouse gas emissions or a carbon tax. Other
measures to address greenhouse gas emissions are in various phases of review or implementation in the U.S.
These measures include state actions to develop statewide or regional programs to impose emission reductions.
Private party litigation is pending against federal and certain state governmental entities seeking additional
greenhouse gas emission reductions beyond those currently being undertaken. These actions could result in
increased costs to operate and maintain our facilities, capital expenditures to install new emission controls and
costs to administer any carbon trading or tax programs implemented. Although uncertain, these developments

could increase our costs, reduce the demand for the products we sell and create delays in our obtaining air
pollution permits for new or modified facilities.

In October 2015,
the EPA reduced the primary (health) ozone National Ambient Air Quality Standards
(“NAAQS”) to 70 ppb from the prior ozone level of 75 ppb. The EPA is expected to finalize new ozone
attainment and nonattainment designations by late 2017, using 2014-2016 air quality monitor data. The lower
primary ozone standard may not by attainable in some areas and could result in the cancellation or delay of
capital projects at our facilities or increased costs related to an increase in the production of low Reid vapor
pressure (RVP) gasoline.

The EISA establishes increases in fuel mileage standards and contains a second Renewable Fuel Standard
commonly referred to as RFS2. Increases in fuel mileage standards and the increased use of renewable fuels
(including ethanol and advanced biofuels) may reduce demand for refined products. Governmental regulations
encouraging the use of new or alternative fuels could also pose a competitive threat
to our operations.
Specifically, the RFS2 required the total volume of renewable transportation fuels sold or introduced annually in
the U.S. to reach 36.0 billion gallons by 2022. The RFS2 presents production and logistics challenges for both
the renewable fuels and petroleum refining industries, and may continue to require additional capital
expenditures or expenses by us to accommodate increased renewable fuels use. Gasoline consumption has been
lower than forecasted by the EPA, which has led to concerns that the renewable fuel volumes may not be met.
The 2014, 2015, and 2016 renewable fuel standards were finalized and published on December 14, 2015. The
final standards are lower than the statutory requirements but nevertheless result in volumes that breach the
ethanol “blendwall.” The advanced biofuels program, a subset of the RFS2 requirements, creates uncertainties
and presents challenges of supply, and may require that we and other refiners and other obligated parties
purchase credits from the EPA to meet our obligations.

Tax incentives and other subsidies have also made renewable fuels more competitive with refined products than
they otherwise would have been, which may further reduce refined product margins.

On March 3, 2014, the EPA signed the final Tier 3 fuel standards. The final Tier 3 fuel standards require, among
other things, a lower annual average sulfur level in gasoline to no more than 10 parts ppm beginning in calendar
year 2017. In addition, gasoline refiners and importers may not exceed a maximum per-gallon sulfur standard of
80 ppm, while retailers may not exceed a maximum per-gallon sulfur standard of 95 ppm. We anticipate that we
will spend an estimated $750 million to $1 billion between 2014 and 2019 for capital expenditures necessary to
comply with these standards.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could delay or
impede producer’s gas production or result in reduced volumes available for MPLX to gather, process and
fractionate. MPLX does not conduct hydraulic fracturing operations, but it does provide gathering, processing
and fractionation services with respect to natural gas and natural gas liquids produced by its customers as a result
of such operations. If federal, state or local laws or regulations that significantly restrict hydraulic fracturing are
adopted, such legal requirements could make it more difficult to complete natural gas wells in shale formations
and increase producers’ costs of compliance.

Severe weather events may adversely affect our facilities and ongoing operations.

For a variety of reasons, natural and/or anthropogenic, some members of the scientific community believe that
climate changes could occur that 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.

Plans we may have to expand existing assets or construct new assets are subject to risks associated with
societal and political pressures and other forms of opposition to the future development, transportation
and use of carbon-based fuels. Such risks could adversely impact our business and ability to realize certain
growth strategies.

Our anticipated growth and planned expenditures are based upon the assumption that societal sentiment will
continue to enable and existing regulations will remain intact to allow for the future development, transportation
and use of carbon-based fuels. A portion of our growth strategy is dependent on our ability to expand existing
assets and to construct additional assets. However, policy decisions relating to the production, refining,
transportation and marketing of carbon-based fuels are subject to political pressures and the influence of
environmental and other special interest groups. The construction of new refinery processing units or crude oil or
refined products pipelines, or the extension or expansion of existing assets, involve numerous political and legal
uncertainties, many of which may cause significant delays or cost increases and most of which are beyond our
control. Delays or cost increases related to capital spending programs involving engineering, procurement and
construction of facilities (including improvements and repairs to our existing facilities) could adversely affect our
ability to achieve forecasted internal rates of return and operating results, thereby limiting our ability to grow and
generate cash flows.

Large capital projects can take many years to complete, and market conditions could deteriorate
significantly between the project approval date and the project startup date, negatively impacting project
returns. If we are unable to complete capital projects at their expected costs and in a timely manner, or if
the market conditions assumed in our project economics deteriorate, our business, financial condition,
results of operations and cash flows could be materially and adversely affected.

Delays or cost
increases related to capital spending programs involving engineering, procurement and
construction of facilities could materially adversely affect our ability to achieve forecasted internal rates of return
and operating results. Delays in making required changes or upgrades to our facilities could subject us to fines or
penalties as well as affect our ability to supply certain products we produce. Such delays or cost increases may
arise as a result of unpredictable factors, many of which are beyond our control, including:

•

denial of or delay in receiving requisite regulatory approvals and/or permits;

unplanned increases in the cost of construction materials or labor;

disruptions in transportation of components or construction materials;

adverse weather conditions, natural disasters or other events (such as equipment malfunctions,
explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;

shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

• market-related increases in a project’s debt or equity financing costs; and

•

nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.

Any one or more of these factors could have a significant impact on our ongoing capital projects. If we were
unable to make up the delays associated with such factors or to recover the related costs, or if market conditions
change, it could materially and adversely affect our business, financial condition, results of operations and cash
flows.

The availability of crude oil and increases in crude oil prices may reduce profitability and refining and
marketing gross margins.

The profitability of our operations depends largely on the difference between the cost of crude oil and other
feedstocks we refine and the selling prices we obtain for refined products. A portion of our crude oil is purchased
from various foreign national oil companies, producing companies and trading companies, including suppliers

from Canada, the Middle East and various other international locations. The market for crude oil and other
feedstocks is largely a world market. We are, therefore, subject to the attendant political, geographic and
economic risks of such a market. If one or more major supply sources were temporarily or permanently
eliminated, we believe adequate alternative supplies of crude oil would be available, but it is possible we would
be unable to find alternative sources of supply. If we are unable to obtain adequate crude oil volumes or are able
to obtain such volumes only at unfavorable prices, our operations, sales of refined products and refining and
marketing gross margins could be adversely affected, materially and adversely impacting our business, financial
condition, results of operations and cash flows.

Worldwide political and economic developments could materially and adversely impact our business,
financial condition, results of operations and cash flows.

In addition to impacting crude oil and other feedstock supplies, political and economic factors in global markets
could have a material adverse effect on us in other ways. Hostilities in the Middle East or the occurrence or threat
of future terrorist attacks could adversely affect the economies of the U.S. and other developed countries. A
lower level of economic activity could result in a decline in energy consumption, which could cause our revenues
and margins to decline and limit our future growth prospects. These risks could lead to increased volatility in
prices for refined products, NGLs and natural gas. Additionally, these risks could increase instability in the
financial and insurance markets and make it more difficult and/or costly for us to access capital and to obtain the
insurance coverage that we consider adequate. Additionally, tax policy, legislative or regulatory action and
commercial restrictions could reduce our operating profitability. For example, the U.S. government could prevent
or restrict exports of refined products, NGLs, natural gas or the conduct of business with certain foreign
countries.

Compliance with and changes in tax laws could materially and adversely impact our financial condition,
results of operations and cash flows.

We are subject to extensive tax liabilities, including federal and state income taxes and transactional taxes such
as excise, sales and use, payroll, franchise, withholding and property taxes. New tax laws and regulations and
changes in existing tax laws and regulations could result in increased expenditures by us for tax liabilities in the
future and could materially and adversely impact our financial condition, results of operations and cash flows.
Additionally, many tax liabilities are subject to periodic audits by taxing authorities, and such audits could
subject us to interest and penalties.

Terrorist attacks aimed at our facilities or that impact our customers or the markets we serve could
adversely affect our business.

The U.S. government has issued warnings that energy assets in general, including the nation’s refining, pipeline
and terminal infrastructure, may be future targets of terrorist organizations. The threat of terrorist attacks has
subjected our operations to increased risks. Any future terrorist attacks 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.

The recent lifting of the U.S. crude oil export ban could adversely affect crack spreads or crude oil price
differentials and have a material adverse effect on our business, financial condition, results of operations
and cash flows.

Since the 1970s, the U.S. has restricted the ability of producers to export domestic crude oil. In December 2015,
U.S. lawmakers passed legislation to lift the crude oil export ban. The lifting of the crude oil export ban may
cause the price of domestic crude oil to rise, potentially impacting crack spreads and price differentials between

domestic and foreign crude oils. A deterioration of crack spreads or price differentials between domestic and
foreign crude oils could have a material adverse effect on our business, financial condition, results of operations
and cash flows.

Risks Relating to Ownership of Our Common Stock

Provisions in our corporate governance documents could operate to delay or prevent a change in control of
our company, dilute the voting power or reduce the value of our capital stock or affect its liquidity.

The existence of some provisions within our restated certificate of incorporation and amended and restated
bylaws could discourage, delay or prevent a change in control of us that a stockholder may consider favorable.
These include provisions:

•

providing that our board of directors fixes the number of members of the board;

providing for the division of our board of directors into three classes with staggered terms;

providing that only our board of directors may fill board vacancies;

limiting who may call special meetings of stockholders;

prohibiting stockholder action by written consent, thereby requiring stockholder action to be taken at a
meeting of the stockholders;

establishing advance notice requirements for nominations of candidates for election to our board of
directors or for proposing matters that can be acted on by stockholders at stockholder meetings;

establishing supermajority vote requirements for certain amendments to our restated certificate of
incorporation and stockholder proposals for amendments to our amended and restated bylaws;

providing that our directors may only be removed for cause;

authorizing a large number of shares of common stock that are not yet issued, which would allow our
board of directors to issue shares to persons friendly to current management, thereby protecting the
continuity of our management, or which could be used to dilute the stock ownership of persons seeking
to obtain control of us; and

authorizing the issuance of “blank check” preferred stock, which could be issued by our board of
directors to increase the number of outstanding shares and thwart a takeover attempt.

We believe these provisions protect our stockholders from coercive or otherwise unfair takeover tactics by
requiring potential acquirers to negotiate with our board of directors and by providing our board of directors time
to assess any acquisition proposal, and are not intended to make us immune from takeovers. However, these
provisions apply even if the offer may be considered beneficial by some stockholders and could delay or prevent
an acquisition.

Our restated certificate of incorporation also authorizes us to issue, without the approval of our stockholders, one
or more classes or series of preferred stock having such designation, powers, preferences and relative,
participating, optional and other special rights,
including preferences over our common stock respecting
dividends and distributions, as our board of directors generally may determine. The terms of one or more classes
or series of preferred stock could dilute the voting power or reduce the value of our common stock. For example,
we could grant holders of preferred stock the right to elect some number of our board of directors in all events or
on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or
redemption rights or liquidation preferences we could assign to holders of preferred stock could affect the
residual value of our common stock.

Finally, to facilitate compliance with the Maritime Laws, our restated certificate of incorporation limits the
aggregate percentage ownership by non-U.S. citizens of our common stock or any other class of our capital stock
to 23 percent of the outstanding shares. We may prohibit transfers that would cause ownership of our common
stock or any other class of our capital stock by non-U.S. citizens to exceed 23 percent. Our restated certificate of
incorporation also authorizes us to effect any and all measures necessary or desirable to monitor and limit foreign
ownership of our common stock or any other class of our capital stock. These limitations could have an adverse
impact on the liquidity of the market for our common stock if holders are unable to transfer shares to non-U.S.
citizens due to the limitations on ownership by non-U.S. citizens. Any such limitation on the liquidity of the
market for our common stock could adversely impact the market price of our common stock.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The location and general character of our refineries, convenience stores and other important physical properties
have been described by segment under Item 1. Business and are incorporated herein by reference. The plants and
facilities have been constructed or acquired over a period of years and vary in age and operating efficiency. In
addition, we believe that our properties and facilities are adequate for our operations and that our facilities are
adequately maintained. As of December 31, 2015, we were the lessee under a number of cancellable and
noncancellable leases for certain properties,
including land and building space, office equipment, storage
facilities and transportation equipment. See Item 8. Financial Statements and Supplementary Data – Note 24 for
additional information regarding our leases.

The following tables set forth certain information relating to our crude and products pipeline systems, storage
assets, gas processing facilities, fractionation facilities, natural gas gathering systems and NGL pipelines as of
December 31, 2015.

MPLX

Pipeline System or Storage Asset

Origin

Destination

Diameter
(inches)

Length
(miles) Capacity(a) Associated MPC refinery

Crude oil pipeline systems (mbpd):

Patoka, IL to Lima, OH crude system
Catlettsburg, KY and Robinson, IL crude

Patoka, IL
Patoka, IL

system

Detroit, MI crude system(b)

Wood River, IL to Patoka, IL crude

system(b)

Inactive pipelines

Total

Samaria &
Romulus, MI
Wood River &
Roxana, IL

Lima, OH
Catlettsburg, KY &
Robinson, IL
Detroit, MI

20”-22”
20”-24”

16”

304
484

249
495

197

Detroit, Canton
Catlettsburg, Robinson

Detroit

Patoka, IL

12”-22”

115

314

All Midwest refineries

Products pipeline systems (mbpd):
Garyville, LA products system
Texas City, TX products system
ORPL products system
Robinson, IL products system(b)
Louisville, KY Airport products system Louisville, KY
Inactive pipelines(b)

Garyville, LA
Texas City, TX
Various
Various

Zachary, LA
Pasadena, TX
Various
Various
Louisville, KY

20”-36”
16”-36”
6”-14”
10”-16”
6”-8”

Total

Wood River, IL barge dock (mbpd)
Storage assets (thousand barrels):
Neal, WV butane cavern(c)
Patoka, IL tank farm
Wood River, IL tank farm
Martinsville, IL tank farm
Lebanon, IN tank farm

Total

1,008

72
42
518
1,171
14
83

1,900

N/A

1,255

Garyville

389
215 Texas City, Galveston Bay
244
582
29
N/A

Catlettsburg, Canton
Robinson
Robinson

1,459

1,000
2,626
419
738
750

5,533

Garyville

Catlettsburg
All Midwest refineries
All Midwest refineries
Detroit, Canton
Detroit, Canton

(a) All capacities reflect 100 percent of the pipeline systems’ and barge dock’s average capacity in thousands of barrels per day and 100

percent of the available storage capacity of our butane cavern and tank farms in thousands of barrels.
Includes pipelines leased from third parties.
The Neal, WV butane cavern is 100 percent owned by MPLX.

(b)

(c)

The throughputs in the following tables are based on days in operation since the MarkWest Merger.

Gas Processing Complexes

Location

Keystone Complex

Houston Complex

Majorsville Complex

Mobley Complex

Sherwood Complex

Cadiz Complex

Seneca Complex

Kenova Complex(d)

Boldman Complex(d)

Cobb Complex

Kermit Complex(d)(e)

Langley Complex

Carthage Complex

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

Western Oklahoma Complex

Custer and Beckham Counties, OK

Javelina Complex

Total

Corpus Christi, TX

Design
Throughput
Capacity
(MMcf/d)(a)

Natural Gas
Throughput
(MMcf/d)(b)(c)

Utilization
of Design
Capacity(b)

410

555

1,070

720

1,200

525

800

160

325

600

425

142

275

320

938

616

815

475

661

111

N/A

516

300

114

7,067

5,273

67%

58%

88%

86%

68%

90%

83%

69%

57%

40%

N/A

20%

86%

71%

80%

75%

(a) Centrahoma processing capacity of 300 MMcf/d is not included in this table as we own a non-operating interest.

(b) 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.

(d) A portion of the gas processed at the Boldman plant, and all of the gas processed at the Kermit plant, is further processed at the Kenova

plant to recover additional NGLs.

(e)

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.

Fractionation Complexes

Location

Keystone Complex(c)(d)

Houston Complex(c)

Hopedale Complex(c)(e)

Ohio Condensate Complex(f)

Siloam Complex(g)

Javelina Complex

Total

Butler County, PA

Washington County, PA

Harrison County, OH

South Shore, KY

Corpus Christi, TX

Design
Throughput
Capacity
(mbpd)

NGL
Throughput
(mbpd)(a)(b)

Utilization
of Design
Capacity(a)

120

285

109

219

21%

103%

91%

74%

50%

82%

77%

(a) 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.

(b) NGL throughput includes volumes from December 4, 2015 to December 31, 2015.

(c)

The MPLX Houston, Hopedale and Keystone Complexes have above ground NGL storage with a usable capacity of 26 million gallons,
large-scale truck and rail loading. In addition, the Houston Complex has large-scale truck unloading. MPLX also has access to up to an
additional 50 million gallons of propane storage capacity that can be utilized in the Marcellus Shale, Utica Shale and Appalachia region
under an agreement with a third party that expires in 2018. Lastly, MPLX has up to nine million gallons of butane storage and eleven
million gallons of propane storage with third parties that can be utilized in the Marcellus Shale and Utica Shale.

(d)

Includes 33 mpbd of de-propanization only capacity.

(e) Our Hopedale Complex is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG, respectively. We account for

MarkWest Utica EMG as an equity method investment.

(f)

The Ohio Condensate Complex is owned by MarkWest Utica EMG Condensate. We account for Ohio Condensate as an equity method
investment.

(g) 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 ten 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 840,000 gallons.

De-ethanization Complexes

Location

Keystone Complex

Houston Complex

Majorsville Complex

Sherwood Complex

Cadiz Complex

Javelina Complex

Total

Butler County, PA

Washington County, PA

Marshall County, WV

Doddridge County, WV

Harrison County, OH

Corpus Christi, TX

Design
Throughput
Capacity
(mbpd)

Natural Gas
Throughput
(mbpd)(a)(b)

Utilization
of Design
Capacity(a)

198

104

50%

53%

105%

32%

15%

83%

54%

(a) 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.

(b) NGL throughput includes volumes from December 4, 2015 to December 31, 2015.

Natural Gas Gathering Systems

Location

Keystone System

Houston System

Butler County, PA

Washington County, PA

Ohio Gathering System(c)

Harrison and Monroe Counties, OH

Jefferson Gas System(d)

Jefferson County, OH

East Texas System

Harrison and Panola Counties, TX

Western Oklahoma System

Southeast Oklahoma System

Eagle Ford System

Other Systems(e)

Total

Wheeler County, TX and Roger
Mills, Ellis, Custer, Beckham and
Washita Counties, OK

Hughes, Pittsburg and Coal Counties,
OK

Dimmit County, TX

Various

Design
Throughput
Capacity
(MMcf/d)

Natural Gas
Throughput
(MMcf/d)(a)(b)

Utilization
of Design
Capacity(a)

227

917

1,291

250

680

585

1,265

200

689

743

628

333

432

5,355

3,075

88%

75%

61%

92%

57%

34%

80%

13%

60%

(a) 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.

(b) NGL throughput includes volumes from December 4, 2015 to December 31, 2015.

(c)

(d)

The Ohio Gathering System is owned by Ohio Gathering, which we account for as an equity method investment.

The Jefferson Gas System is owned by Jefferson Dry Gas, which is a joint venture between MarkWest Liberty Midstream and EMG
MWE Dry Gas Holdings, LLC. We account for Jefferson Dry Gas as an equity method investment.

(e)

Excludes lateral pipelines where revenue is not based on throughput.

NGL Pipeline

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(b)

Houston to Ohio River ethane pipeline(c)

Majorsville to Houston ethane pipeline(b)

Sherwood to Mobley ethane pipeline

Mobley to Fort Beeler ethane pipeline

Fort Beeler to Majorsville ethane pipeline

Seneca to Hopedale liquids pipeline

Langley to Siloam liquids pipeline(d)

East Texas liquids pipeline

Location

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

Langley, KY to South
Shore, KY

Panola County, TX

Design
Throughput
Capacity
(mbpd)

NGL
Throughput
(mbpd)(a)

Utilization
of Design
Capacity

172

69%

28%

89%

56%

22%

29%

26%

83%

33%

14%

20%

15%

53%

69%

(a) NGL throughput includes volumes from December 4, 2015 to December 31, 2015.

(b)

(c)

This pipeline is FERC-regulated.

This is the section of the Mariner West pipeline, which is FERC-regulated, leased to and operated by Sunoco Logistics Partners LP.

(d) NGLs transported through the Langley to Ranger and Ranger to Kenova pipelines are combined with NGLs recovered at the Kenova

facility. The design capacity and volume reported for the Langley to Siloam pipeline represent the combined NGL stream.

Crude Oil Pipeline

Michigan crude pipeline

Location

Manistee County, MI to
Crawford County, MI

Design
Throughput
Capacity
(mbpd)

NGL
Throughput
(mbpd)

Utilization
of Design
Capacity

15%

MPC-Retained Assets and Investments

As of December 31, 2015, we owned undivided joint interests in the following common carrier crude oil pipeline
systems.

Pipeline System

Origin

Destination

Diameter
(inches)

Length
(miles)

Ownership
Interest

Operated
by MPL

Capline

Maumee

Total

St. James, LA Patoka, IL

Lima, OH

Samaria, MI

40”

22”

33%

26%

Yes

644

739

As of December 31, 2015, we had partial ownership interests in the following pipeline companies.

Pipeline Company

Origin

Destination

Diameter
(inches)

Length
(miles)

Ownership
Interest

Operated
by MPL

Crude oil pipeline companies:

Illinois Extension Pipeline

Company LLC

LOCAP LLC

LOOP LLC (LOOP)

North Dakota Pipeline Company

LLC(a)(b)

Total

Products pipeline companies:

Ascension Pipeline Company

Flanagan, IL

Patoka, IL

Clovelly, LA

St. James, LA

24”

48”

168

35%

59%

Offshore Gulf of
Mexico

Clovelly, LA

48”

51%

Plentywood, MT Clearbrook, MN TBD

LLC(a)

Riverside, LA

Garyville

TBD

Centennial Pipeline LLC(c)

Beaumont, TX

Bourbon, IL

24”-26”

Explorer Pipeline Company

Lake Charles, LA Hammond, IN 12”-28”

Muskegon Pipeline LLC

Griffith, IN Muskegon, MI

10”

Wolverine Pipe Line Company

Chicago, IL

Bay City &
Ferrysburg, MI

6”-18”

Total

Yes

38%

TBD

273

50%

25%

60%

TBD

795

1,883

170

743

3,591

(a)

The pipeline diameter and length for these companies will be determined when these pipeline projects are placed into service.

(b) We own 38 percent of the Class B units in this entity. Upon completion of the Sandpiper pipeline project, which is to construct a pipeline
running from Beaver Lodge, North Dakota to Superior, Wisconsin and targeted for completion in early 2019, our Class B units will be
converted to an approximate 27 percent ownership interest in the Class A units of this entity.

(c)

Includes 692 miles of inactive pipeline.

We also own 183 miles of private crude oil pipelines and 658 miles of private refined products pipelines that are
operated by MPL for the benefit of our Refining & Marketing segment on a cost recovery basis. The following
table provides additional information on these assets.

Private Pipeline Systems

Crude oil pipeline systems:

Lima, OH to Canton, OH

St. James, LA to Garyville, LA

Other

Inactive pipelines

Total

Products pipeline systems:

Louisville, KY to Lexington, KY(a)

Woodhaven, MI to Detroit, MI

Illinois pipeline systems

Texas pipeline systems

Ohio pipeline systems

Inactive pipelines

Total

Diameter
(inches)

Length
(miles)

Capacity
(mbpd)

12”-16”

30”

6”-14”

8”

4”

4”-12”

8”

4”-12”

153

183

118

103

267

658

620

N/A

720

N/A

164

(a) We own a 65 percent undivided joint interest in the Louisville, KY to Lexington, KY system.

As of December 31, 2015, we owned or leased 60 private tanks with storage capacity of approximately
6.5 million barrels, which are located along MPL and ORPL pipelines.

Item 3. Legal Proceedings

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 July 2015, a purported class action lawsuit asserting claims challenging the MarkWest Merger was filed in the
Court of Chancery of the State of Delaware by a purported unitholder of MarkWest. In August 2015, two similar
putative class action lawsuits were filed in the Court of Chancery of the State of Delaware by plaintiffs who
purport to be unitholders of MarkWest. On September 9, 2015, these lawsuits were consolidated into one action
pending in the Court of Chancery of the State of Delaware, now captioned In re MarkWest Energy Partners, L.P.
Unitholder Litigation. On October 1, 2015, the plaintiffs filed a consolidated complaint against the individual

members of the board of directors of MarkWest Energy GP, L.L.C. (the “MarkWest GP Board”), MPLX, MPLX
GP LLC, the general partner of MPLX (“MPLX GP”) MPC and Sapphire Holdco LLC, a wholly-owned
subsidiary of MPLX, asserting in connection with the MarkWest Merger and related disclosures that, among
other things, (i) the MarkWest GP Board breached its duties in approving the MarkWest Merger with MPLX and
(ii) MPC, MPLX, MPLX GP, and Sapphire Holdco LLC aided and abetted such breaches. On February 4, 2016,
the Court approved a stipulation and proposed order to dismiss all claims with prejudice as to the named
plaintiffs, but for the Court to retain jurisdiction to adjudicate an application for a mootness fee by the plaintiffs’
counsel for an award of attorneys’ fees and reimbursement of expenses. We intend to vigorously defend against
any application for a mootness fee and do not expect the resolution of such matter to have a material adverse
effect.

In May 2015, the Kentucky attorney general filed a lawsuit against our wholly-owned subsidiary, Marathon
Petroleum Company LP (“MPC LP”), in the United States District Court for the Western District of Kentucky
asserting claims under federal and state antitrust statutes, the Kentucky Consumer Protection Act, and state
common law. The complaint, as amended in July 2015, alleges that MPC LP used deed restrictions, supply
agreements with customers and exchange agreements with competitors to unreasonably restrain trade in areas
within Kentucky and seeks declaratory relief, unspecified damages, civil penalties, restitution and disgorgement
of profits. At this early stage, the ultimate outcome of this litigation remains uncertain, and neither the likelihood
of an unfavorable outcome nor the ultimate liability, if any, can be determined, and we are unable to estimate a
reasonably possible loss (or range of loss) for this matter. We intend to vigorously defend ourselves in this
matter.

In May 2007, the Kentucky attorney general filed a lawsuit against us and Marathon Oil in state court in Franklin
County, Kentucky for alleged violations of Kentucky’s emergency pricing and consumer protection laws
following Hurricanes Katrina and Rita in 2005. The lawsuit alleges that we overcharged customers by $89
million during September and October 2005. The complaint seeks disgorgement of these sums, as well as
penalties, under Kentucky’s emergency pricing and consumer protection laws. We are vigorously defending this
litigation. We believe that this is the first lawsuit for damages and injunctive relief under the Kentucky
emergency pricing laws to progress this far and it contains many novel issues. In May 2011, the Kentucky
to include a request for immediate injunctive relief as well as
attorney general amended his complaint
unspecified damages and penalties related to our wholesale gasoline pricing in April and May 2011 under
statewide price controls that were activated by the Kentucky governor on April 26, 2011 and which have since
expired. The court denied the attorney general’s request for immediate injunctive relief, and the remainder of the
2011 claims likely will be resolved along with those dating from 2005. If the lawsuit is resolved unfavorably in
its entirety, it could materially impact our consolidated results of operations, financial position or cash flows.
However, management does not believe the ultimate resolution of this litigation will have a material adverse
effect.

Environmental Proceedings

On February 17, 2016, MarkWest Liberty Bluestone, L.L.C., a wholly-owned subsidiary of MPLX (“MarkWest
Liberty Bluestone”), received a draft Consent Agreement and Final Order (“CAFO”) from the EPA alleging
violations of the Clean Air Act arising from an EPA compliance inspection conducted in July 2012 at our Sarsen
Facility, a gas processing facility located in Pennsylvania. This inspection occurred shortly after MarkWest
Liberty Bluestone had acquired the facility from a third party and we were already conducting an internal self-
assessment audit. The CAFO alleges certain violations including the failure to comply with monitoring, tagging,
recordkeeping and repair requirements with respect to certain pumps and/or valves at the facility. The alleged
violations also include the failure to comply with certain emissions reduction and permit application
requirements. The CAFO sets forth a proposed civil penalty of $285,078. MarkWest Liberty Bluestone believes
there are substantial defenses and disputable issues regarding the alleged claims and the proposed penalty as set
forth in the CAFO and MarkWest Liberty Bluestone will be asserting those defenses and issues in discussions
with the EPA.

As previously disclosed, in August 2012 the Federal District Court in Michigan entered our Flare Consent Decree
with the EPA that included a civil penalty of $460,000 and injunctive relief designed to ensure good combustion
and flare minimization practices were employed at 22 flares located at six of our refineries. We have since
requested an amendment to the Flare Consent Decree to provide an extension of time to install flare gas recovery
systems as required under the existing Flare Consent Decree. In February 2016, the United States Department of
Justice informed us the amendment to the Flare Consent Decree could include a civil penalty in excess of
$100,000.

In January 2016, the Michigan Department of Environmental Quality (“MDEQ”) issued an Enforcement Notice
to MPC LP indicating MDEQ intends to pursue enforcement for two Violation Notices issued to MPC LP in
2015. The Violation Notices both allege exceedances of air emissions limitations at our Detroit refinery. It is
possible the MDEQ could seek penalties in excess of $100,000 in connection with this matter.

On July 6, 2015, officials from the EPA and the United States Department of Justice entered a pipeline launcher/
receiver site utilized for pipeline pigging operations in Washington County, Pennsylvania of MarkWest Liberty
Midstream & Resources, L.L.C., a wholly-owned subsidiary of MPLX (“MarkWest Liberty Midstream”),
pursuant to a search warrant issued by the United States District Court for the Western District of Pennsylvania.
At the conclusion of the search, the governmental officials presented MarkWest Liberty Midstream with a
subpoena to provide documents related to the design, construction, operation, maintenance, modification,
inspection, assessment, repair of, and/or emissions from MarkWest Liberty Midstream’s pipeline facilities
located in Pennsylvania. MarkWest Liberty Midstream is providing information in response to the subpoena and
related requests for information from the relevant agencies, and is in discussions with the relevant agencies
regarding issues associated with the search and subpoena and its operations of, or supplementary permitting
obligations for, its pipeline facilities in the Northeast. Immediately following the July 6, 2015 search, MarkWest
Liberty Midstream commenced its own assessment of its operations of launcher/receiver facilities. MarkWest
Liberty Midstream’s review to date has determined that other than potentially having to obtain minor source
permits at a relatively small number of individual sites, MarkWest Liberty Midstream’s operations have been
conducted in a manner fully protective of its employees and the public, and in substantial compliance with
applicable laws and regulations. It is possible that, in connection with any potential civil or criminal enforcement
action associated with this matter, MarkWest Liberty Midstream will incur material assessments, penalties or
fines, incur material defense costs and expenses, be required to modify our operations or construction activities
which could increase operating costs and capital expenditures, or be subject to other obligations or restrictions
that could restrict or prohibit our activities, any or all of which could adversely affect our consolidated results of
operations, financial position or cash flows. The amount of any potential assessments, penalties, fines,
requirements, modifications, costs or expenses that may be incurred in connection with any potential
enforcement action cannot be reasonably estimated at this time.

On March 21, 2014, MarkWest Liberty Midstream received a Draft Consent Order from the West Virginia
Department of Environmental Protection (“WVDEP”) incorporating 16 separate inspections in 2013 of various
operations and construction sites with claimed regulatory violations relating to erosion and sediment control
measures, damage in 2013 to a portion of the Marcellus NGL pipeline in Wetzel County, West Virginia which
resulted from landslides and associated issues, pipeline borings and other disparate matters. The Draft Consent
Order aggregated those matters and proposed a total aggregate administrative penalty of $115,120 for all of the
various alleged claims, as well as the development of an approved remediation plan and certain provisions for
approval of pipeline boring plans and other construction related activities in West Virginia going forward.
MarkWest Liberty Midstream and WVDEP entered into a final Consent Order resolving all alleged violations,
which became effective on November 2, 2015. Pursuant
to the final Consent Order, MarkWest Liberty
Midstream paid a penalty of $76,450 and submitted a corrective action plan to the WVDEP, and will periodically
provide the WVDEP with information relating to slips impacting or having the potential to impact waters of the
State of West Virginia.

On January 3, 2013, the Louisiana Department of Environmental Quality (“LDEQ”) issued a consolidated
compliance order and notice of potential penalty alleging violations related to self-reported air emission events
occurring at our Garyville, Louisiana refinery between the years of 2005 and 2011. In January 2016, we settled
this matter with LDEQ by agreeing to reimburse LDEQ for $27,500 in costs incurred and pay $765,000 to fund a
beneficial environmental project. The settlement also resolved self-reported events occurring during 2012 and
2013.

During 2001, we entered into a New Source Review consent decree and settlement of alleged Clean Air Act and
other violations with the EPA covering our refineries. The settlement committed us to specific control
technologies and implementation schedules for environmental expenditures and improvements to our refineries,
which are now complete. We are working with the EPA to terminate the New Source Review consent decree.

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.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities

Our common stock is listed on the NYSE and traded under the symbol “MPC.” As of February 12, 2016, there
were 35,819 registered holders of our common stock.

The following table reflects intraday high and low sales prices of and dividends declared on our common stock
by quarter:

Dollars per share

Quarter 1

Quarter 2

Quarter 3

Quarter 4

Year

High
Price

2015

Low
Price

Dividends

High
Price

2014

Low
Price

Dividends

54.16

37.62

53.07

60.38

59.99

60.38

48.41

43.42

46.03

37.62

0.25

0.32

1.14

47.44

40.34

48.85

46.45

48.97

38.97

37.84

37.32

0.21

0.25

0.92

On April 29, 2015, our board of directors approved a two-for-one stock split in the form of a stock dividend,
which was distributed on June 10, 2015, to shareholders of record at the close of business on May 20, 2015. All
historical share and per share data included in this report have been retroactively restated on a post-split basis.

Dividends

Our board of directors intends to declare and pay dividends on our common stock based on our financial
condition and consolidated results of operations. On January 30, 2016, our board of directors approved a 32 cent
per share dividend, payable March 10, 2016 to stockholders of record at the close of business on February 17,
2016.

Dividends on our common stock are limited to our legally available funds.

Issuer Purchases of Equity Securities

The following table sets forth a summary of our purchases during the quarter ended December 31, 2015, of
equity securities that are registered by MPC pursuant to Section 12 of the Securities Exchange Act of 1934, as
amended:

Period

10/01/15-10/31/15

11/01/15-11/30/15

12/01/15-12/31/15

Total

Total Number
of Shares
Purchased(a)

Average
Price Paid
per Share(b)

1,363,637

1,107,948

1,241,947

3,713,532

48.52

54.17

53.16

51.76

Total Number of
Shares Purchased as
Part of Publicly
Announced Plans
or Programs

Maximum Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans
or Programs(c)

1,360,100

2,887,242,698

1,107,500

1,241,700

3,709,300

2,827,251,439

2,761,241,964

(a)

The amounts in this column include 3,537, 448 and 247 shares of our common stock delivered by employees to MPC, upon vesting of
restricted stock, to satisfy tax withholding requirements in October, November and December, respectively.

(b) Amounts in this column reflect the weighted average price paid for shares purchased under our share repurchase authorizations and for
shares tendered to us in satisfaction of employee tax withholding obligations upon the vesting of restricted stock granted under our stock
plans. The weighted average price includes commissions paid to brokers on shares purchased under our share repurchase authorizations.

(c) On July 30, 2015, we announced that our board of directors had approved an additional $2.0 billion share repurchase authorization
through July 31, 2017. This authorization is in addition to the previous $2.0 billion authorization announced July 30, 2014 and expiring
on July 31, 2016, which had approximately $760 million remaining as of December 31, 2015.

Item 6. Selected Financial Data

Selected financial data for periods subsequent to our June 2011 Spinoff from Marathon Oil were derived from
our consolidated financial statements. Selected financial data for periods prior to the Spinoff were derived from
the results of the RM&T Business, which represented a combined reporting entity. The following table should be
read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations and Item 8. Financial Statements and Supplementary Data.

(In millions, except per share data)

2015(a)

2014(a)

2013(a)

2012

2011

Year Ended December 31,

Statements of Income Data

Revenues
Income from operations
Net income
Net income attributable to MPC

Per Share Data(b)

Net income attributable to MPC per share:

Basic
Diluted

Dividends per share

Statements of Cash Flows Data

Net cash provided by operating activities
Additions to property, plant and equipment
Acquisitions, net of cash acquired(a)
Common stock repurchased
Dividends paid

(In millions)

Balance Sheets Data(c)

$
$

$ 72,051
4,692
2,868
2,852

$
$

5.29
5.26

1.14

4,061
1,998
1,218
965
613

$
$

97,817
4,051
2,555
2,524

4.42
4.39

0.92

3,110
1,480
2,821
2,131
524

$
$

100,160
3,425
2,133
2,112

3.34
3.32

0.77

3,405
1,206
1,515
2,793
484

December 31,

82,243
5,347
3,393
3,389

$ 78,638
3,745
2,389
2,389

4.97
4.95

0.60

$
$

3.35
3.34

0.225

4,492
1,369
190
1,350
407

$ 3,309
1,185
74
-
160

2015(a)

2014(a)

2013(a)

2012

2011

Total assets
Long-term debt, including capitalized leases(d)

$ 43,115
11,925

30,425
6,602

28,367
3,378

27,203
3,341

$ 25,722
3,284

(a) On December 4, 2015, MPLX merged with MarkWest. On September 30, 2014, we acquired Hess’ Retail Operations and Related
Assets. On February 1, 2013, we acquired the Galveston Bay Refinery and Related Assets. Data presented subsequent to these
acquisitions include amounts for these operations.

(b) We completed a two-for-one stock split in June 2015. All historical per share data has been retroactively restated on a post-split basis.
The number of weighted average shares for 2015, 2014, 2013 and 2012 reflect the impacts of shares of common stock repurchased under
our share repurchase plans.

(d)

(c) We adopted the updated FASB debt issuance cost standard as of June 30, 2015 and applied the changes retrospectively to the prior
periods presented. We reclassified unamortized debt issuance costs related to term debt from other noncurrent assets to long-term debt.
Includes amounts due within one year. During 2011, we issued $3.0 billion aggregate principal amount of senior notes, which replaced a
portion of the debt payable to Marathon Oil and subsidiaries. During 2014, we issued $1.95 billion aggregate principal amount of senior
notes and entered into a $700 million term loan agreement to fund a portion of the Hess’ Retail Operations and Related Assets
acquisition. Also during 2014, MPLX entered into a $250 million term loan agreement and drew upon its credit facility to fund a portion
of its purchase of additional interest in Pipe Line Holdings from MPC. During 2015, MPLX issued $500 million aggregate principal
amount of senior notes and repaid the outstanding amounts under its bank revolving credit facility. In connection with the MarkWest
Merger on December 4, 2015, MPLX 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. Also during 2015, we issued
$1.5 billion aggregate principal amount of senior notes and used $763 million of the net proceeds to extinguish our obligation for the
$750 million aggregate principal amount of our 3.500% senior notes due in 2016.

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.

Corporate Overview

We are an independent petroleum refining and marketing, retail and midstream company. We currently own and
operate seven refineries, all located in the United States, with an aggregate crude oil refining capacity of
approximately 1.8 mmbpcd. Our refineries supply refined products to resellers and consumers within our market
areas, including the Midwest, Northeast, East Coast, Southeast and Gulf Coast regions of the United States. We
distribute refined products to our customers through one of the largest private domestic fleets of inland petroleum
product barges, one of the largest terminal operations in the United States, and a combination of MPC-owned and
third-party-owned trucking and rail assets. We are one of the largest wholesale suppliers of gasoline and
distillates to resellers within our market area.

We have two strong retail brands: Speedway® and Marathon®. We believe that Speedway LLC, a wholly-owned
subsidiary, operates the second largest chain of company-owned and operated retail gasoline and convenience
stores in the United States, with approximately 2,770 convenience stores in 22 states throughout the Midwest,
East Coast and Southeast. The Marathon brand is an established motor fuel brand in the Midwest and Southeast
regions of the United States, and is available through approximately 5,600 retail outlets operated by independent
entrepreneurs in 19 states.

Through our ownership interests in MPLX and its wholly-owned subsidiary, MarkWest, we believe we are one
of the largest processors of natural gas in the United States and the largest processor and fractionator in the
Marcellus and Utica shale regions. Our integrated midstream energy asset network links producers of natural gas
and NGLs from some of the largest supply basins in the United States to domestic and international markets. Our
midstream gathering and processing operations include: natural gas gathering, processing and transportation; and
NGL gathering, transportation, fractionation, storage and marketing. Our assets include approximately 5,400
MMcf/d of gathering capacity, 7,100 MMcf/d of natural gas processing capacity and 500 mbpd of fractionation
capacity as of December 31, 2015. We also own 5,000 miles of gas gathering and NGL pipelines and have
ownership interests in over 50 gas processing plants, over 10 NGL fractionation facilities and one condensate
stabilization facility. As of December 31, 2015, we owned, leased or had ownership interests in approximately
8,400 miles of crude oil and refined product pipelines to deliver crude oil to our refineries and other locations and
refined products to wholesale and retail market areas. Overall, we are one of the largest independent petroleum
product refining, marketing, retail and transportation businesses in the United States and the largest east of the
Mississippi.

Our operations consist of three reportable operating segments: Refining & Marketing; Speedway; and
Midstream. Each of these segments is organized and managed based upon the nature of the products and services
they offer. See Item 1. Business for additional information on our segments.

• Refining & Marketing – refines crude oil and other feedstocks at our seven refineries in the Gulf Coast
and Midwest regions of the United States, purchases refined products and ethanol for resale and
distributes refined products through various means, including barges, terminals and trucks that we own
or operate. We sell
to wholesale marketing customers domestically and
internationally, buyers on the spot market, our Speedway business segment and to independent
entrepreneurs who operate Marathon® retail outlets.

refined products

•

Speedway – sells transportation fuels and convenience products in the retail market in the Midwest,
East Coast and Southeast.

Executive Summary

Results

Select results for 2015 and 2014 are reflected in the following table.

(In millions, except per share data)

Income from Operations by segment

Refining & Marketing

Speedway

Midstream

Net income attributable to MPC

Net income attributable to MPC per diluted share

2015

2014

4,186

3,609

673

289

2,852

5.26

544

280

2,524

4.39

Net income attributable to MPC increased $328 million, or $0.87 per diluted share, in 2015 compared to 2014,
primarily due to our Refining & Marketing segment.

Refining & Marketing segment income from operations increased in 2015 compared to 2014, primarily due to
higher crack spreads, favorable effects of changes in market structure on crude oil acquisition prices, more
favorable net product price realizations compared to spot market reference prices and lower direct operating
costs. These positive impacts were partially offset by unfavorable crude oil and feedstock acquisition costs
relative to benchmark LLS crude oil, the unfavorable effect of lower commodity prices on volumetric gains and a
lower of cost or market (“LCM”) inventory valuation charge of $345 million.

Speedway segment income from operations increased in 2015 compared to 2014, primarily due to the full year
benefit in 2015 from the financial results of the locations acquired along the East Coast and Southeast on
September 30, 2014, as well as higher light product margin.

Midstream segment income from operations increased in 2015 compared to 2014, primarily due to the financial
results of MarkWest, which are reflected in Midstream segment income from the December 4, 2015 merger date,
partially offset by $30 million of merger transaction costs.

MPLX LP

MPLX is a publicly traded master limited partnership that was formed by us to own, operate, develop and acquire
pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and
other hydrocarbon-based products. On December 4, 2015, MPLX merged with MarkWest, whereby MarkWest
became a wholly-owned subsidiary of MPLX.

Prior to the MarkWest Merger, we owned a 71.5 percent interest in MPLX, which included our two percent
general partner interest. Each common unit of MarkWest issued and outstanding at the time of the MarkWest
Merger was converted into the right to receive 1.09 common units of MPLX and as of December 31, 2015, our
ownership interest in MPLX was 20.4 percent, including our two percent general partner interest. Due to our
general partner interest, we have determined that we control MPLX and therefore we consolidate MPLX and
record a noncontrolling interest for the 79.6 percent interest owned by the public.

Upon completion of the MarkWest Merger, MPLX assumed an aggregate principal amount of $4.1 billion in
senior notes issued by MarkWest and MarkWest Energy Finance Corporation. On December 22, 2015, MPLX
completed offers to exchange any and all outstanding MarkWest Senior Notes for (1) up to $4.1 billion aggregate
principal amount of new notes issued by MPLX having the same maturity and interest rates as the MarkWest
Senior Notes and (2) cash of $1 for each $1,000 of principal amount exchanged. As of December 31, 2015, the
exchange was completed on all the MarkWest Senior Notes except for 1.6 percent, or $63 million. In addition,
MarkWest’s existing 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’s bank
revolving credit facility and $93 million in cash.

MPLX’s initial assets consisted of a 51 percent general partner interest in Pipe Line Holdings, which owns a
network of common carrier crude oil and product pipeline systems and associated storage assets in the Midwest
and Gulf Coast regions of the United States, and a 100 percent interest in a butane storage cavern in West
Virginia. We originally retained a 49 percent limited partner interest in Pipe Line Holdings.

On May 1, 2013, we sold a five percent interest in Pipe Line Holdings to MPLX for $100 million, which was
financed by MPLX with cash on hand.

The sales and contribution of our interests in Pipe Line Holdings to MPLX resulted in a change of our ownership
in Pipe Line Holdings, but not a change in control. We accounted for these sales as transactions between entities
under common control and did not record a gain or loss.

On December 8, 2014, MPLX completed a public offering of 3.5 million common units at a price to the public of
$66.68 per common unit, with net proceeds of $221 million. MPLX used the net proceeds from this offering to
repay borrowings under its bank revolving credit facility and for general partnership purposes. On December 10,
2014, we exercised our right to maintain our two percent general partner interest in MPLX by purchasing
130 thousand general partner units for $9 million.

On February 12, 2015, MPLX completed an underwritten public offering of $500 million aggregate principal
amount of four percent unsecured senior notes due February 15, 2025. The Senior Notes were offered at a price

to the public of 99.64 percent of par. The net proceeds of this offering were used by MPLX to repay the amounts
outstanding under its bank revolving credit facility, as well as for general partnership purposes.

On December 4, 2015, we sold our remaining 0.5 percent interest in Pipe Line Holdings to MPLX for $12
million. As a result, MPLX now owns 100 percent of Pipe Line Holdings.

Distributions from MPLX

Upon payment of the second-quarter distribution, the financial tests required for conversion of all of the MPLX
subordinated units, which were owned by a subsidiary of MPC, were met. Accordingly, the subordinated units
converted into common units on a one-for-one basis effective August 17, 2015, the first business day following
the payment of the second quarter distribution.

The following table summarizes the cash distributions we received from MPLX during 2015 and 2014.

(In millions)

Cash distributions received from MPLX:

General partner distributions, including IDRs

Limited partner distributions

Total

2015

2014

118

The market value of the 56.9 million MPLX common units we owned at February 12, 2016 was $1.04 billion
based on the February 12, 2016 closing unit price of $18.30. Over time, we also believe there will be substantial
value attributable to our two percent general partnership interest.

On January 25, 2016, MPLX declared a quarterly cash distribution of $0.50 per common unit, which was payable
February 12, 2016. MPC’s portion of this distribution was approximately $70 million.

See Item 8. Financial Statements and Supplementary Data – Note 4 for additional information on MPLX.

Acquisitions and Investments

On December 4, 2015, MPLX merged with MarkWest, whereby MarkWest became a wholly-owned subsidiary
of MPLX. 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 of MPLX representing limited
partner interests in MPLX, plus a one-time cash payment of $6.20 per unit. Each Class B unit of MarkWest
outstanding immediately prior to the merger was converted into the right to receive one Class B unit of MPLX
having substantially similar rights, including conversion and registration rights, and obligations that the Class B
units of MarkWest had immediately prior to the merger. At closing, we contributed $1.23 billion in cash to
MPLX to pay the cash consideration to MarkWest common unitholders. We will contribute an additional total of
$50 million in cash to MPLX for the cash consideration to be paid upon the conversion of the MPLX Class B
units to MPLX common units in equal installments in July 2016 and July 2017, respectively. These contributions
are with respect to MPC’s existing interests in MPLX (including IDRs) and not in consideration of new units or
other equity interest in MPLX. We assigned the total consideration transferred of $8.6 billion, including the $7.3
billion fair value of the equity consideration and the $1.3 billion of cash contributions, to the fair value of the
assets acquired and liabilities and noncontrolling interest assumed in the MarkWest Merger, with the excess
recorded as goodwill. As a result, we recognized total assets acquired of $11.6 billion, including $8.4 billion of
property, plant and equipment and $2.5 billion of equity investments, and total liabilities and noncontrolling
interests assumed of $5.5 billion, including $4.6 billion of assumed debt. The excess of the total consideration
transferred over the fair value of the net assets acquired of $2.5 billion was recorded as goodwill in our

Midstream segment. Goodwill is not amortized, but rather is tested for impairment annually or more frequently if
warranted due to events or changes in circumstances. See the Critical Accounting Estimates – Impairment
Assessments of Long-Lived Assets, Intangible Assets, Goodwill and Equity Investments section for a discussion
of recent circumstances which may impact the assessment of this goodwill. Our financial results and operating
statistics reflect the results of MarkWest from the date of the acquisition.

In September 2015, we acquired a 50 percent ownership interest in a new joint venture with Crowley Maritime
Corporation through our investment in Crowley Ocean Partners, which is included in our Refining & Marketing
segment. The joint venture will operate and charter four new Jones Act product tankers, most of which will be
leased to MPC. Contributions to the joint venture with respect to each vessel will occur at the vessel’s delivery.
During 2015, we contributed $72 million in connection with delivery of the first two vessels. The remaining two
vessels are expected to be delivered by the third quarter of 2016. We account for our ownership interest in
Crowley Ocean Partners as an equity method investment. See Item 8. Financial Statements and Supplementary
Data – Note 25 for information on our conditional guarantee of the indebtedness of the joint venture and future
contributions to Crowley Ocean Partners.

On September 30, 2014, we acquired from Hess all of its retail locations, transport operations and shipper history
on various pipelines, including approximately 40 mbpd on Colonial Pipeline, for $2.82 billion. We refer to these
assets as “Hess’ Retail Operations and Related Assets” and substantially all of these assets are part of our
Speedway segment. This acquisition significantly expands our Speedway presence from nine to 22 states
throughout the East Coast and Southeast and is aligned with our strategy to grow higher-valued, stable cash flow
businesses. This acquisition also enables us to further leverage our integrated refining and transportation
operations, providing an outlet for assured sales from our refining system. The transaction was funded with a
combination of debt and available cash. Our financial results and operating statistics reflect the results for Hess’
Retail Operations and Related Assets from the date of the acquisition.

In July 2014, we exercised our option to acquire a 35 percent ownership interest in Enbridge Inc.’s SAX pipeline
which runs from Flanagan, Illinois to Patoka, Illinois. This option resulted from our agreement to be the anchor
shipper on the SAX pipeline and our commitment to the Sandpiper pipeline project as discussed below. During
2015, we made contributions of $147 million to Illinois Extension Pipeline to fund our portion of the
construction costs for the SAX project. We have contributed $267 million since project inception. The pipeline
became operational in December 2015. Our investment in the pipeline is included in our Midstream segment.

In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional seven percent interest
in Explorer for $77 million, bringing our ownership interest to 25 percent. Due to this increase in our ownership
percentage, we now account for our investment in Explorer using the equity method of accounting and report
Explorer as a related party. Explorer owns approximately 1,900 miles of refined products pipeline from Lake
Charles, Louisiana to Hammond, Indiana.

In November 2013, we agreed with Enbridge Energy Partners to serve as an anchor shipper for the Sandpiper
pipeline, which will run from Beaver Lodge, North Dakota to Superior, Wisconsin. We also agreed to fund 37.5
percent of the construction of the Sandpiper pipeline project, which is currently estimated to cost $2.6 billion, of
which approximately $1.0 billion is our share. We made contributions of $71 million during 2015 and have
contributed $287 million since project inception. In exchange for our commitment to be an anchor shipper and
our investment in the project, we will earn an approximate 27 percent equity interest in Enbridge Energy
Partners’ North Dakota System when the Sandpiper pipeline is placed into service. The anticipated in-service
date for the pipeline is likely to be delayed to early 2019. The project schedule and cost estimates remain under
review. Enbridge Energy Partners’ North Dakota System currently includes approximately 240 miles of crude oil
gathering pipelines connected to a transportation pipeline that is approximately 730 miles long. We will also
have the option to increase our ownership interest to approximately 30 percent through additional investments in
future system improvements.

Share Repurchases

Since January 1, 2012, our board of directors has approved $10.0 billion in total share repurchase authorizations
and we have repurchased a total of $7.24 billion of our common stock, leaving $2.76 billion available for
repurchases as of December 31, 2015. Under these authorizations, we have acquired 198 million shares at an
average cost per share of $36.65.

Liquidity

As of December 31, 2015, we had cash and cash equivalents of $1.13 billion and no borrowings or letters of
credit outstanding under our $2.5 billion bank revolving credit facility or $1.0 billion trade receivables
securitization facility. As of December 31, 2015, eligible trade receivables supported borrowings of $668 million
under the trade receivable securitization facility. MPLX had $877 million of borrowings outstanding under its $2
billion revolving credit agreement as of December 31, 2015.

The above discussion contains forward-looking statements with respect to the estimated construction costs,
timing and completion of the Sandpiper project and the share repurchase authorizations. Factors that could affect
the estimated construction costs, timing and completion of the Sandpiper pipeline project, include, but are not
limited to, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining
or conditions imposed by necessary government and third-party approvals and other risks customarily associated
with construction projects. Factors that could affect the share repurchase authorizations and the timing of any
repurchases include, but are not limited to, business conditions, availability of liquidity and the market price of
our common stock. These factors, among others, could cause actual results to differ materially from those set
forth in the forward-looking statements.

Overview of Segments

Refining & Marketing

Refining & Marketing segment income from operations depends largely on our Refining & Marketing gross
margin and refinery throughputs.

Our Refining & Marketing gross margin is the difference between the prices of refined products sold and the
costs of crude oil and other charge and blendstocks refined, including the costs to transport these inputs to our
refineries and the costs of products purchased for resale. The crack spread is a measure of the difference between

market prices for refined products and crude oil, commonly used by the industry as a proxy for the refining
margin. Crack spreads can fluctuate significantly, particularly when prices of refined products do not move in the
same relationship as the cost of crude oil. As a performance benchmark and a comparison with other industry
participants, we calculate Midwest (Chicago) and USGC crack spreads that we believe most closely track our
operations and slate of products. LLS prices and a 6-3-2-1 ratio of products (6 barrels of LLS crude oil producing
3 barrels of unleaded regular gasoline, 2 barrels of ultra-low sulfur diesel and 1 barrel of three percent residual
fuel oil) are used for these crack-spread calculations.

Refined product prices have historically moved relative to international crude oil prices like Brent crude. In
recent years, domestic U.S. crude oils, such as WTI and LLS, have traded at prices less than Brent due to the
growth in U.S. crude oil production, logistical constraints and other market factors. These price discounts had
favorably impacted the LLS 6-3-2-1 crack spread. The decline in crude oil prices in 2015 has led to declines in
sequential (month on month) onshore U.S. crude oil production and narrowed the LLS discount to Brent. With
less near term production growth and the end of the ban on U.S. crude oil exports, LLS and Brent are expected to
trade near parity.

Our refineries can process significant amounts of sour crude oil, which typically can be purchased at a discount
to sweet crude oil. The amount of this discount, the sweet/sour differential, can vary significantly, causing our
Refining & Marketing gross margin to differ from crack spreads based on sweet crude oil. In general, a larger
sweet/sour differential will enhance our Refining & Marketing gross margin.

Future crude oil differentials will be dependent on a variety of market and economic factors, as well as U.S.
energy policy.

The following table provides sensitivities showing an estimated change in annual net income due to potential
changes in market conditions.

(In millions, after-tax)

LLS 6-3-2-1 crack spread sensitivity(a) (per $1.00/barrel change)

Sweet/sour differential sensitivity(b) (per $1.00/barrel change)

LLS-WTI differential sensitivity(c) (per $1.00/barrel change)

Natural gas price sensitivity (per $1.00/million British thermal unit change)

$ 450

220

140

(a) Weighted 40 percent Chicago and 60 percent USGC LLS 6-3-2-1 crack spreads and assumes all other differentials and pricing

relationships remain unchanged.
LLS (prompt) – [delivered cost of sour crude oil: Arab Light, Kuwait, Maya, Western Canadian Select and Mars].

(b)

In addition to the market changes indicated by the crack spreads, the sweet/sour differential and the discount of
WTI to LLS, our Refining & Marketing gross margin is impacted by factors such as:

•

the types of crude oil and other charge and blendstocks processed;

our refinery yields;

the selling prices realized for refined products;

the impact of commodity derivative instruments used to hedge price risk;

the cost of products purchased for resale; and

the potential impact of LCM adjustments to inventories in periods of declining prices.

Inventories are stated at the lower of cost or market. Costs of crude oil, refinery feedstocks and refined products
are aggregated on a consolidated basis for purposes of assessing if the LIFO cost basis of these inventories may
have to be written down to market values. At December 31, 2015, market values for these inventories, which

totaled approximately 4.0 billion gallons, were lower than their LIFO cost basis and, as a result, we recorded an
inventory valuation charge of $345 million to cost of revenues to value these inventories at the lower of cost or
market. Based on movements of refined product prices, future inventory valuation adjustments could have a
negative or positive effect to earnings. Such losses are subject to reversal in subsequent periods if prices recover.
In 2016, inventory market values have continued to decline and if they do not recover to December 31, 2015
levels by March 31, 2016, an additional inventory valuation charge would be required in first quarter 2016.

In the fourth quarter 2015, we recorded a LIFO charge of $45 million as a result of decreased levels in refined
products and crude inventory volumes. Since the LIFO costs for these layers were based on 2014 costs, the
liquidation of these layers resulted in a charge to income. In the fourth quarter of 2014, we recognized builds in
our refined product and crude inventories. These builds were based on 2014 costs which were significantly
higher than fourth quarter 2014 costs and resulted in a benefit of approximately $240 million to income. For the
full year, we recognized a LIFO charge of $78 million in 2015 as compared to a LIFO benefit of $265 million in
2014.

Refining & Marketing segment income from operations is also affected by changes in refinery direct operating
costs, which include turnaround and major maintenance, depreciation and amortization and other manufacturing
expenses. Changes in manufacturing costs are primarily driven by the cost of energy used by our refineries,
including purchased natural gas, and the level of maintenance costs. Planned major maintenance activities, or
turnarounds, requiring temporary shutdown of certain refinery operating units, are periodically performed at each
refinery. The following table lists the refineries that had significant planned turnaround and major maintenance
activities for each of the last three years.

Year Refinery

2015 Catlettsburg, Galveston Bay, Garyville and Robinson

2014 Catlettsburg, Galveston Bay, Garyville and Robinson

2013 Canton, Catlettsburg, Galveston Bay, Garyville and Robinson

The table below sets forth the location and daily crude oil refining capacity of each of our refineries at
December 31 of each year.

Refinery

Garyville, Louisiana

Galveston Bay, Texas City, Texas

Catlettsburg, Kentucky

Robinson, Illinois

Detroit, Michigan

Canton, Ohio

Texas City, Texas

Total

Speedway

Crude Oil Refining Capacity (mbpcd)
2013
2014
2015

539

459

273

212

132

522

451

242

212

130

522

451

242

212

123

1,794

1,731

1,714

Our retail marketing gross margin for gasoline and distillate, which is the price paid by consumers less the cost of
refined products, including transportation, consumer excise taxes and bankcard processing fees, impacts the
Speedway segment profitability. Numerous factors impact gasoline and distillate demand throughout the year,
including local competition, seasonal demand fluctuations, the available wholesale supply, the level of economic
activity in our marketing areas and weather conditions. Gasoline demand in PADD 2 is estimated to have grown
for the third consecutive year, increasing by 2.3 percent in 2015 and approaching 2007 levels after climbing by

0.5 percent in 2014. Meanwhile, gasoline demand in PADD 1 is estimated to have grown by 3.0 percent in 2015
after a 2.4 percent increase in 2014, returning to 2010 levels. Continuing economic growth and year-on-year
declines in prices supported gasoline demand. Distillate demand in 2015 was softer than the very strong levels in
2014 which were supported by severe winter temperatures and a very strong harvest season. PADD 2 distillate
demand is estimated to have declined by 2.8 percent in 2015 after climbing by 4.3 percent to a record level in
2014. Despite this decline, PADD 2 demand is estimated to have remained near pre-recession highs. PADD 1
estimated distillate demand declined 1.1 percent for 2016 with unseasonably warm weather in November and
December after climbing by 4.9 percent in 2014. Market demand increases for gasoline and distillate generally
increase the product margin we can realize. The gross margin on merchandise sold at convenience stores
historically has been less volatile and has contributed substantially to Speedway’s gross margin. More than half
of Speedway’s gross margin was derived from merchandise sales in 2015. Speedway’s convenience stores offer a
wide variety of merchandise, including prepared foods, beverages and non-food items.

Inventories are stated at the lower of cost or market. At December 31, 2015, market values for refined product
inventories were lower than their LIFO cost basis and, as a result, we recorded an inventory valuation charge of
$25 million to cost of revenues to value these inventories at the lower of cost or market. Based on movements of
refined product prices, future inventory valuation adjustments could have a negative or positive effect to
earnings. Such losses are subject to reversal in subsequent periods if prices recover. In 2016, inventory market
values have continued to decline and if they do not recover to December 31, 2015 levels by March 31, 2016, an
additional inventory valuation charge would be required in first quarter 2016.

Midstream

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 our 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.

The profitability of our pipeline transportation operations primarily depends on tariff rates and the volumes
shipped through the pipelines. A majority of the crude oil and refined product shipments on our common carrier
pipelines serve our Refining & Marketing segment. The volume of crude oil that we transport is directly affected
by the supply of, and refiner demand for, crude oil in the markets served directly by our crude oil pipelines. Key
factors in this supply and demand balance are the production levels of crude oil by producers in various regions
or fields, the availability and cost of alternative modes of transportation, the volumes of crude oil processed at
refineries and refinery and transportation system maintenance levels. The volume of refined products that we
transport is directly affected by the production levels of, and user demand for, refined products in the markets
served by our refined product pipelines. In most of our markets, demand for gasoline and distillate peaks during
the summer driving season, which extends from May through September of each year, and declines during the
fall and winter months. As with crude oil, other transportation alternatives and system maintenance levels
influence refined product movements.

Results of Operations

Consolidated Results of Operations

(In millions)

2015

2014

Revenues and other income:

Sales and other operating revenues (including

2015 vs.
2014
Variance

2014 vs.
2013
Variance

2013

consumer excise taxes)

72,051

97,817

(25,766)

100,160

(2,343)

Income from equity method investments

Net gain on disposal of assets

Other income

112

153

111

(65)

(14)

117

Total revenues and other income

72,258

98,102

(25,844)

100,254

(2,152)

Costs and expenses:

Cost of revenues (excludes items below)

55,583

83,770

(28,187)

87,401

(3,631)

Purchases from related parties

Inventory market valuation charge

Consumer excise taxes

Depreciation and amortization

Selling, general and administrative expenses

Other taxes

Total costs and expenses

Income from operations

Net interest and other financial income (costs)

Income before income taxes

Provision for income taxes

Net income

308

370

7,692

1,646

1,576

391

67,566

4,692

(318)

4,374

1,506

2,868

505

6,685

1,326

1,375

390

94,051

4,051

(216)

3,835

1,280

2,555

Less net income attributable to noncontrolling

interests

(197)

370

1,007

320

201

(26,485)

641

(102)

539

226

313

(15)

357

6,263

1,220

1,248

340

96,829

3,425

(179)

3,246

1,113

2,133

Net income attributable to MPC

2,852

2,524

328

2,112

148

422

106

127

(2,778)

626

(37)

589

167

422

412

Net income attributable to MPC increased $328 million in 2015 compared to 2014 and increased $412 million in
2014 compared to 2013, primarily due to our Refining & Marketing segment income from operations, which
increased $577 million in 2015 compared to 2014 and $403 million in 2014 compared to 2013. The increase in
Refining & Marketing segment income from operations in 2015 was primarily due to higher crack spreads,
favorable effects of changes in market structure on crude oil acquisition prices, more favorable net product price
realizations compared to spot market reference prices and lower direct operating costs. These positive impacts
were partially offset by unfavorable crude oil and feedstock acquisition costs relative to benchmark LLS crude
oil, the unfavorable effect of lower commodity prices on volumetric gains and an LCM inventory valuation
charge of $345 million. The increase in 2014 was primarily due to more favorable net product price realizations
and higher USGC and Chicago crack spreads, partially offset by narrower crude oil differentials and higher
turnaround and other direct operating costs.

Sales and other operating revenues (including consumer excise taxes) decreased $25.77 billion in 2015 compared
to 2014 and $2.34 billion in 2014 compared to 2013. The decrease in 2015 was primarily due to lower refined
product sales prices partially offset by increases in refined product sales volumes. The decrease in 2014 was
primarily due to lower refined product sales prices, partially offset by an increase in refined product sales

volumes and higher merchandise sales for our Speedway segment primarily attributable to the convenience stores
acquired along the East Coast and Southeast. MPC consolidated refined product sales increased 163 mbpd in
2015 compared to 2014 and 52 mbpd in 2014 compared to 2013.

Income from equity method investments decreased $65 million in 2015 compared to 2014 and increased $117
million in 2014 compared to 2013. The decrease in 2015 was primarily due to decreases in income from our
ethanol affiliates of $69 million, mainly due to lower ethanol prices. The increase in 2014 was primarily due to
increases in income from our ethanol affiliates of $68 million and income from our pipeline affiliates of $49
million. The increase in income from our ethanol affiliates includes the affects of our acquisition of interests in
TAAE, TACE and TAEI in August 2013. The higher income from our pipeline affiliates is primarily due to
increases from LOOP and Explorer, which is now accounted for as an equity method investment following our
acquisition of an increased ownership interest in this pipeline company.

Net gain on disposal of assets decreased $14 million in 2015 compared to 2014 and increased $15 million in
2014 compared to 2013, primarily due to the sale of two terminals and terminal assets in 2014.

Other income increased $1 million in 2015 compared to 2014 and $59 million in 2014 compared to 2013. Other
income in 2015 was comparable to 2014. The increase in 2014 was primarily due to higher gains on sales of
excess RINs of $74 million, partially offset by an $11 million impairment in 2014 of an investment in a company
accounted for using the cost method.

Cost of revenues decreased $28.19 billion in 2015 compared to 2014 and decreased $3.63 billion in 2014
compared to 2013. The decrease in 2015 was primarily due to:

•

a decrease in refined product cost of sales of $32.2 billion, primarily due to a decrease in our average
crude oil costs of $43.97 per barrel, partially offset by an increase in refined product sales volumes;
and

decreases in refinery direct operating costs of $726 million, or $1.40 per barrel of total refinery
throughput, primarily due to significantly lower turnaround activity in 2015 and decreases in other
manufacturing costs.

The decrease in 2014 was primarily due to:

•

a decrease in refined product cost of sales of $5.01 billion, primarily due to a decrease in our average
crude oil costs of $9.30 per barrel, partially offset by an increase in refined product sales volumes;

partially offset by a increase in refinery direct operating costs of $913 million, or $1.37 per barrel of
total refinery throughput, which included costs associated with significant planned turnaround activity;
and

an increase in merchandise cost of sales for our Speedway segment of $327 million, primarily
attributable to the convenience stores acquired from Hess.

Purchases from related parties decreased $197 million in 2015 compared to 2014 and increased $148 million in
2014 compared 2013. The decrease in 2015 was primarily due to decreases in prices and volumes of ethanol
purchases from TAME, TACE and TAAE of $149 million, decreases in volumes purchased from LOOP of $36
million and decreases in volumes purchased from Explorer of $19 million. The increase in 2014 was primarily
due to acquisitions of ownership interests in TAAE in August 2013 and Explorer in March 2014, resulting in
purchases from these companies totaling $118 million in 2014 and $24 million in 2013, being reported as
purchases from related parties while purchases from these companies prior to these acquisitions were reported as
cost of revenues. In addition, we also had an increase in purchases from LOOP of $45 million in 2014.

Consumer excise taxes increased $1.01 billion in 2015 compared to 2014 and $422 million in 2014 compared
2013, primarily due to increases in taxable refined product sales volumes, including the effects of the acquisition
of Hess’ Retail Operations and Related Assets.

Depreciation and amortization increased $320 million in 2015 compared to 2014 and $106 million in 2014
compared to 2013. The increase in 2015 was primarily due to an impairment charge of $144 million related to the
cancellation of the ROUX project at our Garyville refinery and the depreciation of the fair value of assets
acquired along the East Coast and Southeast on September 30, 2014 by our Speedway segment. The increase in
2014 was primarily due to completion of certain capital investments at our Galveston Bay refinery, an increase in
the number of convenience stores in our Speedway segment and the implementation of corporate-level
information technology projects, partially offset by an impairment of a light products terminal in 2013.

Selling, general and administrative expenses increased $201 million in 2015 compared to 2014 and $127 million
in 2014 compared to 2013. The increase in 2015 was primarily due to increases in employee benefit costs,
contract services and additional expenses related to the convenience stores acquired along the East Coast and
Southeast, partially offset by a decrease in pension settlement expenses. The increase in 2014 was primarily due
to increases in contract services, employee compensation and benefit expenses and credit card processing fees.

Other taxes increased $1 million in 2015 compared to 2014 and increased $50 million in 2014 compared to 2013.
Other taxes in 2015 were comparable to 2014. The increase in the 2014 was primarily due to increases in
property taxes of $30 million, payroll taxes of $27 million and environmental taxes of $11 million, partially
offset by decreases in other tax expenses. These increases were attributable to a number of factors including the
acquisitions of the Galveston Bay Refinery and Related Assets and Hess’ Retail Operations and Related Assets
and the absence of a Federal Oil Spill Tax refund received in 2013.

Net interest and other financial costs increased $102 million in 2015 compared to 2014 and $37 million in 2014
compared to 2013. The increase in 2015 was primarily due to senior notes issued by MPC in September 2014 to
finance the acquisition of Hess’ Retail Operations and Related Assets, higher levels of borrowings on MPLX’s
bank revolving credit facility used to fund the acquisition of Pipe Line Holdings and interest on the debt assumed
from MarkWest. The increase in 2014 was primarily due to an increase in long-term debt related to the
acquisition of Hess’ Retail Operations and Related Assets and MPLX’s acquisition of additional interest in Pipe
Line Holdings. We capitalized interest of $37 million in 2015, $27 million in 2014 and $28 million in 2013. See
Item 8. Financial Statements and Supplementary Data – Note 19 for further details.

Provision for income taxes increased $226 million in 2015 compared to 2014 and $167 million in 2014 compared
to 2013, primarily due to our income before income taxes, which increased $539 million in 2015 compared to
2014 and $589 million in 2014 compared to 2013. The effective tax rates in 2015, 2014 and 2013 are slightly less
than the U.S. statutory rate of 35 percent primarily due to certain permanent benefit differences, including the
domestic manufacturing deduction, partially offset by state and local
tax expense. See Item 8. Financial
Statements and Supplementary Data – Note 12 for further details.

Segment Results

Revenues

Revenues are summarized by segment in the following table.

(In millions)

Refining & Marketing

Speedway

Midstream

Segment revenues

Items included in both revenues and costs:

Consumer excise taxes

2015

2014

2013

64,192

91,734

19,693

751

84,636

7,692

16,932

597

109,263

6,685

94,910

14,475

537

109,922

6,263

Refining & Marketing segment revenues decreased $27.54 billion in 2015 compared to 2014 and $3.18 billion in
2014 compared to 2013. The decreases were primarily due to lower refined product sales prices, partially offset
by increases in refined product sales volumes. The table below shows our Refining & Marketing segment refined
product sales volumes and prices.

Refining & Marketing segment:

Refined product sales volumes (thousands of barrels per day)(a)

Refined product sales destined for export (thousands of barrels per day)

2,289

319

2,125

275

Average refined product sales prices (dollars per gallon)

1.74 $

2.71 $

2,075

218

2.87

2015

2014

2013

(a)

Includes intersegment sales and sales destined for export.

The table below shows the average refined product benchmark prices for our marketing areas.

(Dollars per gallon)

Chicago spot unleaded regular gasoline

Chicago spot ultra-low sulfur diesel

USGC spot unleaded regular gasoline

USGC spot ultra-low sulfur diesel

2015

2014

2013

1.60

1.62

1.55

1.58

2.55

2.80

2.49

2.71

2.76

3.01

2.69

2.97

Refining & Marketing intersegment sales to our Speedway segment increased $1.11 billion in 2015 compared to
2014 and $1.62 billion in 2014 compared to 2013. The increases in intersegment refined product sales and sales
volumes were primarily due to sales to the approximate 1,245 convenience stores acquired in September 2014
along the East Coast and Southeast.

Refining & Marketing intersegment sales to Speedway:

Intersegment sales (in millions)

Refined product sales volumes (millions of gallons)

Average refined product sales prices (dollars per gallon)

2015

2014

2013

12,018 $

10,912 $

5,873

3,766

1.74 $

2.89 $

9,294

2,976

3.11

Speedway segment revenues increased $2.76 billion in 2015 compared to 2014 and increased $2.46 billion in
2014 compared to 2013, primarily due to increases in gasoline and distillate sales of $1.43 billion and $1.98
billion, respectively, and increases in merchandise sales of $1.27 billion and $476 million, respectively. The
increases in gasoline and distillate sales were primarily due to volume increases of 2.1 billion gallons and
796 million gallons, respectively, primarily due to increases in the number of convenience stores, as noted in the
table below, partially offset by decreases in gasoline and distillate selling prices of $0.89 per gallon and $0.20 per
gallon, respectively. The increases in merchandise sales were primarily due to increases in the number of
convenience stores and higher same store sales. The increase in the number of convenience stores for 2014 was
primarily due to the acquisition of convenience stores along the East Coast and Southeast.

The following table includes certain revenue statistics for the Speedway segment.

Convenience stores at period-end

Gasoline & distillate sales (millions of gallons)

Average gasoline & distillate sales prices (dollars per gallon)

Merchandise sales (in millions)

Same store gasoline sales volume (period over period)

Same store merchandise sales (period over period)(a)

(a)

Excludes cigarettes.

2015

2014

2013

2,766

6,038

2.36

4,879

(0.3)%

4.1%

2,746

3,942

3.25

3,611

(0.7)%

5.0%

1,478

3,146

3.45

3,135

0.5%

4.3%

Midstream segment revenue increased $154 million in 2015 compared to 2014 and $60 million in 2014
compared to 2013. The increase in 2015 was primarily due to the financial results of MarkWest, which are
reflected in Midstream segment income from the December 4, 2015 merger date. The increase in 2014 was
primarily due to an increase in revenue related to volume deficiency credits and higher average tariffs received
on crude oil and refined products shipped, partially offset by lower refined products and crude oil pipeline
throughput volumes.

The following table shows operating statistics for our Midstream segment.

Midstream Operating Statistics

Crude oil and refined product pipeline throughputs (mbpd)(a)

Gathering system throughput (MMcf/d)(b)

Natural gas processed (MMcf/d)(b)

C2 (ethane) + NGLs fractionated (mbpd)(b)

2015

2,191

3,075

5,468

307

(a) On owned common-carrier pipelines, excluding equity method investments.
(b) Beginning December 4, 2015, which was the effective date of the MarkWest Merger.

2014

2,119

2013

2,204

Income from Operations

Income before income taxes and income from operations by segment are summarized in the following table.

(In millions)

Income from operations by segment:

Refining & Marketing

Speedway

Midstream(a)

Items not allocated to segments:

Corporate and other unallocated items(a)

Pension settlement expenses(b)
Impairment(c)

Income from operations

Net interest and other financial income (costs)

Income before income taxes

2015

2014

2013

4,186

3,609

3,206

673

289

(308)

(4)
(144)

4,692

(318)

544

280

(286)

(96)
-

4,051

(216)

375

210

(271)

(95)
-

3,425

(179)

4,374

3,835

3,246

(a)

(b)

(c)

Included in the Midstream segment for 2015, 2014 and 2013 are $20 million, $19 million and $20 million, respectively, of corporate
overhead expenses attributable to MPLX. These expenses are not currently allocated to other segments.
See Item 8. Financial Statements and Supplementary Data – Note 22.
See Item 8. Financial Statements and Supplementary Data – Note 15.

Refining & Marketing segment income from operations increased $577 million in 2015 compared to 2014 and
increased $403 million in 2014 compared to 2013. The increase in Refining & Marketing segment income from
operations in 2015 was primarily due to higher crack spreads, favorable effects of changes in market structure on
crude oil acquisition prices, more favorable net product price realizations compared to spot market reference
prices and lower direct operating costs. These positive impacts were partially offset by unfavorable crude oil and
feedstock acquisition costs relative to benchmark LLS crude oil, the unfavorable effect of lower commodity
prices on volumetric gains and an LCM inventory valuation charge of $345 million. The increase in 2014 was
primarily due to more favorable net product price realizations and higher USGC and Chicago crack spreads,
partially offset by narrower crude oil differentials and higher turnaround and other direct operating costs.

The following table presents certain market indicators that we believe are helpful in understanding the results of
our Refining & Marketing segment’s business.

(Dollars per barrel)

Chicago LLS 6-3-2-1 crack spread(a)(b)

USGC LLS 6-3-2-1 crack spread(a)

Blended 6-3-2-1 crack spread(a)(c)

LLS

WTI

LLS – WTI crude oil differential(a)

Sweet/Sour crude oil differential(a)(d)

2015

2014

2013

10.67

9.11

9.70

52.35

48.76

3.59

6.10

9.56

7.23

8.11

96.90

92.91

3.99

6.97

8.16

6.24

6.97

107.38

98.05

9.33

8.53

(a) All spreads and differentials are measured against prompt LLS.
(b) Calculation utilizes USGC three percent residual fuel oil price as a proxy for Chicago three percent residual fuel oil price.
(c) Blended Chicago/USGC crack spread is 38/62 percent in 2015, 38/62 percent in 2014 and 38/62 percent in 2013 based on MPC’s

refining capacity by region in each period.
LLS (prompt) – [delivered cost of sour crude oil: Arab Light, Kuwait, Maya, Western Canadian Select and Mars].

(d)

Based on the market indicators above and our refinery throughputs, we estimate the following impacts on
Refining & Marketing segment income from operations for 2015 compared to 2014 and for 2014 compared to
2013:

• The Chicago LLS 6-3-2-1 crack spread increased $1.11 per barrel in 2015 compared to 2014 and
increased $1.40 in 2014 compared to 2013, which had positive impacts on segment income of $400
million and $354 million, respectively.

• The USGC LLS 6-3-2-1 crack spread increased $1.88 per barrel in 2015 compared to 2014 and
increased $0.99 per barrel in 2014 compared to 2013 which had positive impacts on segment income of
$940 million and $407 million, respectively.

• The LLS-WTI crude oil differential narrowed $0.40 per barrel in 2015 compared to 2014. This
decrease was offset by an increase in volume resulting in a positive impact on segment income of $6
million. The LLS-WTI crude oil differential narrowed $5.34 per barrel in 2014 compared to 2013,
which had negative impacts on segment income of $695 million.

• The sweet/sour crude oil differential narrowed $0.87 per barrel in 2015 compared to 2014 and $1.56
per barrel in 2014 compared to 2013, which had negative impacts on segment income of $27 million
and $489 million, respectively.

The market indicators shown above use spot market values and an estimated mix of crude purchases and products
sold. Differences in our results compared to these market indicators, including product price realizations, mix and
crude costs as well as the effects of market structure on our crude oil acquisition prices, and other items like
refinery yields and other feedstock variances, had an estimated negative impact on Refining & Marketing
segment income of $1.03 billion in 2015 compared to 2014 and an estimated positive impact $1.35 billion in

2014 compared to 2013. We estimate the negative impact for 2015 was primarily due to unfavorable crude oil
acquisition costs relative to LLS, the unfavorable effect of lower commodity prices on volumetric gains, the price
differential of charge and blend stock relative to crude oil and the LCM inventory valuation charge, partially
offset by changes in market structure and refined product selling prices. We estimate the positive impact for 2014
was primarily due to more favorable net product price realizations as compared to spot market values and a LIFO
accounting benefit.

In the fourth quarter of 2015, we recorded a LIFO charge of $45 million as a result of decreased levels in refined
products and crude inventory volumes. Since the LIFO costs for these layers were based on 2014 costs, the
liquidation of these layers resulted in a charge to income. In the fourth quarter of 2014, we recognized builds in
our refined product and crude inventories. These builds were based on 2014 costs which were significantly
higher than fourth quarter 2014 costs and resulted in a benefit of approximately $240 million to income. For the
full year, we recognized a LIFO charge of $78 million in 2015 as compared to LIFO benefits of $265 million in
2014 and $135 million in 2013.

The following table summarizes our refinery throughputs.

Refinery throughputs (thousands of barrels per day):

Crude oil refined

Other charge and blendstocks

Total

Sour crude oil throughput percent

WTI-priced crude oil throughput percent

2015

2014

2013

1,711

177

1,888

1,622

184

1,806

1,589

213

1,802

The following table includes certain key operating statistics for the Refining & Marketing segment.

Refining & Marketing gross margin (dollars per barrel)(a)

Refinery direct operating costs (dollars per barrel):(b)

Planned turnaround and major maintenance

Depreciation and amortization

Other manufacturing(c)

Total

2015

2014

2013

15.25

15.05

1.13

1.39

4.15

6.67

1.80

1.41

4.86

8.07

13.24

1.20

1.36

4.14

6.70

(a)

(b)

(c)

Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs. Excludes the LCM inventory
valuation charge.

Per barrel of total refinery throughputs.

Includes utilities, labor, routine maintenance and other operating costs.

Refinery direct operating costs decreased $1.40 per barrel in 2015 compared to 2014 and increased $1.37 per
barrel in 2014 compared to 2013, which include a decrease in planned turnaround and major maintenance costs
of $0.67 per barrel and an increase of $0.60 per barrel, respectively, and a decrease in other manufacturing costs
of $0.71 per barrel and an increase of$0.72 per barrel, respectively. The decrease in planned turnaround and
major maintenance costs for 2015 was primarily attributable to the Galveston Bay, Robinson and Garyville
refineries, partially offset by an increase at the Detroit refinery. The increase in planned turnaround and major
maintenance costs for 2014 was primarily attributable to the Galveston Bay, Robinson and Catlettsburg
the Garyville and Canton refineries. The decrease in other
refineries, partially offset by decreases at

manufacturing costs was primarily attributable to lower energy costs and routine maintenance costs for 2015. The
increase in other manufacturing costs was primarily attributable to higher energy costs, catalyst expenses and
routine maintenance costs for 2014.

We purchase RINs to satisfy a portion of our RFS2 compliance. Our expenses associated with purchased RINs
were $212 million in 2015, $141 million in 2014 and $264 million in 2013. The increase in 2015 was primarily
due to a $46 million charge in the second quarter to recognize increased estimated costs for compliance based on
the renewable fuel standards for 2014 and 2015 proposed by the EPA in May 2015 and finalized in November
2015, particularly those for bio-mass based diesel and advanced biofuels. The remaining increase was primarily
due to increased purchases of biomass based diesel RINs, at an increased average cost in 2015 as compared to
2014, partially offset by decreased purchases of ethanol RINs, at a decreased average cost in 2015 as compared
to 2014. The decrease in 2014 was primarily due to decreases in the average cost of ethanol and biomass-based
biodiesel RINs and decreases in our estimated advanced biofuel and ethanol obligation volumes.

Speedway segment income from operations increased $129 million in 2015 compared to 2014 and $169 million
in 2014 compared to 2013, primarily due to increases in our gasoline and distillate gross margin of $401 million
and $246 million, respectively, and increases in our merchandise gross margin of $393 million and $150 million,
respectively, partially offset by higher operating expenses. The increases were primarily attributable the full year
effect of the locations acquired along the East Coast and Southeast on September 30, 2014. The increases in
merchandise gross margin were related to a combination of higher merchandise and food sales and improved
margins. In the fourth quarter of 2015, we recognized an LCM inventory valuation charge of $25 million.

The following table includes margin statistics for the Speedway segment.

Gasoline & distillate gross margin (dollars per gallon)(a)

Merchandise gross margin (in millions)

Merchandise gross margin percent

2015

0.1823

1,368

28.0%

2014

0.1775

975

27.0%

2013

0.1441

825

26.3%

(a)

The price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing
fees, divided by gasoline and distillate sales volume. Excludes LCM inventory valuation charge.

Midstream segment income from operations increased $9 million in 2015 compared to 2014 and increased $70
million in 2014 compared to 2013. The increase in 2015 was primarily due to the financial results of MarkWest,
which are reflected in Midstream segment income from the December 4, 2015 MarkWest Merger date, partially
offset by $30 million of transaction costs. The increase in 2014 was primarily due to higher pipeline
transportation revenue and an increase in income from our pipeline affiliates, which was primarily attributable to
our investment in LOOP, partially offset by an increase in operating expenses primarily attributable to the
proposed Cornerstone pipeline project and pipeline maintenance costs.

Corporate and other unallocated expenses increased $22 million in 2015 compared to 2014 and $15 million in
2014 compared to 2013. The increase in 2015 was primarily due to a lower allocation of employee benefit costs
to the segments. The increase in 2014 was primarily due to costs incurred in connection with the acquisition of
Hess’ Retail Operations and Related Assets in 2014.

Unallocated items also included an impairment charge of $144 million recorded in the third quarter of 2015
related to the cancellation of the ROUX project at our Garyville refinery. The charge reflects the write-off of all
costs capitalized on the project through September 30, 2015, including front-end engineering and long lead time
equipment. See Item 8. Financial Statements and Supplementary Data – Note 17 for additional information on
the impairment.

We recorded pretax pension settlement expenses of $4 million in 2015, $96 million in 2014 and $95 million in
2013 resulting from the level of employee lump sum retirement distributions that occurred during these years.

Liquidity and Capital Resources

Cash Flows

Our cash and cash equivalents balance was $1.13 billion at December 31, 2015 compared to $1.49 billion at
December 31, 2014. Net cash provided by (used in) operating activities, investing activities and financing
activities for the past three years is presented in the following table.

(In millions)

Net cash provided by (used in):

Operating activities

Investing activities

Financing activities

Total

2015

2014

2013

4,061

3,110

3,405

(3,441)

(4,543)

(987)

635

(2,756)

(3,217)

(367)

(798)

$ (2,568)

Net cash provided by operating activities increased $951 million in 2015 compared to 2014, primarily due to
increased operating results, excluding non-cash charges such as the LCM inventory valuation charge and ROUX
project impairment, partially offset by unfavorable changes in working capital of $330 million compared to 2014.
Net cash provided by operating activities decreased $295 million in 2014 compared to 2013, primarily due to
unfavorable changes in working capital of $892 million compared to 2013, partially offset by an increase in net
income of $422 million and non-cash adjustments of $175 million. The above changes in working capital exclude
changes in short-term debt.

For 2015, changes in working capital were a net $1.02 billion use of cash, primarily due to a decrease in accounts
payable and accrued liabilities, partially offset by decreases in current receivables and inventories. Changes from
December 31, 2014 to December 31, 2015 per the consolidated balance sheets, excluding the impact of
acquisitions, were as follows:

• Accounts payable decreased $1.92 billion from year-end 2014, primarily due to lower crude oil payable

prices and volumes.

• Current receivables decreased $1.13 billion from year-end 2014, primarily due to lower refined product

and crude oil receivable prices and lower crude oil receivable volumes.

•

Inventories decreased $417 million from year-end 2014, primarily due to a $370 million LCM
inventory valuation charge and lower refined product and crude oil inventory volumes.

For 2014, changes in working capital were a net $694 million use of cash, primarily due to a decrease in accounts
payable and accrued liabilities and an increase in inventories, partially offset by a decrease in current receivables.
Excluding the impact of acquisitions, accounts payable decreased $1.65 billion from year-end 2013, primarily
due to lower crude oil payable prices, partially offset by higher crude oil payable volumes; inventories decreased
$796 million from year-end 2013, primarily due to higher refined product and crude oil inventory volumes; and
current receivables decreased $1.63 billion from year-end 2013, primarily due to lower refined product and crude
oil receivable prices.

For 2013, changes in working capital were a net $198 million source of cash, primarily due to an increase in
accounts payable and accrued liabilities, partially offset by increases in current receivables and inventory
volumes. Accounts payable increased $1.45 billion from year-end 2012, primarily due to higher crude oil payable
volumes, and current receivables increased $949 million from year-end 2012, primarily due to higher refined
product receivable volumes attributable to an increase in refined product sales volumes. Both of these increases
are associated with the Galveston Bay refinery acquired in February 2013. Changes in inventories were a $305
million use of cash in 2013, primarily due to higher refined product and crude oil inventory volumes.

Cash flows used in investing activities decreased $1.10 billion in 2015 compared to 2014 and increased $1.79
billion in 2014 compared to 2013. The investing activity is further discussed below.

The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect
cash. A reconciliation of additions to property, plant and equipment to total capital expenditures and investments
follows for each of the last three years.

(In millions)

2015

2014

2013

Additions to property, plant and equipment per consolidated statements of cash

flows

1,998

1,480

1,206

Non-cash additions to property, plant and equipment

Asset retirement expenditures

Increase (decrease) in capital accruals

Investments in equity method investees

Total capital expenditures and investments before acquisitions

Acquisitions(a)

331

2,429

13,854

413

1,994

2,744

124

1,403

1,386

Total capital expenditures and investments

16,283

4,738

2,789

(a)

The 2015 acquisitions include the MarkWest Merger. The 2014 acquisitions include the acquisition of Hess’ Retail Operations and
Related Assets. The 2013 acquisitions include the acquisition of the Galveston Bay Refinery and Related Assets. The acquisition
numbers above include property, plant and equipment, equity investments, intangibles and goodwill. See Item 8. Financial Statements
and Supplementary Data – Note 5 for further details.

Capital expenditures and investments for each of the last three years are summarized by segment below.

(In millions)

Capital expenditures and investments:(a)(b)

Refining & Marketing

Speedway

Midstream

Corporate and Other(c)

Total

2015

2014

2013

1,143

1,104

2,094

501

14,447

192

2,981

543

110

296

234

165

16,283

4,738

2,789

(a) Capital expenditures include changes in capital accruals.

(b)

Includes $13.85 billion in 2015 for the MarkWest Merger, $2.71 billion in 2014 for the acquisition of Hess’ Retail Operations and
Related Assets and $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Item 8. Financial
Statements and Supplementary Data – Note 5.

(c)

Includes capitalized interest of $37 million, $27 million and $28 million for 2015, 2014 and 2013, respectively.

The MarkWest Merger comprised 85 percent of our total capital expenditures and investments, excluding
capitalized interest, in 2015. The acquisition of Hess’ Retail Operations and Related Assets comprised 58 percent
of our total capital expenditures and investments, excluding capitalized interest, in 2014. The acquisition of the
Galveston Bay Refinery and Related Assets comprised 49 percent of our total capital expenditures and
investments, excluding capitalized interest, in 2013.

Cash provided by disposal of assets totaled $21 million, $27 million and $16 million in 2015, 2014 and 2013,
respectively.

Net investments were a $327 million use of cash in 2015 compared to a $404 million use of cash in 2014 and a
$74 million use of cash in 2013. The change in 2015 compared to 2014 was primarily due to a decrease in
contributions to the SAX pipeline project of $121 million and the 2014 investment in Explorer, partially offset by
contributions to Crowley Ocean Partners of $72 million. The change in 2014 compared to 2013 was primarily
due to increases in contributions to the Sandpiper and SAX pipeline projects of $287 million and our investment
in Explorer of $77 million, partially offset by a return of capital from our ethanol affiliates of $9 million.

Financing activities were a $987 million use of cash in 2015, a $635 million source of cash in 2014 and a $3.22
billion use of cash in 2013. The sources of cash in 2015 primarily consisted of net long-term borrowings. The
sources of cash primarily consisted of net long-term debt borrowings in 2014 and proceeds from the issuance of
MPLX common units in 2014. The uses of cash in all three years primarily consisted of common stock
repurchases and dividend payments. In addition, uses of cash in 2015 and 2014 included payments to the seller of
the Galveston Bay refinery under the contingent earnout provisions of the purchase and sale agreement.

Long-term debt borrowings and repayments were a net $767 million source of cash in 2015 compared to a $3.25
billion source of cash in 2014 and a $21 million use of cash in 2013. During 2015, we used $763 million of the
net proceeds from the issuance of $1.5 billion of MPC senior notes to extinguish our obligation for the $750
million aggregate principal amount of senior notes due in 2016 and MPLX used proceeds from its issuance of
$500 million aggregate of principal amount of MPLX senior notes to repay $385 million outstanding under the
MPLX bank revolving credit facility. During 2014, we issued $1.95 billion aggregate principal amount of senior
unsecured notes and borrowed $700 million under a term loan credit agreement to finance the acquisition of
Hess’ Retail Operations and Related Assets. In addition, MPLX had net borrowings of $635 million under its
bank revolving credit agreement and term loan agreement. See Item 8. Financial Statements and Supplementary
Data – Note 19 for additional information on our long-term debt.

Cash used in common stock repurchases totaled $965 million in 2015, $2.13 billion in 2014 and $2.79 billion in
2013 associated with the share repurchase plans authorized by our board of directors. The table below
summarizes our total share repurchases. See Item 8. Financial Statements and Supplementary Data – Note 9 for
further discussion of the share repurchase plans.

(In millions, except per share data)

Number of shares repurchased(a)

Cash paid for shares repurchased

Effective average cost per delivered share

2015

2014

2013

965

50.31

2,131

2,793

44.31

$ 38.07

(a)

Shares repurchased in 2013 includes 2 million shares received under the November 2012 ASR program, which were paid for in 2012.

Cash used in dividend payments totaled $613 million in 2015, $524 million in 2014 and $484 million in 2013.
The increases were primarily due to increases in our base dividend, partially offset by a decrease in the number
of outstanding shares of our common stock as a result of share repurchases. Dividends per share were $1.14 in
2015, $0.92 in 2014 and $0.77 in 2013.

Cash proceeds from the issuance of MPLX common units were $221 million in 2014. See Item 8. Financial
Statements and Supplementary Data – Note 4 for further discussion of MPLX.

Derivative Instruments

See Item 7A. Quantitative and Qualitative Disclosures about Market Risk for a discussion of derivative
instruments and associated market risk.

Capital Resources

Our liquidity totaled $4.3 billion at December 31, 2015 consisting of:

(In millions)

Bank revolving credit facility(a)

Trade receivables securitization facility(b)

Total

Cash and cash equivalents

Total liquidity

December 31, 2015
Outstanding
Borrowings

Available
Capacity

Total
Capacity

2,500

668

3,168

2,500

668

3,168

1,127

4,295

(a)

Excludes MPLX’s $2 billion bank revolving credit facility, which had $877 million of borrowings and $8 million of letters of credit
outstanding as of December 31, 2015.

(b) Availability under our $1.0 billion trade receivables securitization facility is a function of refined product selling prices, which will be
lower in a sustained lower price environment. As of January 31, 2016, eligible trade receivables supported borrowings of $507 million.

Because of the alternatives available to us, including internally generated cash flow and access to capital markets,
including a commercial paper program, we believe that our short-term and long-term liquidity is adequate to fund
not only our current operations, but also our near-term and long-term funding requirements, including capital
spending programs, the repurchase of shares of our common stock, dividend payments, defined benefit plan
contributions, repayment of debt maturities and other amounts that may ultimately be paid in connection with
contingencies.

MPC Bank Revolving Credit Facility – We have a $2.5 billion unsecured revolving credit facility (“revolving
credit facility”) in place with a maturity date of September 14, 2017. Our revolving credit facility includes letter
of credit issuing capacity of up to $2.0 billion and swingline loan capacity of up to $100 million. We may
increase our borrowing capacity under our revolving credit facility by up to an additional $500 million, subject to
certain conditions including the consent of the lenders whose commitments would be increased. In addition, the
maturity date may be extended for up to two additional one-year periods subject to the approval of lenders
holding greater than 50 percent of the commitments then outstanding, provided that the commitments of any non-
consenting lenders will terminate on the then-effective maturity date.

Borrowings under our revolving credit facility bear interest, at our election, at either the Adjusted LIBO Rate (as
defined in our revolving credit facility) plus a margin or the Alternate Base Rate (as defined in our revolving
credit facility) plus a margin. We are charged various fees and expenses in connection with our revolving credit
facility, including administrative agent fees, commitment fees on the unused portion of our borrowing capacity
and fees related to issued and outstanding letters of credit. The applicable margin to the benchmark interest rates
and margin to the benchmark commitment fees payable under our revolving credit facility fluctuate from time-to-
time based on the credit ratings.

There were no borrowings or letters of credit outstanding at December 31, 2015.

Trade receivables securitization facility – On December 18, 2013, we entered into a three-year, $1.3 billion trade
receivables securitization facility (“trade receivables facility”), with a group of financial institutions that act as
issuers and managing agents under the trade
committed purchasers, conduit purchasers,
receivables facility. The trade receivables facility is evidenced by a Receivables Purchase Agreement and a
Second Amended and Restated Receivables Sale Agreement. In October 2015, we reduced the maximum
capacity under the trade receivables facility from $1.3 billion to $1.0 billion.

letter of credit

receivables acquired from Marathon Petroleum Trading Canada LLC, a wholly-owned subsidiary of MPC LP),
together with all related security and interests in the proceeds thereof, without recourse, to another wholly-
owned, bankruptcy-remote special purpose subsidiary, MPC Trade Receivables Company LLC (“TRC”), in
exchange for a combination of cash, equity or a subordinated note issued by TRC to MPC LP. TRC, in turn, has
the ability to finance its purchase of the receivables from MPC LP by selling undivided ownership interests in
qualifying trade receivables, together with all related security and interests in the proceeds thereof, without
recourse, to the purchasing group in exchange for cash proceeds. The trade receivables facility also provides for
the issuance of letters of credit up to $1.0 billion, provided that the aggregate credit exposure of the purchasing
group, including outstanding letters of credit, may not exceed the lessor of $1.0 billion or the balance of our
eligible trade receivables at any one time.

To the extent that TRC retains an ownership interest in the receivables it has purchased or received from MPC
LP, such interest will be included in our consolidated financial statements solely as a result of the consolidation
of the financial statements of TRC with those of MPC. The receivables sold or contributed to TRC are available
first and foremost to satisfy claims of the creditors of TRC and are not available to satisfy the claims of creditors
of MPC. TRC has granted a security interest in all of its assets to the purchasing group to secure its obligations
under the Receivables Purchase Agreement.

Proceeds from the sale of undivided percentage ownership interests in qualifying receivables under the trade
receivables facility will be reflected as debt on our consolidated balance sheet. We will remain responsible for
servicing the receivables sold to the purchasing group. TRC pays floating-rate interest charges and usage fees on
amounts outstanding under the trade receivables facility,
if any, and certain other fees related to the
administration of the facility and letters of credit that are issued and outstanding under the trade receivables
facility.

As of December 31, 2015, eligible trade receivables supported borrowings of $668 million. There were no
borrowings outstanding at December 31, 2015. Availability under our trade receivables securitization facility is a
function of refined product selling prices, which will be lower in a sustained lower price environment.

MPLX Credit Agreement – MPLX is party to a credit agreement, dated as of November 20, 2014, and amended
as of October 27, 2015 (“MPLX credit agreement”), providing for a $2 billion bank revolving credit facility with
a maturity date of December 4, 2020 and an outstanding $250 million term loan facility with a maturity date of
November 20, 2019.

The MPLX credit agreement includes letter of credit issuing capacity of up to $250 million and swingline loan
capacity of up to $100 million. The revolving 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 the lenders
whose commitments would increase. In addition, the maturity date of the bank revolving credit facility may be
extended from time-to-time during its term to a date that is one year after the then-effective date, subject to the
approval of lenders holding the majority of the loans and 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 original then-effective date. The borrowings under
this facility during 2015 were at an average interest rate of 1.7 percent.

Borrowings under the MPLX credit agreement bear interest, at our election, at either the Adjusted LIBO Rate or
the Alternate Base Rate (as defined in the MPLX credit agreement) plus a specified margin. MPLX is charged
various fees and expenses in connection with the agreement, including administrative agent fees, commitment
fees on the unused portion of the borrowing capacity and fees with respect to issued and outstanding letters of

credit. The applicable margin to the benchmark interest rates and the commitment fees payable under the MPLX
credit agreement fluctuate from time-to-time based on MPLX’s credit ratings.

During 2015, MPLX borrowed $992 million under the bank revolving credit facility, at an average interest rate of
1.6 percent, per annum, and repaid $500 million of these borrowings. At December 31, 2015, MPLX had $877
million of borrowings and $8.0 million of letters of credit outstanding under the bank revolving credit facility,
resulting in total unused loan availability of $1.1 billion.

We may also utilize a commercial paper program in the future to provide funding for short-term working capital
needs. Commercial paper maturities are generally limited to 90 days. As of December 31, 2015, we have no
borrowings under a commercial paper program.

Debt-to-Total-Capital Ratio

As described in further detail below, the increase in debt as of year-end 2015 compared to year-end 2014 was
primarily related to debt assumed by MPLX as part of the MarkWest Merger and increased MPC borrowings.
Equity also increased primarily due to the issuance of MPLX units with the MarkWest Merger. Our debt-to-total
capital ratio (total debt to total debt-plus-equity) was 38 percent and 37 percent at December 31, 2015 and 2014,
respectively.

(In millions)

Long-term debt due within one year

Long-term debt

Total debt

Calculation of debt-to-total capital ratio:

Total debt

Plus equity

Total debt plus equity

Debt-to-total capital ratio

December 31,

2015

2014

11,896

11,925

19,675

31,600

38%

6,575

6,602

11,390

17,992

37%

Equity – On December 4, 2015, MPLX merged with MarkWest, whereby MarkWest became a wholly-owned
subsidiary of MPLX. 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 of MPLX representing
limited partner interests in MPLX, plus a one-time cash payment of $6.20 per unit. Each Class B unit of
MarkWest outstanding immediately prior to the merger was converted into the right to receive one Class B unit
of MPLX having substantially similar rights, including conversion and registration rights, and obligations that the
Class B units of MarkWest had immediately prior to the merger. The total fair value of the equity consideration
issued by MPLX resulted in a $7.3 billion increase to Total Equity based on the MPLX closing price of $32.62
per unit as of December 3, 2015. Of this amount, $5.8 billion was reflected as noncontrolling interest for the
portion of MPLX owned by the public and the remaining $1.5 billion was reflected as MPC equity on our
balance sheet.

MPC Senior Notes – On December 14, 2015, we completed a public offering of $1.5 billion in aggregate
principal amount of unsecured senior notes (“MPC senior notes”), consisting of $600 million aggregate principal
amount of senior notes due 2018, $650 million aggregate principal amount of senior notes due 2020 and $250
million aggregate principal amount of senior notes due 2045. The net proceeds from the offering of the MPC
senior notes were $1.49 billion, after deducting underwriting discounts and estimated offering expenses. We used
approximately $763 million of the net proceeds from this offering to fund the extinguishment of our obligation
for the $750 million aggregate principal amount of our 3.500% senior notes due 2016. As a result of the

retirement of our 2016 senior notes, we recorded a loss on extinguishment of debt of $5 million. We intend to use
the remaining net proceeds for general corporate purposes, which may include investments in and advances to
our affiliates and subsidiaries, including MPLX. Interest on each series of MPC senior notes is payable semi-
annually in arrears on June 15 and December 15, commencing on June 15, 2016.

The senior notes are unsecured and unsubordinated obligations of ours and rank equally with all our other
existing and future unsecured and unsubordinated indebtedness.

MPLX and MarkWest Senior Notes – In connection with the MarkWest Merger, MPLX 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 in an exchange offer and consent solicitation undertaken by MPLX and MarkWest.

The new MPLX senior notes consist of approximately $710 million aggregate principal amount of 5.500% senior
notes due February 15, 2023, approximately $989 million aggregate principal amount of 4.500% senior notes due
July 15, 2023, approximately $1.15 billion aggregate principal amount of 4.875% senior notes due December 1,
2024 and approximately $1.19 billion aggregate principal amount of 4.875% senior notes due June 1, 2025.
Interest on each series of new MPLX senior notes is payable semi-annually in arrears on February 15th and
August 15th of each year with respect to the 5.500% 2023 senior notes, on January 15th and July 15th of each year
with respect to the 4.500% 2023 senior notes and on June 1st and December 1st of each year with respect to the
4.875% 2024 senior notes and the 4.875% 2025 senior notes.

After giving effect to the exchange offer and consent solicitation referred to above, as of December 31, 2015,
MarkWest had outstanding approximately $40 million aggregate principal amount of 5.500% senior notes due
February 15, 2023, approximately $11 million aggregate principal amount of 4.500% senior notes due July 15,
2023, approximately $1 million aggregate principal amount of 4.875% senior notes due December 1, 2024 and
approximately $11 million aggregate principal amount of 4.875% senior notes due June 1, 2024. Interest on each
series of the MarkWest senior notes is payable semi-annually in arrears on February 15th and August 15th of each
year with respect to the 5.500% 2023 senior notes, on January 15th and July 15th of each year with respect to the
4.500% 2023 senior notes and on June 1st and December 1st of each year with respect to the 4.875% 2024 senior
notes and the 4.875% 2025 senior notes.

On February 12, 2015, MPLX completed a public offering of $500 million aggregate principal amount of four
percent unsecured senior notes due February 15, 2025. The net proceeds, which were approximately $495 million
after deducting underwriting discounts, were used to repay the amounts outstanding under the MPLX bank
revolving credit facility, as well as for general partnership purposes. Interest is payable semi-annually in arrears
on February 15th and August 15th of each year.

The term loan agreement, the MPC bank revolving credit facility and the MPLX credit agreement contain
representations and warranties, affirmative and negative covenants and events of default that we consider usual
and customary for agreements of these types. The financial covenant included in the term loan agreement and the
MPC bank revolving credit facility requires us to maintain, as of the last day of each fiscal quarter, a ratio of
Consolidated Net Debt to Total Capitalization (as defined in the term loan agreement and the MPC bank
revolving credit facility) of no greater than 0.65 to 1.00. As of December 31, 2015, we were in compliance with
this debt covenant with a ratio of Consolidated Net Debt to Total Capitalization of 0.33 to 1.00, as well as the
other covenants contained in the term loan agreement and the MPC bank revolving credit facility.

The MPLX credit agreement
includes certain representations and warranties, affirmative and restrictive
covenants and events of default that we consider to be usual and customary for an agreement of this type. The
MPLX credit agreement includes a financial covenant that requires MPLX to maintain a ratio of Consolidated
Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX credit

agreement) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal
quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions
completed and capital projects undertaken during the relevant period. Other covenants restrict MPLX and certain
of its subsidiaries from incurring debt, creating liens on its assets and entering into transactions with affiliates. As
of December 31, 2015, MPLX was in compliance with the covenants contained in the MPLX credit agreement,
including a ratio of Consolidated Total Debt to Consolidated EBITDA of 4.6 to 1.0.

Our intention is to maintain an investment grade credit profile. As of December 31, 2015, the credit ratings on
our and MPLX’s senior unsecured debt were at or above investment grade level as follows.

Company

MPC

MPLX

Rating Agency

Rating

Moody’s
Standard & Poor’s
Fitch
Moody’s
Standard & Poor’s
Fitch

Baa2 (stable outlook)
BBB (stable outlook)
BBB (stable outlook)
Baa3 (stable outlook)
BBB- (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.

Neither the revolving credit facility, the MPLX credit agreement nor our trade receivables securitization facility
contains 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 of our senior unsecured debt to below
investment grade ratings would increase the applicable interest rates, yields and other fees payable under the
revolving credit facility and our trade receivables securitization facility. In addition, a downgrade of our senior
unsecured debt rating to below investment grade levels could, under certain circumstances, decrease the amount
of trade receivables that are eligible to be sold under our trade receivables securitization facility, impact our
ability to purchase crude oil on an unsecured basis and could result in us having to post letters of credit under
existing transportation services agreements.

Capital Requirements

Our board approved a 2016 capital spending and investment plan of $4.2 billion towards the end of 2015. In light
of current market conditions and revisions to expected completion dates for certain projects, we expect 2016
capital spending and investments to be $3.0 billion, excluding capitalized interest. Additional details related to
expected 2016 capital spending and investments are discussed in the Capital Budget Outlook section below.

Pursuant to the purchase and sale agreement for the Galveston Bay Refinery and Related Assets, we may be
required to pay the seller a contingent earnout of up to $700 million over six years, subject to certain conditions.
In June 2015, we paid BP $189 million for the second period’s contingent earnout and have paid BP $369 million
to-date for the first two year’s contingent earnout. See Item 8. Financial Statements and Supplementary Data –
Notes 5 and 17.

While we have no required contributions to our pension plans for 2016, we may make voluntary contributions at
our discretion.

On February 1, 2016, our board of directors approved a 32 cents per share dividend, payable March 10, 2016 to
stockholders of record at the close of business on February 17, 2016.

We may utilize various methods to effect the repurchases, which could include open market repurchases,
negotiated block transactions, accelerated share repurchases or open market solicitations for shares, some of
which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will
including market and business conditions, and such repurchases may be
depend upon several factors,
discontinued at any time.

The above discussion contains forward-looking statements with respect to our capital requirements. Forward-
looking statements about our capital requirements are based on current expectations, estimates and projections
and are not guarantees of future performance. Factors that could cause actual results to differ materially from
those included in our forward-looking statements regarding capital requirements include the availability of
liquidity; changes to the expected construction costs and timing of pipeline projects; continued/further volatility
in and/or degradation of market and industry conditions; the availability and pricing of crude oil and other
feedstocks; slower growth in domestic and Canadian crude supply; the effects of the lifting of the U.S. crude oil
export ban; completion of pipeline capacity to areas outside the U.S. Midwest; consumer demand for refined
products; transportation logistics; the reliability of processing units and other equipment; MPC’s ability to
successfully implement growth opportunities; the market price of our common stock; modifications to MPLX
earnings and distribution growth objectives; federal and state environmental, economic, health and safety, energy
and other policies and regulations; MPC’s ability to successfully achieve the strategic and other expected
objectives relating to the MarkWest Merger. 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.

Contractual Cash Obligations

The table below provides aggregated information on our consolidated obligations to make future payments under
existing contracts as of December 31, 2015. The contractual obligations detailed below do not include our
contractual obligations to MPLX under various fee-based commercial agreements as these transactions are
eliminated in the consolidated financial statements.

Total

2016

2017-2018

2019-2020

Later Years

1,656

3,474

13,624

536

243

328

(In millions)

Long-term debt(a)

Capital lease obligations(b)

Operating lease obligations

Purchase obligations:(c)

Crude oil, feedstock, refined

product and renewable fuel
contracts(d)

Transportation and related

contracts

Contracts to acquire property,
plant and equipment(e)(f)

Service, materials and other

contracts(g)

Total purchase obligations

Other long-term liabilities reported in
the consolidated balance sheet(h)

Total contractual cash

obligations

19,290

431

1,194

8,340

4,900

1,599

2,222

17,061

1,408

5,997

1,014

375

865

558

7,795

190

584

734

608

2,940

303

240

722

3,215

403

4,340

156

208

383

607

726

653

1,986

759

39,384

8,812

5,317

8,295

16,960

(a)

Includes interest payments for our senior notes, term loans and the MPLX credit agreement and commitment and administrative fees for
our credit agreement, the MPLX credit agreement and our trade receivables securitization facility.

(e)

(d)

(b) Capital lease obligations represent future minimum payments.
Includes both short- and long-term purchases obligations.
(c)
These contracts include variable price arrangements with estimated prices to be paid primarily based on futures curves.
Includes $632 million to fund 37.5 percent of the construction of the Sandpiper pipeline project.
Includes $331 million of contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets. See
Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on this acquisition.
Primarily includes contracts to purchase services such as utilities, supplies and various other maintenance and operating services.
Primarily includes obligations for pension and other postretirement benefits including medical and life insurance, which we have
estimated through 2024. See Item 8. Financial Statements and Supplementary Data – Note 22.

(h)

(g)

(f)

Off-Balance Sheet Arrangements

Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital
resources and results of operations, even though such arrangements are not recorded as liabilities under
accounting principles generally accepted in the United States. Our off-balance sheet arrangements are limited to
indemnities and guarantees that are described below. Although these arrangements serve a variety of our business
purposes, we are not dependent on them to maintain our liquidity and capital resources, and we are not aware of
any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material
adverse effect on liquidity and capital resources.

We have provided various guarantees related to equity method investees. In conjunction with the Spinoff, we
entered into various indemnities and guarantees to Marathon Oil. These arrangements are described in Item 8.
Financial Statements and Supplementary Data – Note 25.

Capital Budget Outlook

We expect to spend $3.0 billion in 2016 on capital projects and investments, excluding capitalized interest and
any acquisitions we may make. This represents a 23 percent increase from our 2015 spending due to additional
midstream capital spending resulting from the MarkWest Merger. The budget includes spending on refining,
retail marketing and midstream projects as well as amounts designated for corporate activities. We continuously
evaluate our capital budget and make changes as conditions warrant.

Refining & Marketing

The Refining & Marketing segment’s forecasted 2016 capital spending and investments is $1.3 billion, which
includes approximately $250 million for midstream related assets, approximately $375 million for refining
margin enhancement projects and approximately $675 million for refinery-sustaining capital. A number of these
projects span multiple years.

The $250 million forecasted for midstream related assets includes contributions to our ocean vessel equity
affiliate as well as a number of projects in our terminal, transportation and rail operations.

The $375 million forecasted for refining margin enhancement projects includes 2016 spending on the STAR
program. The forecast also includes investments in the FCC units at our Garyville and Detroit refineries to
increase our capacity to produce higher value alkylate and light products. At our Galveston Bay refinery, we will
complete a hydrocracker project designed to increase our ULSD production by nine mbpd by shifting yields from
gasoline. At our Robinson refinery, we expect to complete a project to increase the light crude oil processing
capacity by 30 mbpcd in 2016, which will allow it to run 100 percent light crude oil. We will complete another
project at our Galveston Bay refinery in mid-2016 which will increase export capabilities approximately 30
mbpd. We have another project at our Galveston Bay refinery to further increase export capabilities by 115 mbpd
by 2018 for a total increase of 145 mbpd.

The remaining $675 million budget is primarily allocated to maintaining facilities and meeting regulatory
requirements at our refineries.

Speedway

The Speedway segment’s 2016 capital forecast of approximately $300 million is focused on store remodels,
particularly remodels of its recently converted stores along the East Coast, and building new stores in
Speedway’s core markets. The forecast includes approximately $140 million for store conversions and remodels,
which will drive incremental merchandise sales. The remaining budget is primarily for new convenience store
construction and land acquisition to expand our markets and remodeling and rebuilding projects to upgrade and
enhance our existing facilities. Also included in the capital budget are expenditures for technology, equipment
and dispenser upgrades. We intend to continue growing Speedway’s sales and profitability by focusing on the
conversion and integration of acquired locations, from which we expect to realize increased merchandise sales
and other synergies. We also remain focused on organic growth through remodeling stores, constructing new
stores, rebuilding old stores, acquiring high quality stores through opportunistic acquisitions and improving
margins at our existing operations. We have identified numerous opportunities for new convenience stores or
store rebuilds in our existing market, Pennsylvania and Tennessee, as well as growth opportunities in Georgia,
South Carolina and the Florida panhandle.

Midstream

The Midstream segment’s forecasted 2016 capital spend of $1.3 billion, including $1.1 billion for MPLX which
represents the mid-point of the growth capital spending forecast of $800 million to $1.2 billion plus
approximately $60 million for maintenance capital spending. MPLX is focused on projects attributed to

MarkWest’s ongoing development of natural gas and gas liquids infrastructure to support its producer customers,
particularly those in the Marcellus and Utica shale regions. MarkWest is a wholly-owned subsidiary of MPLX.

MPLX is continuing its development of the Cornerstone pipeline project to connect Utica Shale production in
southeastern Ohio to our Canton refinery and related build-out opportunities, which is expected to cost
approximately $230 million, $46 million of which has been spent to date, and is anticipated to be operational late
in 2016.

Corporate and Other

The remaining 2016 capital forecast includes $95 million, primarily related to an expansion project for our
corporate headquarters and upgrades to information technology systems.

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 credit ratings by rating agencies. The discussion of
liquidity and capital resources above also contains forward-looking statements regarding expected capital and
investment spending, costs for projects under construction, project completion dates and expectations or
projections about strategies and goals for growth, upgrades and expansion. The forward-looking statements about
our capital and investment 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 prices of and
demand for crude oil and refinery feedstocks and refined products, actions of competitors, delays in obtaining
necessary third-party approvals, changes in labor, materials, and equipment costs and availability, planned and
unplanned outages, the delay of, cancellation of or failure to implement planned capital projects, project cost
overruns, disruptions or interruptions of our refining 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.

Transactions with Related Parties

We believe that transactions with related parties were conducted under terms comparable to those with unrelated
parties. See Item 8. Financial Statements and Supplementary Data – Note 7 for discussion of activity with related
parties.

Environmental Matters and Compliance Costs

We have incurred and may continue to incur substantial capital, operating and maintenance, and remediation
expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not
ultimately reflected in the prices of our products and services, our operating results will be adversely affected.
We believe that substantially all of our competitors must comply with similar environmental
laws and
regulations. However, the specific impact on each competitor may vary depending on a number of factors,
including the age and location of its operating facilities, marketing areas, production processes and whether it is
also engaged in the petrochemical business or the marine transportation of crude oil and refined products.

Legislation and regulations pertaining to fuel specifications, climate change and greenhouse gas emissions have
the potential to materially adversely impact our business, financial condition, results of operations and cash
flows, including costs of compliance and permitting delays. The extent and magnitude of these adverse impacts
cannot be reliably or accurately estimated at this time because specific regulatory and legislative requirements
have not been finalized and uncertainty exists with respect to the measures being considered, the costs and the
time frames for compliance, and our ability to pass compliance costs on to our customers. For additional
information see Item 1A. Risk Factors.

Our environmental expenditures, including non-regulatory expenditures, for each of the last three years were:

(In millions)

Capital

Compliance:(a)

Operating and maintenance

Remediation(b)

Total

2015

2014

2013

222

102

355

397

630

535

321

393

(a) Based on the American Petroleum Institute’s definition of environmental expenditures.
(b)

These amounts include spending charged against remediation reserves, where permissible, but exclude non-cash provisions recorded 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 accounted for nine percent, five percent and four percent of capital
expenditures excluding the MarkWest Merger and the acquisitions of the Galveston Bay Refinery and Related
Assets and Hess’ Retail Operations and Related Assets in 2015, 2014 and 2013, respectively. Our environmental
capital expenditures are expected to approximate $356 million, or twelve percent, of total capital expenditures in
2016. Predictions beyond 2016 can only be broad-based estimates, which have varied, and will continue to vary,
due to the ongoing evolution of specific regulatory requirements, the possible imposition of more stringent
requirements and the availability of new technologies, among other matters. Based on currently identified
projects, we anticipate that environmental capital expenditures will be approximately $539 million in 2017;
however, actual expenditures may vary as the number and scope of environmental projects are revised as a result
of improved technology or changes in regulatory requirements and could increase if additional projects are
identified or additional requirements are imposed.

For more information on environmental regulations that impact us, or could impact us, see Item 1. Business –
Environmental Matters, Item 1A. Risk Factors and Item 3. Legal Proceedings.

Critical Accounting Estimates

The preparation of financial statements in accordance with US 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.

Fair Value Estimates

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction
between market participants at the measurement date. There are three approaches for measuring the fair value of
assets and liabilities: the market approach, the income approach and the cost approach, each of which includes
multiple valuation techniques. The market approach uses prices and other relevant information generated by
market transactions involving identical or comparable assets or liabilities. The income approach uses valuation
techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single
present value amount using current market expectations about those future amounts. The cost approach is based
on the amount that would currently be required to replace the service capacity of an asset. This is often referred
to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would
cost a market participant
to acquire or construct a substitute asset of comparable utility, adjusted for
obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring
fair value and does not prioritize among the techniques. These standards establish a fair value hierarchy that
prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions
that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given
the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels
of the fair value hierarchy are as follows:

• Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in
active markets as of the measurement date. Active markets are those in which transactions for the asset
or liability occur in sufficient frequency and volume to provide pricing information on an ongoing
basis.

• Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data.
These are inputs other than quoted prices in active markets included in Level 1, which are either
directly or indirectly observable as of the measurement date.

• Level 3 – Unobservable inputs that are not corroborated by market data and may be used with

internally developed methodologies that result in management’s best estimate of fair value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified
in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The
assessment of the significance of a particular input to the fair value measurement requires judgment and may
affect the placement of assets and liabilities within the levels of the fair value hierarchy. We use a market or
income approach for recurring fair value measurements and endeavor to use the best information available. See
Item 8. Financial Statements and Supplementary Data – Note 17 for disclosures regarding our fair value
measurements.

Significant uses of fair value measurements include:

•

assessment of impairment of long-lived assets;

assessment of impairment of intangible assets:

assessment of impairment of goodwill;

•

assessment of impairment of equity method investments;

recorded values for acquisitions; and

recorded values of derivative instruments.

Impairment Assessments of Long-Lived Assets, Intangible Assets, Goodwill and Equity Method
Investments

Fair value calculated for the purpose of testing our long-lived assets, goodwill and equity method investments for
impairment is estimated using the expected present value of future cash flows method and comparative market
prices when appropriate. Significant judgment is involved in performing these fair value estimates since the
results are based on forecasted assumptions. Significant assumptions include:

• Future margins on products produced and sold. Our estimates of future product margins are based on
our analysis of various supply and demand factors, which include, among other things, industry-wide
capacity, our planned utilization rate, end-user demand, capital expenditures and economic conditions.
Such estimates are consistent with those used in our planning and capital investment reviews.

• Future volumes. Our estimates of future refinery, pipeline throughput and natural gas and NGL
processing volumes are based on internal forecasts prepared by our Refining & Marketing and
Midstream segments operations personnel.

• Discount rate commensurate with the risks involved. We apply a discount rate to our cash flows
based on a variety of factors, including market and economic conditions, operational risk, regulatory
risk and political risk. This discount rate is also compared to recent observable market transactions, if
possible. A higher discount rate decreases the net present value of cash flows.

• Future capital requirements. These are based on authorized spending and internal forecasts.

We base our fair value estimates on projected financial information which we believe to be reasonable. However,
actual results may differ from these projections.

The need to test for impairment can be based on several indicators, including a significant reduction in prices of
or demand for products produced, a poor outlook for profitability, a significant reduction in pipeline throughput
volumes, a significant reduction in natural gas or NGLs processed, significant reduction in refining margins,
other changes to contracts or changes in the regulatory environment in which the asset or equity method
investment is located.

Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances
indicate that the carrying value of the assets may not be recoverable based on the expected undiscounted future
cash flow of an asset group. For purposes of impairment evaluation, long-lived assets must be grouped at the
lowest level for which independent cash flows can be identified, which generally is the refinery and associated
distribution system level for Refining & Marketing segment assets, site level for Speedway segment convenience
stores, the plant level or pipeline system level and the customer relationship for our customer contract intangibles
for Midstream segment assets. If the sum of the undiscounted estimated pretax cash flows is less than the
carrying value of an asset group, fair value is calculated, and the carrying value is written down if greater than
the calculated fair value.

Unlike long-lived assets, goodwill and intangibles must be tested for impairment at least annually, or between
annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a
reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. At
December 31, 2015, we had a total of $4.0 billion of goodwill recorded on our consolidated balance sheet. The
fair value of our reporting units exceeded book value for each of our reporting units in 2015.

The carrying values of certain reporting units in our Midstream segment equaled their fair values as of the date of
the MarkWest Merger. Any decrease in the fair value of these reporting units going forward could result in an
impairment charge to the approximate $2.5 billion of goodwill recorded in connection with the MarkWest
Merger.

In February of 2016, MPLX common units were trading at a price per unit which is significantly lower than the
price per unit used to calculate the merger consideration and the resulting goodwill that was assigned to certain
reporting units in our Midstream segment.

The significant assumptions which were used to develop the estimates of the fair values recorded in acquisition
accounting and the resulting goodwill assigned to the reporting units included discount rates, growth rates and
customer attrition rates. If MPLX experiences negative events related to these assumptions or if the market price
of MPLX common units continues to trade at a low level in 2016, MPLX may need to assess whether this is a
change in circumstances that indicates it is more likely than not that the fair value of the reporting units to which
they assigned goodwill in connection with the MarkWest Merger is less than their carrying value and, if so,
evaluate goodwill for impairment.

Equity method investments are assessed for impairment whenever factors indicate an other than temporary loss
in value. Factors providing evidence of such a loss include the fair value of an investment that is less than its
carrying value, absence of an ability to recover the carrying value or the investee’s inability to generate income
sufficient to justify our carrying value. At December 31, 2015, we had $3.62 billion of investments in equity
method investments recorded on our consolidated balance sheet.

An estimate of the sensitivity to net income resulting from impairment calculations is not practicable, given the
numerous assumptions (e.g., pricing, volumes and discount rates) that can materially affect our estimates. That is,
unfavorable adjustments to some of the above listed assumptions may be offset by favorable adjustments in other
assumptions.

Centennial experienced a significant reduction in shipment volumes in the second half of 2011 that has continued
through 2015. At December 31, 2015, Centennial was not shipping product. As a result, we continued to evaluate
the carrying value of our equity investment in Centennial. We concluded that no impairment was required given
our assessment of its fair value based on market participant assumptions for various potential uses and future
cash flows of Centennial’s assets. If market conditions were to change and the owners of Centennial are unable to
find an alternative use for the assets, there could be a future impairment of our Centennial interest. As of
December 31, 2015, our equity investment in Centennial was $37 million and we had a $34 million guarantee
associated with 50 percent of Centennial’s outstanding debt. See Item 8. Financial Statements and Supplementary
Data – Note 25 for additional information on the debt guarantee.

The above discussion contains forward-looking statements with respect to the carrying value of our Centennial
equity investment. Factors that could affect the carrying value of our Centennial equity investment include, but
are not limited to, a change in business conditions, a further decline or improvement in the long-term outlook of
the potential uses of Centennial’s assets and the pursuit of different strategic alternatives for such assets. These
factors, among others, could cause actual results to differ materially from those set forth in the forward-looking
statements.

Acquisitions

In accounting for business combinations, acquired assets and liabilities and contingent consideration are recorded
based on estimated fair values as of the date of acquisition. The excess or shortfall of the purchase price when
compared to the fair value of the net tangible and identifiable intangible assets acquired, if any, is recorded as
goodwill or a bargain purchase gain, respectively. A significant amount of judgment is involved in estimating the
individual fair values of property, plant and equipment, intangible assets, contingent consideration and other

assets and liabilities. We use all available information to make these fair value determinations and, for certain
acquisitions, engage third-party consultants for assistance.

The fair value of assets and liabilities, including contingent consideration, as of the acquisition date are often
estimated using a combination of approaches, including the income approach, which requires us to project related
future cash inflows and outflows and apply an appropriate discount rate; the cost approach, which requires
estimates of replacement costs and depreciation and obsolescence estimates; and the market approach which uses
market data and adjusts for entity-specific differences. The estimates used in determining fair values are based on
assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ
from the projected results used to determine fair value.

For the customer contract intangibles for our Midstream segment, we must estimate the expected life of the
relationships with our customers on an individual 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.

The fair value of the contingent consideration we expect to pay to BP is re-measured each quarter using an
income approach, with changes in fair value recorded in cost of revenues. The amount of cash to be paid under
the arrangement is based on both a market-based crack spread and refinery throughput volumes for the months
during which the contract applies, as well as established thresholds that cap the annual and total payment. We
used internal and external forecasts for the crack spread and internal forecasts for refinery throughput volumes
and applied an appropriate risk-adjusted discount rate to the range of cash flows indicated by various scenarios to
determine the fair value of the arrangement. See Item 8. Financial Statements and Supplementary Data – Note 5
for additional information on our acquisitions. See Item 8. Financial Statements and Supplementary Data – Note
17 for additional information on fair value measurements.

Derivatives

We record all derivative instruments at fair value. Substantially all of our commodity derivatives are cleared
through exchanges which provide active trading information for identical derivatives and do not require any
assumptions in arriving at fair value. Fair value estimation for all our derivative instruments is discussed in
Item 8. Financial Statements and Supplementary Data – Note 17. Additional information about derivatives and
their valuation may be found in Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Variable Interest Entities

We evaluate all legal entities in which we hold an ownership or other pecuniary interest to determine if the entity
is a VIE. Our interests in a VIE are referred to as variable interests. Variable interests can be contractual,
ownership or other pecuniary interests in an entity that change with changes in the fair value of the VIE’s assets.
When we conclude that we hold an interest in a VIE we must determine if we are the entity’s primary
beneficiary. A primary beneficiary is deemed to have a controlling financial interest in a VIE. This controlling
financial interest is evidenced by both (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.

Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interest in a
VIE. We use primarily a qualitative analysis to determine if an entity is a VIE. We evaluate the entity’s need for
continuing financial support; the equity holder’s lack of a controlling financial interest; and/or if an equity
holder’s voting interests are disproportionate to its obligation to absorb expected losses or receive residual
returns. We evaluate our interests in a VIE to determine whether we are the primary beneficiary. We use a

primarily qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE,
either on a standalone basis or as part of a related party group. We continually monitor our interests in legal
entities for changes in the design or activities of an entity and changes in our interests, including our status as the
primary beneficiary to determine if the changes require us to revise our previous conclusions.

MarkWest Utica EMG, a natural gas and NGL processing joint venture, is a VIE; however, we are not considered
to be the primary beneficiary. As a result, it is accounted for under the equity method. Changes in the design or
nature of the activities of this entity, or our involvement with the 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 consolidation of the
entity 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.

Variable Interest Entities are discussed in Item 8. Financial Statements and Supplementary Data – Note 6 .

Pension and Other Postretirement Benefit Obligations

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most
significant of which relate to the following:

•

the discount rate for measuring the present value of future plan obligations;

the expected long-term return on plan assets;

the rate of future increases in compensation levels;

health care cost projections; and

the mortality table used in determining future plan obligations.

We utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected
different discount rates for our funded pension plans and our unfunded retiree health care plans due to the
different projected benefit payment patterns. The selected rates are compared to various similar bond indexes for
reasonableness. In determining the assumed discount rates, we use our third-party actuary’s discount rate model.
This model calculates an equivalent single discount rate for the projected benefit plan cash flows using a yield
curve derived from Aa bond yields. The yield curve represents a series of annualized individual spot discount
rates from 0.5 to 99 years. The bonds used have an average rating of Aa or higher by a recognized rating agency
and generally only non-callable bonds are included. Outlier bonds that have a yield to maturity that deviate
significantly from the average yield within each maturity grouping are not included. Each issue is required to
have at least $250 million par value outstanding.

Of the assumptions used to measure the year-end obligations and estimated annual net periodic benefit cost, the
discount rate has the most significant effect on the periodic benefit cost reported for the plans. Decreasing the
discount rates of 3.65 percent for our pension plans and 4.15 percent for our other postretirement benefit plans by
0.25 percent would increase pension obligations and other postretirement benefit plan obligations by $42 million
and $32 million, respectively, and would increase defined benefit pension expense and other postretirement
benefit plan expense by $2 million and $4 million, respectively.

The long-term asset rate of return assumption considers the asset mix of the plans (currently targeted at
approximately 51 percent equity securities and 49 percent fixed income securities for the primary funded pension
plan), past performance and other factors. Certain components of the asset mix are modeled with various
assumptions regarding inflation and returns. In addition, our long-term asset rate of return assumption is
compared to those of other companies and to historical returns for reasonableness. After evaluating activity in the

capital markets, along with the current and projected plan investments, we reduced the asset rate of return for our
primary plan from 7.00 percent to 6.75 percent effective for 2015. We used the 7.00 percent long-term rate of
return to determine our 2014 defined benefit pension expense. Decreasing the 6.75 percent asset rate of return
assumption by 0.25 percent would increase our defined benefit pension expense by $4 million.

Compensation change assumptions are based on historical experience, anticipated future management actions
and demographics of the benefit plans.

Health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an
assessment of likely long-term trends.

We utilized the 2015 mortality tables from the U.S. Society of Actuaries.

Item 8. Financial Statements and Supplementary Data – Note 22 includes detailed information about the
assumptions used to calculate the components of our annual defined benefit pension and other postretirement
plan expense, as well as the obligations and accumulated other comprehensive loss reported on the year-end
balance sheets.

Contingent Liabilities

We accrue contingent liabilities for legal actions, claims, litigation, environmental remediation, tax deficiencies
related to operating taxes and third-party indemnities for specified tax matters when such contingencies are both
probable and estimable. We regularly assess these estimates in consultation with legal counsel to consider
resolved and new matters, material developments in court proceedings or settlement discussions, new
information obtained as a result of ongoing discovery and past experience in defending and settling similar
matters. Actual costs can differ from estimates for many reasons. For instance, settlement costs for claims and
litigation can vary from estimates based on differing interpretations of laws, opinions on degree of responsibility
and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary from
estimates because of changes in laws, regulations and their interpretation, additional information on the extent
and nature of site contamination and improvements in technology.

We generally record losses related to these types of contingencies as cost of revenues or selling, general and
administrative expenses in the consolidated statements of income, except for tax deficiencies unrelated to income
taxes, which are recorded as other taxes. For additional information on contingent liabilities, see Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental
Matters and Compliance Costs.

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.

Accounting Standards Not Yet Adopted

As discussed in Item 8. Financial Statements and Supplementary Data – Note 3 to our audited consolidated
financial statements, certain new financial accounting pronouncements will be effective for our financial
statements in the future.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

General

We are exposed to market risks related to the volatility of crude oil and refined product prices. We employ
various strategies, including the use of commodity derivative instruments, to hedge the risks related to these price
fluctuations. We are also exposed to market risks related to changes in interest rates and foreign currency
exchange rates. As of December 31, 2015, we did not have any financial derivative instruments to hedge the risks
related to interest rate fluctuations; however, we have used them in the past, and we continually monitor the
market and our exposure and may enter into these agreements again in the future. We are at risk for changes in
fair value of all of our derivative instruments; however, such risk should be mitigated by price or rate changes
related to the underlying commodity or financial transaction.

We believe that our use of derivative instruments, along with our risk assessment procedures and internal
controls, does not expose us to material adverse consequences. While the use of derivative instruments could
materially affect our results of operations in particular quarterly or annual periods, we believe that the use of
these instruments will not have a material adverse effect on our financial position or liquidity.

See Item 8. Financial Statements and Supplementary Data – Notes 17 and 18 for more information about the fair
value measurement of our derivatives, as well as the amounts recorded in our consolidated balance sheets and
statements of income. We do not designate any of our commodity derivative instruments as hedges for
accounting purposes.

Commodity Price Risk

Refining & Marketing

Our strategy is to obtain competitive prices for our products and allow operating results to reflect market price
movements dictated by supply and demand. We use a variety of commodity derivative instruments, including
futures and options, as part of an overall program to hedge commodity price risk. We also authorize the use of
the market knowledge gained from these activities to do a limited amount of trading not directly related to our
physical transactions.

We use commodity derivative instruments on crude oil and refined product inventories to hedge price risk
associated with inventories above or below LIFO inventory targets. We also use derivative instruments related to
the acquisition of foreign-sourced crude oil and ethanol blended with refined petroleum products to hedge price
risk associated with market volatility between the time we purchase the product and when we use it in the
refinery production process or it is blended. In addition, we may use commodity derivative instruments on fixed
price contracts for the sale of refined products to hedge risk by converting the refined product sales to market-
based prices. The majority of these derivatives are exchange-traded contracts. We closely monitor and hedge our
exposure to market risk on a daily basis in accordance with policies approved by our board of directors. Our
positions are monitored daily by a risk control group to ensure compliance with our stated risk management
policy.

Midstream

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 MPLX’s control. MPLX’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 MPLX’s producer customers, such prices also affect profitability. To protect MPLX financially

against adverse price movements and to maintain more stable and predictable cash flows so that it can meet its
cash distribution objectives, debt service and capital plans, MPLX executes a strategy governed by its risk
management policy. MPLX 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.
Derivative contracts utilized for crude oil, natural gas and NGLs are swaps and options traded on the OTC
market and fixed price forward contracts. As a result of MPLX’s current derivative positions, it believes that it
has mitigated a portion of its expected commodity price risk through the fourth quarter of 2016. MPLX 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 MPLX has
derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions
may be terminated.

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

Open Derivative Positions and Sensitivity Analysis

The table below sets forth information relating to our significant open commodity derivative contracts as of
December 31, 2015.

Crude Oil(a)

Exchange-traded

OTC

Position

Total Barrels
(In thousands)

Weighted Average Price
(Per barrel)

Benchmark

December 31, 2015

Long

Short

14,517

(22,989)

(110)

$38.38

$41.29

$63.56

CME and ICE Crude(c)(d)

Position

Total Gallons
(In thousands)

Weighted Average Price
(Per gallon)

Benchmark

Refined Products(b)

Exchange-traded

OTC

OTC (MarkWest Liberty)

Long

Short

221,256

(203,700)

(28,239)

(15,599)

$ 1.19

$ 1.20

$ 0.50

$ 0.85

(a)

(b)

100 percent of exchange-traded contracts expire in the first quarter of 2016.

(d)

Intercontinental Exchange (“ICE”).

(e) Reformulated gasoline Blendstock for Oxygenate Blending (“RBOB”).

CME Heating Oil and RBOB(c)(e)

Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and
25 percent increases and decreases in commodity prices for open commodity derivative instruments as of
December 31, 2015 is provided in the following table.

(In millions)

As of December 31, 2015

Crude

Refined products

Embedded derivatives

Change
in IFO from a
Hypothetical Price
Increase of

Change
in IFO from a
Hypothetical Price
Decrease of

10%

25%

10%

25%

(20)

(51)

(3)

(8)

(2)

(6)

We remain at risk for possible changes in the market value of commodity derivative instruments; however, such
risk should be mitigated by price changes in the underlying physical commodity. Effects of these offsets are not
reflected in the above sensitivity analysis.

We evaluate our portfolio of commodity derivative instruments on an ongoing basis and add or revise strategies
in anticipation of changes in market conditions and in risk profiles. Changes to the portfolio after December 31,
2015 would cause future IFO effects to differ from those presented above.

Interest Rate Risk

We are impacted by interest rate fluctuations related to our debt obligations. At December 31, 2015, our debt was
primarily comprised of the $2.25 billion aggregate principal amount of fixed rate senior notes issued February 1,
2011, the $1.95 billion aggregate principal amount of fixed rate senior notes issued September 5, 2014, the $500
million aggregate principal amount of fixed rate MPLX senior notes issued February 12, 2015, the $1.50 billion
aggregate principal amount of fixed rate senior notes issued December 15, 2015 and the $4.04 billion aggregate
principal amount of fixed rate MPLX senior notes issued December 22, 2015. Additionally, we have $1.83
billion of variable rate term debt.

Sensitivity analysis of the effect of a hypothetical 100-basis-point change in interest rates on long-term debt as of
December 31, 2015 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(a)

Fixed-rate

Variable-rate

Fair Value(b)

Change in
Fair Value

Change in Net Income for the
Twelve Months Ended
December 31, 2015

9,539

798 (c)

1,827

n/a

11 (d)

(a)

(b)

Excludes capital leases.

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

(d) Assumes a 100-basis-point change in interest rates. The change in net income was based on the weighted average balance of debt

outstanding for the year ended December 31, 2015.

At December 31, 2015, our portfolio of long-term debt was comprised of fixed-rate instruments and variable-rate
borrowings under the term loan agreement, the MPLX term loan facility and MPLX bank revolving credit
facility. The fair value of our fixed-rate debt is relatively sensitive to interest rate fluctuations. Our sensitivity to
interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affects our
results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices
above carrying value. Interest rate fluctuations generally do not impact the fair value of borrowings under the
term loan agreement, the MPLX term loan facility and MPLX bank revolving credit facility, but may affect our
results of operations and cash flows.

Foreign Currency Exchange Rate Risk

We are impacted by foreign exchange rate fluctuations related to some of our purchases of crude oil denominated
in Canadian dollars. We did not utilize derivatives to hedge our market risk exposure to these foreign exchange
rate fluctuations in 2015.

Counterparty Risk

We are subject to risk of loss resulting from nonpayment by our customers to whom we provide services or sell
natural gas or NGLs. We believe that certain contracts would allow us to pass those losses through to our
customers, thus reducing our risk, when we are selling NGLs and acting as our producer customers’ agent. Our
credit exposure related to these customers is represented by the value of our trade receivables. Where exposed to
credit risk, we analyze the customer’s financial condition prior to entering into a transaction or agreement,
establish credit terms and monitor the appropriateness of these terms on an ongoing basis. In the event of a
customer default, we may sustain a loss and our cash receipts could be negatively impacted.

We are subject to risk of loss resulting from nonpayment or nonperformance by counterparties or future
commission merchants. 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 nonperformance by the counterparties to the agreements. Should the
creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance 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
derivative as the overall value is a liability. We regularly review the creditworthiness of counterparties and
futures commission merchants and enter into master netting agreements when appropriate.

Forward-Looking Statements

These quantitative and qualitative disclosures about market risk include forward-looking statements with respect
to management’s opinion about risks associated with the use of derivative instruments. These statements are
based on certain assumptions with respect to market prices and industry supply of and demand for crude oil,
other refinery feedstocks, refined products and ethanol. If these assumptions prove to be inaccurate, future
outcomes with respect to our use of derivative instruments may differ materially from those discussed in the
forward-looking statements.

100

Item 8. Financial Statements and Supplementary Data

Index

Management’s Responsibilities for Financial Statements

Management’s Report on Internal Control Over Financial Reporting

Report of Independent Registered Public Accounting Firm

Audited Consolidated Financial Statements:

Consolidated Statements of Income

Consolidated Statements of Comprehensive Income

Consolidated Balance Sheets

Consolidated Statements of Cash Flows

Consolidated Statements of Equity

Notes to Consolidated Financial Statements

Selected Quarterly Financial Data (Unaudited)

Supplementary Statistics (Unaudited)

Page

102

103

104

105

106

107

108

109

168

169

101

Management’s Responsibilities for Financial Statements

The accompanying consolidated financial statements of Marathon Petroleum Corporation and its subsidiaries
(“MPC”) are the responsibility of management 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.

MPC seeks to assure the objectivity and integrity of its 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 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
Gary R. Heminger
President and
Chief Executive Officer

/s/ Timothy T. Griffith
Timothy T. Griffith
Senior Vice President
and Chief Financial
Officer

/s/ John J. Quaid
John J. Quaid
Vice President and
Controller

Management’s Report on Internal Control over Financial Reporting

MPC’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). 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, MPC’s management concluded that its internal control over financial reporting was effective as of
December 31, 2015.

Management has excluded MarkWest (as defined in footnote 4) from the Company’s assessment of internal
control over financial reporting as of December 31, 2015 as it was acquired by the Company in a business
combination on December 4, 2015. MarkWest represents approximately 26% of consolidated total assets as of
December 31, 2015 and less than 1% of total revenues and other income for the year ended December 31, 2015.
We plan to fully integrate the acquired businesses into our internal control over financial reporting in 2016.

The effectiveness of MPC’s internal control over financial reporting as of December 31, 2015 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
Gary R. Heminger
President and
Chief Executive Officer

/s/ Timothy T. Griffith
Timothy T. Griffith
Senior Vice President
and Chief Financial
Officer

102

Report of Independent Registered Public Accounting Firm

To the Stockholders of Marathon Petroleum Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income,
comprehensive income, equity, and cash flows present fairly, in all material respects, the financial position of
Marathon Petroleum Corporation and its subsidiaries at December 31, 2015 and 2014, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2015 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, 2015,
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.

As discussed in Note 3 to the consolidated financial statements, in 2015, the Company changed the manner in
which it classifies its deferred taxes on the consolidated balance sheet.

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
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.

limitations,

As described in Management’s Report on Internal Control over Financial Reporting, management has excluded
MarkWest (as defined in Note 4) from the Company’s assessment of internal control over financial reporting as
of December 31, 2015 as it was acquired by the Company in a business combination on December 4, 2015. We
have also excluded MarkWest from our audit of internal control over financial reporting. MarkWest represents
approximately 26% of consolidated total assets as of December 31, 2015 and less than 1% of total revenues and
other income for the year ended December 31, 2015.

/s/PricewaterhouseCoopers LLP

Toledo, Ohio
February 26, 2016

103

Marathon Petroleum Corporation

Consolidated Statements of Income

(In millions, except per share data)

Revenues and other income:

2015

2014

2013

Sales and other operating revenues (including consumer excise taxes)

72,051

97,817

100,160

Income from equity method investments

Net gain on disposal of assets

Other income

Total revenues and other income

Costs and expenses:

112

153

111

72,258

98,102

100,254

Cost of revenues (excludes items below)

55,583

83,770

87,401

Purchases from related parties

Inventory market valuation charge

Consumer excise taxes

Depreciation and amortization

Selling, general and administrative expenses

Other taxes

Total costs and expenses

Income from operations

308

370

7,692

1,646

1,576

391

67,566

4,692

505

6,685

1,326

1,375

390

94,051

4,051

Net interest and other financial income (costs)

(318)

(216)

Income before income taxes

Provision for income taxes

Net income

Less net income attributable to noncontrolling interests

4,374

1,506

2,868

3,835

1,280

2,555

357

6,263

1,220

1,248

340

96,829

3,425

(179)

3,246

1,113

2,133

Net income attributable to MPC

Per Share Data (See Note 8)

Basic:

Net income attributable to MPC per share

Weighted average shares outstanding

Diluted:

Net income attributable to MPC per share

Weighted average shares outstanding

Dividends paid

2,852

2,524

2,112

5.29

538

5.26

542

1.14

4.42

570

4.39

574

0.92

3.34

630

3.32

634

0.77

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

104

Marathon Petroleum Corporation

Consolidated Statements of Comprehensive Income

(In millions)

Net income

Other comprehensive income (loss):

Defined benefit postretirement and post-employment plans:

Actuarial changes, net of tax of $21, ($47) and $174

Prior service costs, net of tax of ($24), ($19) and ($19)

Other comprehensive income (loss)

Comprehensive income

Less comprehensive income attributable to noncontrolling interests

2015

2014

2013

2,868

2,555

2,133

(39)

(5)

2,863

(78)

(31)

(109)

2,446

294

(34)

260

2,393

Comprehensive income attributable to MPC

2,847

2,415

2,372

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

105

Marathon Petroleum Corporation

Consolidated Balance Sheets

(In millions, except share data)

Assets
Current assets:

Cash and cash equivalents
Receivables, less allowance for doubtful accounts of $12 and $13
Inventories
Other current assets

Total current assets
Equity method investments
Property, plant and equipment, net
Goodwill
Other noncurrent assets
Total assets

Liabilities
Current liabilities:

Accounts payable
Payroll and benefits payable
Consumer excise taxes payable
Accrued taxes
Long-term debt due within one year
Other current liabilities

Total current liabilities

Long-term debt
Deferred income taxes
Defined benefit postretirement plan obligations
Deferred credits and other liabilities

Total liabilities

Commitments and contingencies (see Note 25)
Equity
MPC stockholders’ equity:

Preferred stock, no shares issued and outstanding (par value $0.01 per share, 30 million shares

authorized)
Common stock:

Issued – 729 million and 726 million shares (par value $0.01 per share, 1 billion shares

authorized)

Held in treasury, at cost – 198 million and 179 million shares

Additional paid-in capital
Retained earnings
Accumulated other comprehensive loss
Total MPC stockholders’ equity

Noncontrolling interests
Total equity
Total liabilities and equity

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

106

December 31,

2015

2014

1,127
2,927
5,225
192
9,471
3,622
25,164
4,019
839
43,115

4,743
503
460
184
29
426
6,345
11,896
3,285
1,179
735
23,440

1,494
4,058
5,642
145
11,339
865
16,261
1,566
394
30,425

6,661
427
463
647
27
354
8,579
6,575
2,014
1,099
768
19,035

7
(7,275)
11,071
9,752
(318)
13,237
6,438
19,675
43,115

7
(6,299)
9,841
7,515
(313)
10,751
639
11,390
30,425

Marathon Petroleum Corporation

Consolidated Statements of Cash Flows

(In millions)

2015

2014

2013

Increase (decrease) in cash and cash equivalents
Operating activities:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:

$ 2,868

$ 2,555

$ 2,133

Depreciation and amortization
Inventory market valuation charge
Pension and other postretirement benefits, net
Deferred income taxes
Net gain on disposal of assets
Equity method investments, net
Changes in the fair value of derivative instruments
Changes in:

Current receivables
Inventories
Current accounts payable and accrued liabilities

All other, net

Net cash provided by operating activities

Investing activities:
Additions to property, plant and equipment
Acquisitions, net of cash acquired
Disposal of assets
Investments – acquisitions, loans and contributions

– redemptions, repayments and return of capital

All other, net

Net cash used in investing activities

Financing activities:
Long-term debt – borrowings
– repayments

Debt issuance costs
Issuance of common stock
Common stock repurchased
Dividends paid
Net proceeds from issuance of MPLX LP common units
Distributions to noncontrolling interests
Tax settlement with Marathon Oil Corporation
Contingent consideration payment
All other, net

Net cash provided by (used in) financing activities

Net decrease in cash and cash equivalents
Cash and cash equivalents at beginning of period

Cash and cash equivalents at end of period

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

107

1,646
370
80
134
(7)
25
4

1,292
80
(2,400)
(31)

4,061

(1,998)
(1,218)
21
(331)
4
81

(3,441)

2,993
(2,226)
(21)
33
(965)
(613)
-
(40)
-
(175)
27

(987)

(367)
1,494

1,326
-
151
(242)
(21)
17
(3)

1,642
(786)
(1,547)
18

3,110

(1,480)
(2,821)
27
(413)
9
135

(4,543)

3,793
(548)
(22)
26
(2,131)
(524)
221
(27)
-
(172)
19

635

(798)
2,292

1,220
-
(124)
23
(6)
(18)
(21)

(940)
(305)
1,464
(21)

3,405

(1,206)
(1,515)
16
(151)
77
23

(2,756)

-
(21)
(4)
48
(2,793)
(484)
-
(21)
39
-
19

(3,217)

(2,568)
4,860

$ 1,127

$ 1,494

$ 2,292

Marathon Petroleum Corporation

Consolidated Statements of Equity

(In millions)

Balance as of December 31, 2012

Balance as of December 31, 2013

Net income
Dividends declared
Distributions to noncontrolling interests
Other comprehensive loss
Shares repurchased
Shares issued (returned) – stock-based compensation
Stock-based compensation
Issuance of MPLX LP common units
Other

Balance as of December 31, 2014

Net income
Dividends declared
Distributions to noncontrolling interests
Other comprehensive income
Shares repurchased
Shares issued (returned) – stock-based compensation
Stock-based compensation
Issuance of MPLX LP common units
Issuance of MPLX LP common units – MarkWest Merger
Issuance of MPLX LP Class B units – MarkWest Merger
Tax effect of issuance of MPLX units – MarkWest Merger
Noncontrolling interest – MarkWest Merger
Other

MPC Stockholders’ Equity

Common
Stock

Treasury
Stock

Additional
Paid-in
Capital

Retained
Earnings

Accumulated
Other
Comprehensive
Income (Loss)

Non-controlling
Interests

Total
Equity

7 $ (1,253) $
-
-
-
-
-
-
-
-

-
-
-
-
(2,893)
(9)
-
-

7 $ (4,155) $
-
-
-
-
-
-
-
-
-

-
-
-
-
(2,131)
(13)
-
-
-

7 $ (6,299) $
-
-
-
-
-
-
-
-
-
-
-
-

-
-
-
-
(965)
(11)
-
-
-
-
-
-

9,524 $

-
-
-
-

100
47
55
39

9,765 $

-
-
-
-
-
26
50

-
-

9,841 $

-
-
-
-
-
33
69

-
1,481
51
(404)
-

3,880
2,112
(485)
-
-
-
-
-
-

5,507
2,524
(525)
-
-
-
-
-
-

7,515
2,852
(615)
-
-
-
-
-
-
-
-
-
-

(464)
-
-
-

260

-
-
-
-

(204)
-
-
-
(109)
-
-
-
-
-

(313)
-
-
-
(5)
-
-
-
-
-
-
-
-

411
21

-
(21)
-
-
-

412
31

-
(27)
-
-
-

2
221
-

639
16

-
(40)
-
-
-

16
1
5,579
215

13
(1)

12,105
2,133
(485)
(21)
260
(2,793)
38
56
39

11,332
2,555
(525)
(27)
(109)
(2,131)
13
52
221
9

11,390
2,868
(615)
(40)
(5)
(965)
22
85
1
7,060
266
(404)
13
(1)

Balance as of December 31, 2015

7 $ (7,275) $

11,071 $

9,752

(318)

6,438

19,675

(Shares in millions)

Balance as of December 31, 2012

Shares repurchased
Shares issued – stock-based compensation

Balance as of December 31, 2013

Shares repurchased
Shares issued – stock-based compensation

Balance as of December 31, 2014

Shares repurchased
Shares issued (returned) – stock-based compensation

Balance as of December 31, 2015

Common
Stock

Treasury
Stock

722
-
2

724
-
2

726
-
3

729

(56)
(74)
-

(130)
(49)
-

(179)
(19)
-

(198)

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

108

Notes to Consolidated Financial Statements

1. Description of the Business and Basis of Presentation

Description of the Business – Our business consists of refining and marketing, retail and midstream services
conducted primarily in the Midwest, Gulf Coast, East Coast, Northeast and Southeast regions of the United
States, through subsidiaries, including Marathon Petroleum Company LP, Speedway LLC and its subsidiaries
(“Speedway”) and MPLX LP and its subsidiaries (“MPLX”).

See Note 10 for additional information about our operations.

Spinoff – On May 25, 2011, the Marathon Oil board of directors approved the spinoff of its Refining,
Marketing & Transportation Business (“RM&T Business”) into an independent, publicly traded company, MPC,
through the distribution of MPC common stock to the stockholders of Marathon Oil common stock (the
“Spinoff”). MPC became an independent, publicly traded company on July 1, 2011.

Basis of Presentation – Our results of operations and cash flows consist of consolidated MPC activities. All
significant intercompany transactions and accounts have been eliminated.

We completed a two-for-one stock split in June 2015. All historical share and per share data included in these
consolidated financial statements has been retroactively restated on a post-split basis. Additionally, we adopted
the updated FASB debt issuance cost standard as of June 30, 2015 and applied the changes retrospectively to the
prior period presented. We also adopted the updated FASB deferred tax simplification standard in the fourth
quarter of 2015. Since we have elected to apply this standard prospectively, the prior period has not been
retrospectively adjusted.

2. Summary of Principal Accounting Policies

Principles applied in consolidation – These consolidated financial statements include the accounts of our
majority-owned, controlled subsidiaries and MPLX. Changes in ownership interest in consolidated subsidiaries
that do not result in a change in control are recorded as an equity transaction. We own 20.4 percent of MPLX,
including the two percent general partner interest. Due to our 100 percent ownership of the general partner
interest, we have determined that we control MPLX and therefore we consolidate MPLX and record a
noncontrolling interest for the 79.6 percent interest owned by the public.

Investments in entities over which we have significant influence, but not control, are accounted for using the
equity method of accounting. This includes entities in which we hold majority ownership but the minority
shareholders have substantive participating rights. Income from equity method investments represents our
proportionate share of net income generated by the equity method investees.

Equity method investments are generally carried at our share of net assets plus loans and advances. Such
investments are assessed for impairment whenever changes in the facts and circumstances indicate an other than
temporary loss in value has occurred. When the loss is deemed to be other than temporary, the carrying value of
the equity method investment is written down to fair value, and the amount of the write-down is included in net
income. 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.

Use of estimates – The preparation of financial statements in accordance with generally accepted accounting
principles 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.

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Revenue recognition – Revenues are recognized when products are shipped or services are provided to
customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured.
Costs associated with revenues are recorded in cost of revenues. Shipping and other transportation costs billed to
our customers are presented on a gross basis in revenues and cost of revenues.

Rebates from vendors are recognized as a reduction of cost of revenues when the initiating transaction occurs.
Incentives that are derived from contractual provisions are accrued based on past experience and recognized in
cost of revenues. Rebates to customers are reflected as a reduction of revenue and are accrued for in accounts
payable on the consolidated balance sheets.

Crude oil and refined product exchanges and matching buy/sell transactions – We enter into exchange
contracts and matching buy/sell arrangements whereby we agree to deliver a particular quantity and quality of
crude oil or refined products at a specified location and date to a particular counterparty and to receive from the
same counterparty the same commodity at a specified location on the same or another specified date. The
exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location
differentials that are settled in cash. The matching buy/sell purchase and sale transactions are settled in cash.
Both exchange and matching buy/sell transactions are accounted for as exchanges of inventory and no revenues
are recorded. The exchange transactions are recognized at the carrying amount of the inventory transferred.

Consumer excise taxes – We are required by various governmental authorities, including countries, states and
municipalities, to collect and remit taxes on certain consumer products. Such taxes are presented on a gross basis
in revenues and costs and expenses in the consolidated statements of income.

Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in
highly liquid debt instruments with 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, 2015
and 2014, the amount of restricted cash included in other current assets on the consolidated balance sheets were
$9 million and $4 million, which is currently reflected in our Midstream segment.

Accounts receivable and allowance for doubtful accounts – Our receivables primarily consist of customer
accounts receivable. Customer receivables are recorded at the invoiced amounts and generally do not bear
interest. Allowances for doubtful accounts are generally recorded when it becomes probable the receivable will
not be collected and are booked to bad debt expense. The allowance for doubtful accounts is the best estimate of
the amount of probable credit losses in customer accounts receivable and is based on historical write-off
experience. We review the allowance quarterly and past-due balances over 180 days are reviewed individually
for collectability.

Approximately 26 percent and 41 percent of our accounts receivable balances at December 31, 2015 and 2014,
respectively, are related to sales of crude oil or refinery feedstocks to customers with whom we have master
netting agreements. We have master netting agreements with more than 100 companies engaged in the crude oil
or refinery feedstock trading and supply business or the petroleum refining industry. A master netting agreement
generally provides for a once per month net cash settlement of the accounts receivable from and the accounts
payable to a particular counterparty.

Inventories – Inventories are carried at the lower of cost or market value. Cost of inventories is determined
primarily under the LIFO method. Costs for crude oil, refinery feedstocks and refined product inventories are
aggregated on a consolidated basis for purposes of assessing if the LIFO cost basis of these inventories may have
to be written down to market value.

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Derivative instruments – We use derivatives to economically hedge a portion of our exposure to commodity
price risk and, historically, to interest rate risk. We also have limited authority to use selective derivative
instruments that assume market risk. All derivative instruments (including derivative instruments embedded in
other contracts) are recorded at fair value. Commodity derivatives are reflected on the consolidated balance
sheets on a net basis by counterparty as they are governed by master netting agreements. Cash flows related to
derivatives used to hedge commodity price risk and interest rate risk are classified in operating activities with the
underlying transactions.

Fair value accounting hedges – We used interest rate swaps to hedge our exposure to interest rate risk associated
with fixed interest rate debt in our portfolio. These interest rate swap agreements were terminated in 2012.
Changes in the fair values of both the hedged item and the related derivative were recognized immediately in net
income with an offsetting effect included in the basis of the hedged item. The net effect was to report in net
income the extent to which the accounting hedge was not effective in achieving offsetting changes in fair value.
There was a gain on the termination of the agreements, which has been accounted for as an adjustment to our
long-term debt balance. The gain was being amortized over the remaining life of the associated debt as a
reduction of our interest expense, until the December 2015 extinguishment of our obligation for the associated
debt. At such time, the remaining unamortized gain was credited to net interest and other financial income
(costs).

Derivatives not designated as accounting hedges – Derivatives that are not designated as accounting hedges may
include commodity derivatives used to hedge price risk on (1) inventories, (2) fixed price sales of refined
products, (3) the acquisition of foreign-sourced crude oil, (4) the acquisition of ethanol for blending with refined
products, (5) the sale of NGLs, (6) the purchase of natural gas and (6) the purchase of electricity. Changes in the
fair value of derivatives not designated as accounting hedges are recognized immediately in net income.

Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit
and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The
counterparties to our financial instruments consist primarily of major financial institutions and companies within
the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor
counterparties based on an assessment of their financial strength and on credit ratings, if available. Additionally,
we limit the level of exposure with any single counterparty.

Property, plant and equipment – Property, plant and equipment are recorded at cost and depreciated on a
straight-line basis over the estimated useful lives of the assets, which range from two to 42 years. Such assets are
reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an
asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset
and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based
on the fair value of the asset.

When items of property, plant and equipment are sold or otherwise disposed of, any gains or losses are reported
in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is
generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are
classified as held for sale.

Interest expense is capitalized for qualifying assets under construction. Capitalized interest costs are included in
property, plant and equipment and are depreciated over the useful life of the related asset.

Goodwill and intangible assets – Goodwill represents the excess of the purchase price over the estimated fair
value of the net assets acquired in the acquisition of a business. Goodwill is not amortized, but rather is tested for
impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit
with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other
assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the

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book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including
goodwill, the implied fair value of goodwill is calculated. The excess, if any, of the book value over the implied
fair value of goodwill is charged to net income.

Amortization of intangibles with definite lives is calculated using the straight-line method which is reflective of
the benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful
life of the intangible asset. Intangibles not subject to amortization are reviewed for impairment whenever events
or changes in circumstances indicate that the carrying amount of the intangible may not be recoverable. If the
sum of the expected undiscounted future cash flows related to the asset is less than the carrying amount of the
asset, an impairment loss is recognized based on the fair value of the asset.

Major maintenance activities – Costs for planned turnaround, major maintenance and engineered project
activities are expensed in the period incurred. These types of costs include contractor repair services, materials
and supplies, equipment rentals and our labor costs.

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. We recognize
remediation costs and penalties when the responsibility to remediate is probable and the amount of associated
costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility
study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of
known environmental exposure and are discounted when the estimated amounts are reasonably fixed and
determinable. If recoveries of remediation costs from third parties are probable, a receivable is recorded and is
discounted when the estimated amount is reasonably fixed and determinable.

Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which
the obligations are incurred if a reasonable estimate of fair value can be made. The majority of our recognized
asset retirement liability relates to conditional asset retirement obligations for removal and disposal of fire-
retardant material from certain refining facilities. The remaining recognized asset retirement liability relates to
other refining assets, the removal of underground storage tanks at our leased convenience stores, certain pipelines
and processing facilities and other related pipeline assets. The fair values recorded for such obligations are based
on the most probable current cost projections. The recorded asset retirement obligations are not material to the
consolidated financial statements.

Asset retirement obligations have not been recognized for some assets because the fair value cannot be
reasonably estimated since the settlement dates of the obligations are indeterminate. Such obligations will be
recognized in the period when sufficient
information becomes available to estimate a range of potential
settlement dates. The asset retirement obligations principally include the hazardous material disposal and
removal or dismantlement requirements associated with the closure of certain refining, terminal, retail, pipeline
and processing assets.

Our practice is to keep our assets in good operating condition through routine repair and maintenance of
component parts in the ordinary course of business and by continuing to make improvements based on
technological advances. As a result, we believe that generally these assets have no expected settlement date for
purposes of estimating asset retirement obligations since the dates or ranges of dates upon which we would retire
these assets cannot be reasonably estimated at this time.

Income taxes – Deferred tax assets and liabilities are recognized for the estimated future tax consequences
attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax
bases. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization
of deferred tax assets is assessed periodically based on several factors, primarily our expectation to generate
sufficient future taxable income.

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Stock-based compensation arrangements – The fair value of stock options granted to our employees is estimated
on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions,
based on management’s estimates at the time of grant, which impact the calculation of fair value and ultimately,
the amount of expense that is recognized over the vesting period of the stock option award. Of the required
assumptions, the expected life of the stock option award and the expected volatility of our stock price have the
most significant impact on the fair value calculation. The average expected life is based on our historical
employee exercise behavior. The assumption for expected volatility of our stock price reflects a weighting of 50
percent of our common stock implied volatility and 50 percent of MPC’s common stock historical volatility.

The fair value of restricted stock awards granted to our employees is determined based on the fair market value
of our common stock on the date of grant. The fair value of performance unit awards granted to our employees is
estimated on the date of grant using a Monte Carlo valuation model.

Our stock-based compensation expense is recognized based on management’s estimate of the awards that are
expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting
feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense
may be required in future periods. Unearned stock-based compensation is charged to equity when restricted stock
awards are granted. Compensation expense is recognized over the vesting period and is adjusted if conditions of
the restricted stock award are not met.

Business combinations – We recognize and measure 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, we 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 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.

Renewable fuel identification numbers – We purchase RINs to satisfy a portion of our RFS2 compliance. We
record a short-term intangible asset, included in other current assets on the balance sheet, for RINs owned in
excess of our anticipated current period compliance requirements. The asset value is based on the product of the
excess RINs as of the balance sheet date, if any, and the average cost of our RINs. We record a current liability,
included in other current liabilities on the balance sheet, when we are deficient RINs based on the product of the
deficient RINs as of the balance sheet date, if any, and the market price of the RINs at the balance sheet date. The
cost of RINs used for compliance is reflected in cost of revenues. Any gains or losses on the sale or expiration of
RINs are classified as other income. Proceeds from RIN sales are included in investing activities – all other, net
on the cash flow statement.

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3. Accounting Standards

Recently Adopted

In November 2015, the FASB issued an accounting standards update to simplify the balance sheet classification
of deferred taxes. The update requires that deferred tax assets and liabilities, along with any related valuation
allowance, be classified as noncurrent on the balance sheet. The update does not change the existing requirement
that only permits offsetting within a jurisdiction. The change is effective for fiscal years and interim periods
within those fiscal years beginning after December 15, 2016. The guidance may be applied either prospectively
or retrospectively with early adoption permitted. Our early adoption of this standard in the fourth quarter of 2015
did not have a material impact on our consolidated results of operations, financial position or cash flows. We
have elected to apply this standard prospectively, therefore, prior periods have not been retrospectively adjusted.

In April 2015, the FASB issued an accounting standards update to simplify the presentation of debt issuance
costs. The update requires that debt issue costs for term debt are to be presented on the balance sheet as a direct
reduction of the term debt liability as opposed to a deferred charge within other noncurrent assets. The change is
effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2015.
Retrospective application is required and early adoption is permitted. Our early adoption of this standard in the
second quarter of 2015 did not have a material impact on our consolidated results of operations, financial
position or cash flows. In August 2015, the FASB subsequently issued a clarification as to the handling of debt
issuance costs related to line-of-credit arrangements that allows for the presentation of these costs as an asset.
This clarification did not have any impact on our consolidated results of operations, financial position or cash
flows.

In June 2014, the FASB issued an accounting standards update for the elimination of the concept of development
stage entity (“DSE”) from U.S. GAAP and removes the related incremental reporting. The standards update
eliminates the additional financial statement requirements specific to a DSE and was adopted in the first quarter
of 2015. In addition, the portion of the standard to amend the consolidation model that eliminates the special
provisions in the VIE rules for assessing the sufficiency of the equity of a DSE is effective in the first quarter of
2016. Adoption of this standards update in the first quarter of 2015 and 2016 has not and is not expected to have
an impact on our consolidated results of operations, financial position or cash flows.

In April 2014, the FASB issued an accounting standards update that redefines the criteria for determining
discontinued operations and introduces new disclosures related to these disposals. The updated definition of a
discontinued operation is the disposal of a component (or components) of an entity or the classification of a
component (or components) of an entity as held for sale that represents a strategic shift for an entity and has (or
will have) a major impact on an entity’s operations and financial results. The standard requires disclosure of
additional financial information for discontinued operations and individually material components not qualifying
for discontinued operation presentation, as well as information regarding an entity’s continuing involvement with
the discontinued operation. The accounting standards update was effective prospectively for annual periods
beginning on or after December 15, 2014, and interim periods within those years. Adoption of this standards
update in the first quarter of 2015 did not impact our consolidated results of operations, financial position or cash
flows.

Not Yet Adopted

In January 2016, the FASB issued an accounting standards update requiring unconsolidated equity investments,
not accounted for under the equity method, to be measured at fair value with changes in fair value recognized in
net income. The update also requires the use of the exit price notion when measuring the fair value of financial
instruments for disclosure purposes and the separate presentation of financial assets and liabilities by
measurement category and form on the balance sheet and accompanying notes. The update eliminates the
requirement to disclose the methods and assumptions used in estimating the fair value of financial instruments
measured at amortized cost. Lastly, the update requires separate presentation in other comprehensive income of

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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. Upon adoption, entities will be required to make a cumulative-effect
adjustment to the consolidated results of operations as of the beginning of the first reporting period the guidance
is effective. Early adoption is permitted only for the amendment regarding presentation of liability’s credit risk.
We are in the process of determining the impact of the new standard on the consolidated financial statements.

In September 2015, the FASB issued an accounting standard update that eliminates the requirement to restate
prior period financial statements for measurement period adjustments for business combinations. This update
requires that the cumulative impact of a measurement period adjustment be recognized in the reporting period in
which the adjustment is identified. The standard is effective for interim and annual periods beginning after
December 15, 2015 with early application permitted. Adoption of this standard is not expected to have a material
impact on our consolidated results of operations, financial position or cash flows.

In May 2015, the FASB issued an accounting standard update that eliminates the requirement to categorize in the
fair value hierarchy investments that are measured at net asset value using the practical expedient. The standard
is effective for fiscal years beginning after December 15, 2015 and interim periods within the fiscal year.
Retrospective application is required and early adoption is permitted. While we expect adoption of this standard
to affect our fair value hierarchy disclosures, we do not believe it will have an impact on our consolidated results
of operations, financial position or cash flows.

In April 2015, the FASB issued an accounting standards 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 is effective for fiscal years and interim periods within those fiscal years beginning after
December 15, 2015. Retrospective or prospective application is allowed and early adoption is permitted.
Adoption of this standard is not expected to have a material impact on our consolidated results of operations,
financial position or cash flows.

In February 2015, the FASB issued an accounting standards update making targeted changes to the current
consolidation guidance. The new standard 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 update is effective for fiscal
years and interim periods within those fiscal years beginning after December 15, 2015. Early adoption is
permitted. We expect to continue to consolidate our master limited partnership, MPLX, after implementing this
standard, but it will impact the determination of whether MPLX is a VIE and related disclosures. Otherwise the
standard is not expected to have a material impact on our results of operations, financial position or cash flows.

In August 2014, the FASB issued an accounting standards 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 will be required to assess if there is substantial doubt about an entity’s ability to continue as a going
concern within one year after the date that the financial statements are issued. Disclosures will be required if
conditions give rise to substantial doubt and the type of disclosure will be determined based on whether
management’s plans will be able to alleviate the substantial doubt. The accounting standards update will be
effective for the first annual period ending after December 15, 2016, and for annual periods and interim periods
thereafter with early application permitted. We do not expect application of this standard to have an impact on
our financial reporting.

In May 2014, the FASB issued an accounting standards update for revenue recognition that is aligned with the
International Accounting Standards Board’s revenue recognition standard. The guidance in the update states that
revenue is recognized when a customer obtains control of a good or service. Recognition of the revenue will

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identifying the separate performance
involve a multiple step approach including identifying the contract,
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 accounting standards update will be effective on a retrospective or modified
retrospective basis for annual reporting periods beginning after December 15, 2017, and interim periods within
those years, with early adoption permitted, no earlier than January 1, 2017. We are in the process of determining
the impact of the new standard on our consolidated financial statements.

4. MPLX LP

MPLX is a publicly traded master limited partnership formed by us to own, operate, develop and acquire
pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and
other hydrocarbon-based products. On December 4, 2015, MPLX and MarkWest Energy Partners, L.P.
(“MarkWest”) completed a merger, whereby MarkWest became a wholly-owned subsidiary of MPLX (the
“MarkWest Merger”). MarkWest’s operations include: natural gas gathering, processing and transportation; NGL
gathering, transportation, fractionation, storage and marketing; and crude oil gathering and transportation.

Prior to the MarkWest Merger, we owned a 71.5 percent interest in MPLX, which included the two percent
general partner interest. Each common unit of MarkWest issued and outstanding at the time of the MarkWest
Merger was converted into the right to receive 1.09 common units of MPLX and, as of December 31, 2015, our
ownership interest in MPLX was 20.4 percent, including the two percent general partner interest. Due to our 100
percent ownership of the general partner interest, we have determined that we control MPLX and therefore we
consolidate MPLX and record a noncontrolling interest for the 79.6 percent interest owned by the public.

Sales and Contributions to MPLX

On May 1, 2013, we sold a five percent interest in Pipe Line Holdings to MPLX for $100 million, which was
financed by MPLX with cash on-hand.

On March 1, 2014, we sold MPLX a 13 percent interest in Pipe Line Holdings for $310 million. MPLX financed
this transaction with $40 million of cash on-hand and $270 million of borrowings on its bank revolving credit
facility.

On December 4, 2015, we sold our remaining 0.5 percent interest in Pipe Line Holdings to MPLX for $12
million. As a result, MPLX now owns 100 percent of Pipe Line Holdings.

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Public Offerings

On February 12, 2015, MPLX completed a public offering of $500 million aggregate principal amount of four
percent unsecured senior notes due February 15, 2025. See Note 19 for more information.

Agreements

We have various long-term, fee-based transportation and storage services agreements with MPLX. Under these
agreements, MPLX provides transportation and storage services to us, and we commit to provide MPLX with
minimum quarterly throughput volumes on crude oil and refined products systems and minimum storage
volumes of crude oil, refined products and butane. We also have agreements with MPLX which establish fees for
operational and management services provided between us and MPLX and for executive management services
and certain general and administrative services provided by us to MPLX. These transactions are eliminated in
consolidation.

5. Acquisitions and Investments

Merger with MarkWest Energy Partners, L.P.

On December 4, 2015, MPLX completed the MarkWest Merger. 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 of MPLX representing limited partner interests in MPLX, plus a one-time cash payment of
$6.20 per unit. We will contribute approximately $1.28 billion of cash to MPLX to pay the aggregate cash
consideration to MarkWest unitholders, without receiving any new equity from MPLX in exchange. At closing,
we made a payment of $1.23 billion to MarkWest common unitholders and the remaining $50 million will be
paid in equal amounts in July 2016 and July 2017, respectively, in connection with the conversion of the MPLX
Class B units to MPLX common units. Our financial results and operating statistics reflect the results of
MarkWest from the date of the MarkWest Merger.

The components of the fair value of consideration transferred are as follows:

(In millions)

Fair value of MPLX units issued

Cash payment to MarkWest unitholders

Payable to MarkWest Class B unitholders

Total fair value of consideration transferred

7,326

1,230

8,606

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The following table summarizes the preliminary purchase price allocation. Due to the proximity of the MarkWest
Merger to December 31, 2015, we are still completing our analysis of the final purchase price allocation for
property, plant and equipment, intangibles and deferred taxes. The estimated fair value of assets acquired and
liabilities and noncontrolling interests assumed at the acquisition date, are as follows:

(In millions)

Cash and cash equivalents

Receivables

Inventories

Other current assets

Equity method investments

Property, plant and equipment, net

Other noncurrent assets

Total assets acquired

Accounts payable

Payroll and benefits payable

Accrued taxes

Other current liabilities

Long-term debt

Deferred income taxes

Deferred credit and other liabilities

Noncontrolling interests

Total liabilities and noncontrolling interest assumed

Net assets acquired excluding goodwill

Goodwill

Net assets acquired

164

2,457

8,474

473

11,657

322

4,567

374

151

5,505

6,152

2,454

8,606

Included in noncurrent assets is a $468 million intangible asset related to customer contracts and relationships.
Amortization of intangibles with definite lives is calculated using the straight-line method which is reflective of
the benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful
life of the intangible asset. The estimated useful life of the customer contracts and relationships is 11 to 25 years.

The purchase price allocation resulted in the recognition of $2.45 billion in goodwill by our Midstream 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 that will provide significant additional opportunities
across the hydrocarbon value chain. In addition,
integration
opportunities, as MPC is a large consumer of NGLs.

the combination provides significant vertical

We recognized $36 million of transaction costs related to the MarkWest Merger. These costs were expensed and
$30 million is included in selling, general and administrative expenses and $6 million is in net interest and other
financial income (costs).

The amounts of revenue and income from operations associated with the MarkWest Merger included in our
consolidated statements of income for 2015 are as follows:

(In millions)

Sales and other operating revenues (including consumer excise taxes)

Income from operations

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2015

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Acquisition of Hess’ Retail Operations and Related Assets

On September 30, 2014, we acquired from Hess Corporation (“Hess”) all of Hess’ retail locations, transport
operations and shipper history on various pipelines, including approximately 40,000 barrels per day on Colonial
Pipeline, for $2.82 billion. We refer to these assets as “Hess’ Retail Operations and Related Assets.” The
transaction was funded with a combination of debt and available cash. The transaction provided for an
adjustment for working capital, which was finalized with Hess during the first quarter of 2015, resulting in a $3
million reduction to our total consideration.

The components of the fair value of consideration transferred are as follows:

(In millions)

Cash

Net working capital adjustment estimate

Total fair value of consideration transferred

2,824

(3)

2,821

During the fourth quarter of 2014, an independent appraisal of the assets acquired and liabilities assumed and
other evaluations were completed and finalized. Updates to the preliminary fair value measurements of assets
acquired and liabilities assumed were made during the fourth quarter of 2014. The following table summarizes
the amounts assigned to the assets acquired and liabilities assumed as of the acquisition date.

(In millions)

Cash and cash equivalents

Receivables

Inventories

Other current assets

Property, plant and equipment, net

Other noncurrent assets

Total assets acquired

Accounts payable

Payroll and benefits payable

Consumer excise taxes payable

Accrued taxes

Other current liabilities

Defined benefit postretirement plan obligations

Deferred credits and other liabilities

Total liabilities assumed

Net assets acquired excluding goodwill

Goodwill

Net assets acquired

123

165

2,063

111

2,519

155

327

2,192

629

2,821

The purchase price allocation resulted in the recognition of $629 million in goodwill by our Speedway segment.
The goodwill primarily relates to the expected benefits of a significantly expanded retail platform that should
enable growth in new markets, as well as the potential for higher merchandise sales by utilizing Speedway’s
marketing approach at the acquired locations. The goodwill is deductible for tax purposes.

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Other noncurrent assets includes a $22 million intangible asset related to a trade name and $72 million related to
favorable lease contract terms. Deferred credits and other liabilities includes $90 million related to unfavorable
lease contract terms. The trade name is being amortized over its estimated useful life of two years based on the
utilization of the assets. The favorable and unfavorable lease contract amounts are being amortized over the
terms of the leases.

We recognized $14 million of acquisition-related costs associated with Hess’ Retail Operations and Related
Assets acquisition. These costs were expensed and were included in selling, general and administrative expenses.

The amounts of revenue and income from operations associated with Hess’ Retail Operations and Related Assets
included in our consolidated statements of income for 2014 are as follows:

(In millions)

Sales and other operating revenues (including consumer excise taxes)

Income from operations

Acquisition of Refinery and Related Logistics and Marketing Assets

2014

2,403

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On February 1, 2013, we acquired from BP Products North America Inc. and BP Pipelines (North America) Inc.
(collectively, “BP”) the 451,000 barrel per calendar day refinery in Texas City, Texas, three intrastate natural gas
liquid pipelines originating at the refinery, four light product terminals, branded-jobber marketing contract
assignments for the supply of approximately 1,200 branded sites, a 1,040 megawatt electric cogeneration facility
and a 50,000 barrel per day allocation of space on the Colonial Pipeline. We refer to these assets as the
“Galveston Bay Refinery and Related Assets.” We paid $1.49 billion for these assets, which included $935
million for inventory. The transaction was funded with cash on-hand. Pursuant to the purchase and sale
agreement, we may also be required to pay to BP a contingent earnout of up to an additional $700 million over
six years. See Note 17 for additional information on the contingent consideration.

Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the Galveston Bay
Refinery and Related Assets acquisition.

We recognized $7 million of acquisition-related costs associated with the Galveston Bay Refinery and Related
Assets acquisition. These costs were expensed and were included in selling, general and administrative expenses.

Our refineries and related assets are operated as an integrated system. As the information is not available by
refinery, it is not practicable to disclose the revenues and net income associated with the acquisition that were
included in our consolidated statements of income for 2013.

Unaudited Pro Forma Financial Information

The following unaudited pro forma financial information presents consolidated results assuming the MarkWest
Merger occurred on January 1, 2014, the Hess’ Retail Operations and Related Assets acquisition occurred on
January 1, 2013 and the Galveston Bay Refinery and Related Assets acquisition occurred on January 1, 2012.
The unaudited pro forma financial information does not give effect to potential synergies that could result from
the transactions and is not necessarily indicative of the results of future operations.

(In millions, except per share data)

2015

2014

2013

Sales and other operating revenues (including consumer excise taxes)

Net income attributable to MPC

Net income attributable to MPC per share – basic

Net income attributable to MPC per share – diluted

73,760

2,825

5.25

5.21

108,605

2,522

4.42

4.39

114,148

2,142

3.40

3.38

120

The unaudited pro forma information includes adjustments to align accounting policies, an adjustment to
depreciation expense to reflect the fair value of property, plant and equipment, increased amortization expense
related to identifiable intangible assets, adjustments to amortize the fair value adjustment for the debt assumed by
MPLX, adjustments to reflect the change in our limited partner interest in MPLX resulting from the MarkWest
Merger, additional interest expense related to financing the acquisition of Hess’ Retail Operations and Related
Assets, as well as the related income tax effects.

Acquisition of Biodiesel Facility

On April 1, 2014, we purchased a facility in Cincinnati, Ohio from Felda Iffco Sdn Bhd, Malaysia for $40
million. The plant currently produces biodiesel, glycerin and other by-products. The production capacity of the
plant is approximately 60 million gallons per year.

Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the biodiesel facility
acquisition.

Assuming the acquisition of the biodiesel facility in 2014 had been made at the beginning of any period
presented, the consolidated pro forma results would not be materially different from reported results.

Investments in Ethanol Companies

Investment in Ocean Vessel Joint Venture

In September 2015, we acquired a 50 percent ownership interest in a new joint venture with Crowley Maritime
Corporation through our investment in Crowley Ocean Partners LLC (“Crowley Ocean Partners”), which is
included in our Refining & Marketing segment. The joint venture will operate and charter four new Jones Act
product tankers, most of which will be leased to MPC. Contributions to the joint venture with respect to each
vessel will occur at the vessel’s delivery. During 2015, we contributed $72 million in connection with delivery of
the first two vessels. The remaining two vessels are expected to be delivered by the third quarter of 2016. We
account for our ownership interest in Crowley Ocean Partners as an equity method investment. See Note 25 for
information on our conditional guarantee of the indebtedness of the joint venture and future contributions to
Crowley Ocean Partners.

Investments in Pipeline Companies

In July 2014, we exercised our option to acquire a 35 percent ownership interest in Enbridge Inc.’s Southern
Access Extension pipeline (“SAX”) through our investment in Illinois Extension Pipeline Company, LLC
(“Illinois Extension Pipeline”). During 2015, we made contributions of $147 million to Illinois Extension
Pipeline to fund our portion of the construction costs for the SAX project. We have contributed $267 million
since project inception. We account for our ownership interest in Illinois Extension Pipeline as an equity method
investment. During the construction of the pipeline, our ownership interest in Illinois Extension Pipeline was
considered a VIE. Upon completion and start up of the pipeline in December of 2015, a reassessment determined
that our investment is no longer considered a VIE. Our investment in the pipeline and our share of its results are
included in our Midstream segment.

121

In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional seven percent interest
in Explorer Pipeline Company (“Explorer”) for $77 million, bringing our ownership interest to 25 percent. As a
result of this increase in our ownership, we now account for our investment in Explorer using the equity method
of accounting rather than the cost method. The cumulative impact of the change was applied as an adjustment to
2014 retained earnings.

In November 2013, we agreed to serve as an anchor shipper for the Sandpiper pipeline project and fund 37.5
percent of the construction costs of the project, which will become part of Enbridge Energy Partners L.P.’s
(“Enbridge Energy Partners”) North Dakota System. In exchange for these commitments, we will earn an
approximate 27 percent equity interest in Enbridge Energy Partners’ North Dakota System when the Sandpiper
pipeline is placed into service. The anticipated in-service date for the pipeline is likely to be delayed to early
2019. The project schedule and cost estimates remain under review. We also have the option to increase our
ownership interest to approximately 30 percent through additional investments in future system improvements.
We made contributions of $71 million to North Dakota Pipeline Company LLC (“North Dakota Pipeline”) during
2015 and have contributed $287 million since project inception, which are reflected in our Midstream segment.
We account for our interest in North Dakota Pipeline using the equity method of accounting. See Note 25 for
information on future contributions to North Dakota Pipeline.

6. Variable Interest Entities

MarkWest Utica EMG

On January 1, 2012, MarkWest Utica Operating Company, LLC (“Utica Operating”), a wholly-owned and
consolidated subsidiary of MarkWest, and EMG Utica, LLC (“EMG Utica”) (together the “Members”), executed
to develop
agreements to form a joint venture, MarkWest Utica EMG LLC (“MarkWest Utica EMG”),
significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure
in eastern Ohio.

MarkWest has a 60 percent legal ownership interest in MarkWest Utica EMG. MarkWest Utica EMG’s inability to
fund its planned activities without subordinated financial support qualify it as a VIE. Utica Operating is not deemed
to be the primary beneficiary due to EMG Utica’s voting rights on significant matters. We account for our
ownership interest in MarkWest Utica EMG as an equity method investment. MPLX receives engineering and
construction and administrative management fee revenue and reimbursement for other direct personnel costs for
operating MarkWest Utica EMG. Our maximum exposure to loss as a result of our involvement with MarkWest
Utica EMG includes our equity investment, any additional capital contribution commitments and any operating
expenses incurred by the subsidiary operator in excess of compensation received for the performance of the
operating services. Our equity investment in MarkWest Utica EMG at December 31, 2015 was $2.16 billion.

Ohio Gathering

Ohio Gathering Company, L.L.C. (“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 (“Summit”). As of December 31, 2015, we had
a 36 percent indirect ownership interest in Ohio Gathering. As this entity is a subsidiary of MarkWest Utica
EMG, which is accounted for as an equity method investment, MPLX reports its portion of Ohio Gathering’s net
assets as a component of its investment in MarkWest Utica EMG. MPLX receives engineering and construction
and administrative management fee revenue and reimbursement for other direct personnel costs for operating
Ohio Gathering.

122

7. Related Party Transactions

Our related parties included:

• Centennial Pipeline LLC (“Centennial”), in which we have a 50 percent noncontrolling interest.

Centennial owns a refined products pipeline and storage facility.

• Crowley Ocean Partners, in which we have a 50 percent noncontrolling interest. Crowley Ocean

Partners operates and charters Jones Act product tankers.

• Explorer, in which we have a 25 percent interest. Explorer owns and operates a refined products pipeline.

•

Illinois Extension Pipeline, in which we have a 35 percent noncontrolling interest. Illinois Extension
Pipeline owns and operates a crude oil pipeline.

• LOCAP LLC (“LOCAP”), in which we have a 59 percent noncontrolling interest. LOCAP owns and

operates a crude oil pipeline.

• LOOP LLC (“LOOP”), in which we have a 51 percent noncontrolling interest. LOOP owns and

operates the only U.S. deepwater oil port.

• MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“MarkWest EMG Jefferson”), in
which we have a 67 percent noncontrolling interest. Jefferson Dry Gas is engaged in dry natural gas
gathering in the county of Jefferson, Ohio.

• MarkWest Utica EMG, in which we have a 60 percent noncontrolling interest. MarkWest Utica EMG

owns and operates an NGL pipeline and natural gas gathering system.

• Ohio Condensate, in which we have a 60 percent noncontrolling interest. Ohio Condensate owns and
operates wellhead condensate stabilization and gathering services for certain locations within Ohio.

• Ohio Gathering, in which we have a 36 percent indirect noncontrolling interest. Ohio Gathering owns,

operates and develops midstream gathering infrastructure in southeastern Ohio.

• TAAE, in which we have a 43 percent noncontrolling interest, TACE, in which we have a 60 percent
noncontrolling interest and TAME, in which we have a 67 percent direct and indirect noncontrolling
interest. These companies each own an ethanol production facility.

• Other equity method investees.

We believe that transactions with related parties were conducted on terms comparable to those with unaffiliated
parties.

Sales to related parties, which are included in sales and other operating revenues (including consumer excise
taxes) on the consolidated statements of income, were $6 million, $7 million and $8 million in 2015, 2014 and
2013, respectively.

Other income from related parties, which is included in other income on the consolidated statements of income,
were $4 million, $1 million and $1 million in 2015, 2014 and 2013, respectively. Other income from related
parties consists primarily of operating revenue.

123

Purchases from related parties were as follows:

(In millions)

Centennial

Crowley Ocean Partners

Explorer

Illinois Extension Pipeline

LOCAP

LOOP

TAAE

TACE

TAME

Other equity method investees

Total

2015

2014

2013

121

141

308

505

130

131

357

Related party purchases from Centennial consist primarily of
refinery feedstocks and refined product
transportation costs. Related party purchases from Crowley Ocean Partners consist primarily of leasing
equipment. Related party purchases from Explorer consist primarily of refined product transportation costs.
Related party purchases from Illinois Extension Pipeline, LOCAP, LOOP and other equity method investees
consist primarily of crude oil transportation costs. Related party purchases from TAAE, TACE and TAME
consist of ethanol purchases.

Receivables from related parties, which are included in receivables, less allowance for doubtful accounts on the
consolidated balance sheets, were as follows:

(In millions)

Centennial

Explorer

MarkWest EMG Jefferson

MarkWest Utica EMG

Ohio Condensate

Ohio Gathering

TAME

Other equity method investees

Total

December 31,

2015

2014

Long-term receivable from Ohio Condensate, which is included in other noncurrent assets on the consolidated
balance sheet, was $1 million at December 31, 2015.

124

Payables to related parties, which are included in accounts payable on the consolidated balance sheets, were as
follows:

(In millions)

Explorer

Illinois Extension Pipeline

LOCAP

LOOP

MarkWest Utica EMG

Ohio Condensate

TAAE

TACE

TAME

Other equity method investees

Total

December 31,

2015

2014

Income per Common Share

We compute basic earnings per share by dividing net income attributable to MPC by the weighted average
number of shares of common stock outstanding. The average number of shares of common stock and per share
amounts have been retroactively restated to reflect the two-for-one stock split completed in June 2015. Diluted
income per share assumes exercise of certain stock based compensation awards, provided the effect is not anti-
dilutive.

125

MPC grants certain incentive compensation awards to employees and non-employee directors that are considered
to be participating securities. Due to the presence of participating securities, we have calculated our earnings per
share using the two-class method.

(In millions, except per share data)

2015

2014

2013

Basic earnings per share:

Allocation of earnings:

Net income attributable to MPC

Income allocated to participating securities

2,852

2,524

2,112

Income available to common stockholders – basic

2,848

2,520

2,108

Weighted average common shares outstanding

Basic earnings per share

Diluted earnings per share:

Allocation of earnings:

538

570

630

5.29

4.42

3.34

Net income attributable to MPC

Income allocated to participating securities

2,852

2,524

2,112

Income available to common stockholders – diluted

2,848

2,520

2,108

Weighted average common shares outstanding

Effect of dilutive securities

Weighted average common shares, including dilutive effect

538

542

570

574

630

634

Diluted earnings per share

5.26

4.39

3.32

The following table summarizes the shares that were anti-dilutive, and therefore, were excluded from the diluted
share calculation.

(In millions)

2015

2014

2013

Shares issued under stock-based compensation plans

9. Equity

On April 29, 2015, our board of directors approved a two-for-one stock split in the form of a stock dividend,
which was distributed on June 10, 2015 to shareholders of record at the close of business on May 20, 2015. The
total number of authorized shares of common stock and common stock par value per share remain unchanged.
All historical share and per share data included in this report have been retroactively restated on a post-split
basis.

On July 29, 2015, our board of directors approved an additional $2.0 billion share repurchase authorization
expiring in July 2017. Since January 1, 2012, our board of directors had approved $10.0 billion in total share
repurchase authorizations and we have repurchased a total of $7.24 billion of our common stock under these
authorizations,
leaving $2.76 billion available for repurchases as of December 31, 2015. Under these
authorizations, we have acquired 198 million shares at an average cost per share of $36.65.

126

Total share repurchases were as follows for the respective periods:

(In millions, except per share data)

Number of shares repurchased(a)

Cash paid for shares repurchased

Effective average cost per delivered share

2015

2014

2013

965

50.31

2,131

44.31

2,793

38.07

(a)

Shares repurchased in 2013 includes 2 million shares received under the November 2012 accelerated share repurchase program, which
were paid for in 2012.

At December 31, 2015, we had agreements to acquire 172,200 common shares for $9 million, which were settled
in early January 2016.

10. Segment Information

We have three reportable segments: Refining & Marketing; Speedway; and Midstream. Each of these segments is
organized and managed based upon the nature of the products and services it offers.

• Refining & Marketing – refines crude oil and other feedstocks at our refineries in the Gulf Coast and
Midwest regions of the United States, purchases ethanol and refined products for resale and distributes
refined products through various means, including barges, terminals and trucks that we own or operate.
We sell refined products to wholesale marketing customers domestically and internationally, to buyers
on the spot market,
to our Speedway segment and to independent entrepreneurs who operate
Marathon® retail outlets.

•

Speedway – sells transportation fuels and convenience merchandise in retail markets in the Midwest,
East Coast and Southeast regions of the United States.

On December 4, 2015, MPLX completed a merger with MarkWest and its results are included in the Midstream
segment. On September 30, 2014, we acquired Hess’ Retail Operations and Related Assets, substantially all of
which is part of the Speedway segment. On February 1, 2013, we acquired the Galveston Bay Refinery and
Related Assets, which is part of the Refining & Marketing and Midstream segments. Segment information for
periods prior to each acquisition or the MarkWest Merger does not include amounts for these operations. See
Note 5.

127

income represents income from operations attributable to the reportable segments. Corporate
Segment
administrative expenses and costs related to certain non-operating assets are not allocated to the reportable
segments. In addition, certain items that affect comparability (as determined by the chief operating decision
maker) are not allocated to the reportable segments.

(In millions)

Year Ended December 31, 2015

Revenues:

Customer

Intersegment(a)

Segment revenues

Segment income from operations(b)(c)

Income from equity method investments

Depreciation and amortization(d)

Capital expenditures and investments(e)(f)

(In millions)

Year Ended December 31, 2014

Revenues:

Customer

Intersegment(a)

Segment revenues

Segment income from operations(b)

Income from equity method investments

Depreciation and amortization(d)

Capital expenditures and investments(e)(g)

Refining &
Marketing

Speedway

Midstream

Total

52,174

19,690

12,018

64,192

4,186

1,079

1,143

Refining &
Marketing

19,693

673

254

501

187

564

751

289

117

14,447

72,051

12,585

84,636

5,148

1,450

16,091

Speedway

Midstream

Total

80,822

16,927

10,912

91,734

3,609

1,045

1,104

16,932

544

152

2,981

527

597

280

543

97,819

11,444

109,263

4,433

153

1,274

4,628

128

(In millions)

Year Ended December 31, 2013

Revenues:

Customer

Intersegment(a)

Segment revenues

Segment income from operations(b)

Income from equity method investments

Depreciation and amortization(d)

Capital expenditures and investments(e)(h)

Refining &
Marketing

Speedway

Midstream

Total

85,616

14,471

9,294

94,910

3,206

1,011

2,094

14,475

375

—

112

296

458

537

210

234

100,166

9,756

109,922

3,791

1,197

2,624

(a) Management believes intersegment transactions were conducted under terms comparable to those with unaffiliated parties.

(b)

(c)

Included in the Midstream segment for 2015, 2014 and 2013 are $20 million, $19 million and $20 million, respectively, of corporate
overhead expenses attributable to MPLX. Corporate overhead expenses are not currently allocated to other segments. Also included in
the Midstream segment for 2015 are $36 million of transaction costs related to the MarkWest Merger.

The Refining & Marketing and Speedway segments include inventory lower of cost or market charge of $345 million and $25 million,
respectively.

(d) Differences between segment totals and MPC totals represent amounts related to unallocated items and are included in “Items not

allocated to segments” in the reconciliation below.

(e) Capital expenditures include changes in capital accruals, acquisitions and investments in affiliates.

(f)

(g)

(h)

The Midstream segment includes $13.85 billion for the MarkWest Merger. See Note 5.

The Speedway and Refining & Marketing segments include $2.66 billion and $52 million, respectively, for the acquisition of Hess’
Retail Operations and Related Assets. See Note 5.

The Refining & Marketing and Midstream segments include $1.29 billion and $70 million, respectively, for the acquisition of the
Galveston Bay Refinery and Related Assets. See Note 5.

The following reconciles segment income from operations to income before income taxes as reported in the
consolidated statements of income:

(In millions)

Segment income from operations

Items not allocated to segments:

Corporate and other unallocated items(a)(b)

Pension settlement expenses(c)

Impairment(d)

Net interest and other financial income (costs)

Income before income taxes

2015

2014

2013

5,148

4,433

3,791

(308)

(4)

(144)

(318)

(286)

(96)

(216)

(271)

(95)

(179)

4,374

3,835

3,246

(a) Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses and costs related to certain non-

operating assets.

(b) Corporate overhead expenses attributable to MPLX are included in the Midstream segment. Corporate overhead expenses are not

allocated to the Refining & Marketing and Speedway segments.

(c)

See Note 22.

(d) Related to the cancellation of the ROUX project at our Garyville, LA refinery. See Note 15.

129

The following reconciles segment capital expenditures and investments to total capital expenditures:

(In millions)

Segment capital expenditures and investments

Less: Investments in equity method investees(a)

Plus: Items not allocated to segments:

Capital expenditures not allocated to segments

Capitalized interest

Total capital expenditures(b)

2015

2014

2013

16,091

4,628

2,624

2,788

155

413

124

137

13,495

4,325

2,665

(a)

2015 includes $2.46 billion for the MarkWest Merger. See Note 5.

(b) Capital expenditures include changes in capital accruals. See Note 20 for a reconciliation of total capital expenditures to additions to

property, plant and equipment as reported in the consolidated statements of cash flows.

The following reconciles total segment customer revenues to sales and other operating revenues (including
consumer excise taxes) as reported in the consolidated statements of income:

(In millions)

Customer revenues

Corporate and other unallocated items

2015

2014

2013

72,051

97,819

100,166

—

(2)

(6)

Sales and other operating revenues (including consumer excise taxes)

72,051

97,817

100,160

Revenues by product line were:

(In millions)

Refined products

Merchandise

Crude oil and refinery feedstocks

Transportation and other

2015

2014

2013

63,708

90,702

93,520

5,188

2,718

437

3,817

2,917

381

3,308

2,988

344

Sales and other operating revenues (including consumer excise taxes)

72,051

97,817

100,160

No single customer accounted for more than 10 percent of annual revenues for the years ended December 31,
2015 and 2014. Revenue from BP p.l.c. included in the Refining & Marketing segment represented 10 percent of
our total annual revenues for the year ended December 31, 2013.

We do not have significant operations in foreign countries. Therefore, revenues in foreign countries and long-
lived assets located in foreign countries, including property, plant and equipment and investments, are not
material to our operations.

Total assets by reportable segment were:

(In millions)

Refining & Marketing

Speedway

Midstream

Corporate and Other

Total consolidated assets

130

December 31,

2015

2014

17,780

19,751

5,349

17,061

2,925

5,296

2,407

2,971

43,115

30,425

11. Other Items

Net interest and other financial income (costs) was:

(In millions)

Interest income

Interest expense

Interest capitalized

Loss on extinguishment of debt

Other financial costs(a)

2015

2014

2013

(325)

(5)

(31)

(229)

(21)

(195)

(21)

Net interest and other financial income (costs)

(318)

(216)

(179)

(a)

2015 includes $6 million of transaction costs related to the MarkWest Merger.

12.

Income Taxes

Income tax provisions (benefits) were:

(In millions)

Current

Deferred

Total

Current

Deferred

Total

Current Deferred

Total

2015

2014

2013

Federal

$ 1,210

$ 134

$ 1,344

$ 1,382

$ (199)

$ 1,183

152

(9)

161

135

(37)

(6)

(1)

954

131

$ 20

(5)

974

139

$ 1,372

$ 134

$ 1,506

$ 1,522

$ (242)

$ 1,280

$ 1,090

$ 23

$ 1,113

State and local

Foreign

Total

A reconciliation of the federal statutory income tax rate (35 percent) applied to income before income taxes to
the provision for income taxes follows:

Statutory rate applied to income before income taxes

State and local income taxes, net of federal income tax effects

Domestic manufacturing deduction

Other

Provision for income taxes

2015

2014

2013

35 %

(2)

(1)

(2)

34 %

33 %

34 %

131

Deferred tax assets and liabilities resulted from the following:

(In millions)

Deferred tax assets:

Employee benefits

Environmental

Investments in subsidiaries and affiliates

Net operating loss carryforwards

Other

Total deferred tax assets

Deferred tax liabilities:

Property, plant and equipment

Inventories

Investments in subsidiaries and affiliates(a)

Other

Total deferred tax liabilities

Net deferred tax liabilities

December 31,

2015

2014

631

616

821

764

2,512

2,411

579

909

614

101

4,089

3,126

3,268

2,362

(a)

2015 includes $443 million acquired in the MarkWest Merger. See Note 5 for total net deferred income taxes acquired. 2015 also
includes $404 million tax effect related to MPC’s $1.5 billion share of the MPLX equity issued in connection with the MarkWest
Merger. See Consolidated Statements of Equity.

Net deferred tax liabilities were classified in the consolidated balance sheets as follows:

(In millions)

Assets:

Other noncurrent assets

Liabilities:

Accrued taxes(a)

Deferred income taxes

Net deferred tax liabilities

December 31,

2015

2014

3,285

3,268

355

2,014

2,362

(a) We adopted the updated FASB balance classification of deferred taxes standard and applied the changes prospectively. We reclassified

current deferred taxes from current accrued taxes to long-term deferred income taxes. See Note 3.

Tax carryforwards – At December 31, 2015, federal operating loss carryforwards were $66 million, including
$58 million from a subsidiary acquired with the MarkWest Merger which is not included in MPC’s consolidated
federal income tax return, which expire in 2022 through 2035. State and local operating loss carryforwards of $7
million, including $4 million acquired with the MarkWest Merger, expire in 2016 through 2035.

Valuation allowances – As of December 31, 2015 and 2014, $4 million of valuation allowances were recognized
primarily due to the expected realizability of foreign tax credits and based on estimates of future financial income
and expected realizability of state and local tax operating losses.

132

MPC is continuously undergoing examination of its U.S. federal income tax returns by the Internal Revenue
Service. Such audits have been completed through the 2009 tax year. We believe adequate provision has been
made for federal income taxes and interest which may become payable for years not yet settled. Further, we are
routinely involved in U.S. state income tax audits. We believe all other audits will be resolved with the amounts
paid and/or provided for these liabilities. As of December 31, 2015, our income tax returns remain subject to
examination in the following major tax jurisdictions for the tax years indicated:

United States Federal

States

2010 - 2014

2004 - 2014

As a result of the Spinoff and pursuant to the tax sharing agreement by Marathon Oil and MPC, the unrecognized
tax benefits related to MPC operations for which Marathon Oil was the taxpayer remain the responsibility of
Marathon Oil and MPC has indemnified Marathon Oil. During 2013, we settled with Marathon Oil our U.S.
federal and related state return liabilities for the 2008-2009 tax years, resulting in a reduction in unrecognized tax
benefits of $21 million, which are also reflected in the table below as settlements.

During 2013, we settled with Marathon Oil for the 2011 period prior to the Spinoff based on filed tax returns and
in accordance with the tax sharing agreement, resulting in a $39 million increase to additional paid-in capital.

The following table summarizes the activity in unrecognized tax benefits:

(In millions)

January 1 balance

Additions for tax positions of prior years

Reductions for tax positions of prior years

Settlements

Statute of limitations

December 31 balance

2015

2014

2013

(10)

(25)

(30)

(2)

If the unrecognized tax benefits as of December 31, 2015 were recognized, $5 million would affect our effective
income tax rate. There were $4 million of uncertain tax positions as of December 31, 2015 for which it is
reasonably possible that the amount of unrecognized tax benefits would significantly decrease during the next
twelve months.

Interest and penalties related to income taxes are recorded as part of the provision for income taxes. Such interest
and penalties were net expenses of $3 million, less than $1 million and $11 million in 2015, 2014 and 2013,
respectively. As of December 31, 2015 and 2014, $18 million and $14 million of interest and penalties were
accrued related to income taxes.

13.

Inventories

(In millions)

Crude oil and refinery feedstocks

Refined products

Materials and supplies

Merchandise

Lower of cost or market reserve

Total

December 31,

2015

2014

2,180

2,804

438

173

(370)

2,219

2,955

302

166

5,225

5,642

133

The LIFO method accounted for 91 percent and 94 percent of total inventory value at December 31, 2015 and
2014, respectively. Costs of crude oil, refinery feedstocks and refined products are aggregated on a consolidated
basis for purposes of assessing if the LIFO cost basis of these inventories may have to be written down to market
values. At December 31, 2015, market values for these inventories were lower than their LIFO cost basis and, as
a result, we recorded an inventory valuation charge of $370 million to cost of revenues to value these inventories
at the lower of cost or market. Based on movements of refined product prices, future inventory valuation
adjustments could have a negative or positive effect to earnings. Such losses are subject to reversal in subsequent
periods if prices recover. In 2016, inventory market values have continued to decline and if they do not recover to
December 31, 2015 levels by March 31, 2016, an additional inventory valuation charge would be required in first
quarter 2016. At December 31, 2014, current acquisition costs of inventories were estimated to exceed the LIFO
inventory value by $684 million.

During 2015, we recorded LIFO liquidations caused by permanently decreased levels in crude oil and refined
products inventory volumes. Cost of revenues increased and income from operations decreased by $78 million
for the year ended December 31, 2015. There were no liquidations of LIFO inventories in 2014 and 2013.

14. Equity Method Investments

(In millions)

Centennial

Centrahoma Processing LLC

Crowley Ocean Partners

Explorer

Illinois Extension Pipeline

LOCAP

LOOP

MarkWest Utica EMG

North Dakota Pipeline(a)

Ohio Condensate

TAAE

TACE

TAEI

TAME(b)

Other MPLX investments

Other

Total

Ownership
as of
December 31,
2015

Carrying value at
December 31,

2015

2014

50%

40%

50%

25%

35%

59%

51%

60%

38%

60%

43%

60%

34%

50%

111

267

243

2,160

287

101

120

230

216

3,622

865

(a) We own a 38 percent interest in the Class B units of this entity. Our Class B units will be converted to an approximate 27 percent
ownership interest in the Class A units of this entity upon completion of the Sandpiper pipeline construction project, which is expected to
be in early 2019.

(b)

Excludes TAEI’s investment in TAME.

134

Summarized financial information for equity method investees is as follows:

(In millions)

Income statement data:

Revenues and other income

Income from operations

Net income

Balance sheet data – December 31:

Current assets

Noncurrent assets

Current liabilities

Noncurrent liabilities

2015

2014

2013

1,390

1,430

1,067

332

239

379

316

906

990

6,418

468

1,130

2,166

280

957

As of December 31, 2015, the carrying value of our equity method investments was $1.07 billion 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 $426 million of excess related to
goodwill.

Centennial experienced a significant reduction in shipment volumes in the second half of 2011 that has continued
through 2015. At December 31, 2015, Centennial was not shipping product. As a result, we continued to evaluate
the carrying value of our equity investment in Centennial. We concluded that no impairment was required given
our assessment of its fair value based on market participant assumptions for various potential uses and future
cash flows of Centennial’s assets. If market conditions were to change and the owners of Centennial are unable to
find an alternative use for the assets, there could be a future impairment of our Centennial interest. As of
December 31, 2015, our equity investment in Centennial was $37 million and we had a $34 million guarantee
associated with 50 percent of Centennial’s outstanding debt. See Note 25 for additional information on the debt
guarantee.

Dividends and partnership distributions received from equity method investees (excluding distributions that
represented a return of capital previously contributed) were $113 million, $170 million and $18 million in 2015,
2014 and 2013.

15. Property, Plant and Equipment

(In millions)

Refining & Marketing

Speedway

Midstream

Corporate and Other

Total

Less accumulated depreciation

Property, plant and equipment, net

Estimated
Useful Lives

December 31,

2015

2014

2 - 30 years

18,925

18,001

4 - 25 years

10 - 42 years

4 - 40 years

5,067

10,850

762

35,604

10,440

4,639

2,044

618

25,302

9,041

25,164

16,261

Property, plant and equipment includes gross assets acquired under capital leases of $511 million and $510
million at December 31, 2015 and 2014, respectively, with related amounts in accumulated depreciation of $176
million and $144 million at December 31, 2015 and 2014. Property, plant and equipment includes construction in
progress of $2,263 million and $1,043 million at December 31, 2015 and 2014, respectively, which primarily
relates to capital projects at our refineries.

135

In the third quarter of 2015, we decided to cancel the ROUX project at our Garyville, Louisiana refinery due to
the implications of current market conditions. The project was intended to increase margins by upgrading
residual fuel to ultra-low sulfur diesel and gas oil. As a result, we recorded a $144 million impairment charge to
write off the costs incurred through September 30, 2015 on the project. This impairment charge is included in
depreciation and amortization on the consolidated statements of income.

16. Goodwill and Intangibles

Goodwill

Goodwill is tested for impairment on an annual basis and when events or changes in circumstances indicate the
fair value of a reporting unit with goodwill has been reduced below the carrying value of the net assets of the
reporting unit. We performed our annual impairment tests for 2015 and 2014, and no impairment was required.

The significant assumptions which were used to develop the estimates of the fair values recorded in acquisition
accounting and the resulting goodwill assigned to the reporting units included discount rates, growth rates, and
customer attrition rates. If MPLX experiences negative events related to these assumptions or if the market price
of MPLX common units continues to trade at a low level in 2016, MPLX may need to assess whether this is a
change in circumstances that indicates it is more likely than not that the fair value of the reporting units to which
MPLX assigned goodwill in connection with the MarkWest Merger is less than their carrying value and, if so,
evaluate goodwill for impairment.

The changes in the carrying amount of goodwill for 2015 and 2014 were as follows:

(In millions)

Balance at January 1, 2014

Acquisitions(a)
Disposition

Balance at December 31, 2014

Acquisitions(a)
Disposition

Balance at December 31, 2015

(a)

See Note 5 for information on the acquisitions.

Refining &
Marketing

$ 551
-
(1)
$ 550
-
-
$ 550

Speedway

Midstream

Total

225
629
-
854
-
(1)
853

162
-
-
162
2,454
-
2,616

938
629
(1)
1,566
2,454
(1)
4,019

136

Intangible Assets

Our intangible assets as of December 31, 2015 and 2014 are as follows:

(In millions)

Balance at December 31, 2015

Refining &
Marketing

Speedway

Midstream

Total

Customer contracts and relationships

Royalty agreements

Favorable lease contract terms

Other(a)

Gross

Accumulated amortization

Net

Balance at December 31, 2014

122

242

(104)

138

Customer contracts and relationships

105

Royalty agreements

Favorable lease contract terms

Other(a)

Gross

Accumulated amortization

Net

121

257

(106)

151

468

$ 560

122

103

146

(31)

115

468

856

(2)

(137)

466

719

146

(10)

136

$ 106

121

104

403

(116)

287

(a)

The Refining & Marketing and Speedway segments include unamortized intangible assets of $3 million and $46 million, respectively,
which are primarily trademarks.

Amortization expense for 2015 and 2014 was $29 million and $18 million, respectively. Estimated future
amortization expense related to the intangible assets at December 31, 2015 is as follows:

(In millions)

2016

2017

2018

2019

2020

137

17. Fair Value Measurements

Fair Values – Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of
December 31, 2015 and 2014 by fair value hierarchy level. We have elected to offset the fair value amounts
recognized for multiple derivative contracts executed with the same counterparty, including any related cash
collateral as shown below; however, fair value amounts by hierarchy level are presented on a gross basis in the
following tables.

December 31, 2015

(In millions)

Fair Value Hierarchy
Level 1 Level 2 Level 3

Netting and
Collateral(a)

Net Carrying
Value on Balance
Sheet(b)

Collateral
Pledged Not
Offset

Commodity derivative instruments, assets

$ 104

Other assets

Total assets at fair value

Commodity derivative instruments,

liabilities

Embedded derivatives in commodity

contracts(c)

Contingent consideration, liability(d)

$ 106

Total liabilities at fair value

317

(62)

N/A

(62)

(39)

N/A

349

(39)

317

349

(In millions)

Commodity derivative instruments, assets

Other assets

Total assets at fair value

Commodity derivative instruments,

liabilities

Contingent consideration, liability(d)

Total liabilities at fair value

December 31, 2014

Fair Value Hierarchy

Level 1

Level 2 Level 3

Netting and
Collateral(a)

Net Carrying
Value on Balance
Sheet(b)

Collateral
Pledged Not
Offset

317

319

180

$ (258)

N/A

$ (258)

$ (180)

478

N/A

478

$ (180)

478

(a) Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of December 31, 2015, cash
collateral of $23 million was netted with mark-to-market derivative assets. As of December 31, 2014, cash collateral of $78 million was
netted with mark-to-market derivative assets.

(b) We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet.

(c)

(d)

Includes $5 million at December 31, 2015 classified as current.

Includes $196 million and $174 million classified as current as of December 31, 2015 and 2014, respectively.

Commodity derivatives in Level 1 are exchange-traded contracts for crude oil and refined products measured at
fair value with a market approach using the close-of-day settlement prices for the market. Commodity derivatives
are covered under master netting agreements with an unconditional right to offset. Collateral deposits in futures
commission merchant accounts covered by master netting agreements related to Level 1 commodity derivatives
are classified as Level 1 in the fair value hierarchy.

138

Commodity derivatives in Level 2 include crude oil and natural gas swap contracts and are measured at fair value
with a market approach. The valuations are based on the appropriate commodity prices and contain no significant
unobservable inputs. LIBO Rates are an observable input for the measurement of these derivative contracts. The
measurements for commodity contracts contain observable inputs in the form of forward prices based on WTI
crude oil prices; and Columbia Appalachia, Henry Hub, PEPL and Houston Ship Channel natural gas prices.
MPLX settled natural gas swaps during the year ended December 31, 2015; however, no such instruments were
outstanding as of December 31, 2015.

Level 3 instruments include OTC NGL contracts and embedded derivatives in commodity contracts. The fair
value calculation for these Level 3 instruments used significant unobservable inputs including: (1) NGL prices
interpolated and extrapolated due to inactive markets ranging from approximately $0.15 to $3.40 per gallon,
(2) electricity prices ranging from approximately $23 to $45 per megawatt hour and (3) the probability of
renewal of 50 percent. For these 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. The embedded
derivative liability relates to a natural gas purchase agreement embedded in a keep-whole processing agreement.
Increases or decreases in forward NGL prices result in an increase or decrease in the fair value of the embedded
derivative. An increase in the probability of renewal would result in an increase in the fair value of the related
embedded derivative liability.

The contingent consideration represents the fair value as of December 31, 2015 and 2014 of the remaining
amount we expect to pay to BP related to the earnout provision for the Galveston Bay Refinery and Related
Assets acquisition. See Note 5. The fair value of the remaining contingent consideration was estimated using an
income approach and is therefore a Level 3 liability. The amount of cash to be paid under the arrangement is
based on both a market-based crack spread and refinery throughput volumes for the months during which the
earnout applies, as well as established thresholds that cap the annual and total payment. The earnout payment
cannot exceed $200 million per year for the first three years of the arrangement or $250 million per year for the
last three years of the arrangement, with the total cumulative payment capped at $700 million over the six-year
period commencing in 2014. Any excess or shortfall from the annual cap for a current year’s earnout calculation
will not affect subsequent years’ calculations. The fair value calculation used significant unobservable inputs
including: (1) an estimate of monthly refinery throughput volumes; (2) a range of internal and external monthly
crack spread forecasts from approximately $7 to $16 per barrel; and (3) a range of risk-adjusted discount rates
from five percent to 10 percent. An increase or decrease in crack spread forecasts or refinery throughput volume
expectations may result in a corresponding increase or decrease in the fair value. Increases to the fair value as a
result of increasing forecasts for both of these unobservable inputs, however, are limited as the earnout payment
is subject to annual caps. An increase or decrease in the discount rate may result in a decrease or increase to the
fair value, respectively. The fair value of the contingent consideration is reassessed each quarter, with changes in
fair value recorded in cost of revenues.

139

The following is a reconciliation of the net beginning and ending balances recorded for net assets and liabilities
classified as Level 3 in the fair value hierarchy.

(In millions)

Beginning balance

Contingent consideration agreement

Contingent consideration payment(a)

Net derivative positions assumed - MarkWest Merger

Unrealized and realized (gains) losses included in net income

Settlements of derivative instruments

Ending balance

2015

2014

2013

478 $

625

600

(189)

(180)

342 $

478

$ 625

(a) On the consolidated statements of cash flows for 2015 and 2014, $175 million and $172 million, respectively, of the contingent earnout

payment to BP is included as a financing activity with the remainder included as an operating activity.

We held Level 3 derivative instruments in 2015 in conjunction with the MarkWest Merger, but we did not hold
any Level 3 derivative instruments in 2014 and 2013. See Note 18 for the income statement impacts of our
derivative instruments. There was an unrealized gain of $7 million in 2015 related to derivatives. There was an
unrealized loss of $28 million, $33 million, and $25 million in 2015, 2014 and 2013, respectively, related to the
contingent consideration.

Fair Values – Nonrecurring

The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis
in periods subsequent to their initial recognition.

Year Ended December 31,

2015

2014

2013

(In millions)

Fair Value

Impairment Fair Value

Impairment

Property, plant and equipment, net

Other noncurrent assets

144

In the third quarter of 2015, we decided to cancel the ROUX project at our Garyville, LA refinery. The work
completed on the project through September 30, 2015 had no alternate use or net salvage value; therefore, we
fully impaired the $144 million of cost capitalized for the project through that date. The fair value of our
investment in the project was determined using an income approach and is classified as Level 3.

Based on the financial and operational status of a company in which we have an interest, we fully impaired our
$11 million investment in that company in 2014. Our investment in this company was accounted for using the
cost method and was included in our Refining & Marketing segment. The impairment charge is included in other
income on the consolidated statements of income. The fair value of our investment in this cost company was
measured using an income approach. This measurement is classified as Level 3.

Due to changing market conditions, we assessed one of our light products terminals for impairment. The terminal
is operated by our Refining & Marketing segment. We recorded an impairment charge of $8 million for this
terminal in 2013. The impairment charge is included in depreciation and amortization on the consolidated
statements of income. The fair value of the terminal was measured using a market approach based on comparable
area property values which are Level 3 inputs.

140

Fair Values – Reported

The following table summarizes financial instruments on the basis of their nature, characteristics and risk at
December 31, 2015 and 2014, excluding the derivative financial instruments and contingent consideration
reported above.

(In millions)

Financial assets:

Investments

Other

Total financial assets

Financial liabilities:

Long-term debt(a)

Deferred credits and other liabilities

Total financial liabilities

December 31,

2015

2014

Fair Value

Carrying
Value

Fair Value

Carrying
Value

11,366

11,628

6,571

6,265

136

135

11,502

11,763

6,588

6,282

(a)

Excludes capital leases and debt issuance costs, however, includes amount classified as short-term debt.

Our current assets and liabilities include financial instruments, the most significant of which are trade accounts
receivable and payables. We believe the carrying values of our current assets and liabilities approximate fair
value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of
the instruments, (2) our investment-grade credit rating and (3) our historical incurrence of and expected future
insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

Fair values of our financial assets included in investments and other financial assets and of our financial
liabilities included in deferred credits and other liabilities are measured primarily using an income approach and
most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are
discounted using a rate deemed appropriate to obtain the fair value. Other financial assets primarily consist of
environmental remediation receivables. Deferred credits and other liabilities primarily consist of a liability
related to SMR, a payable for merger cash consideration due to MPLX’s Class B unitholders to be paid upon
conversion, insurance liabilities and environmental remediation liabilities.

Fair value of fixed-rate long-term debt is measured using a market approach, based upon the average of quotes
from major financial
institutions and a third-party service for our debt. Because these quotes cannot be
independently verified to the market, they are considered Level 3 inputs. Fair value of variable-rate long-term
debt approximates the carrying value.

141

18. Derivatives

For further information regarding the fair value measurement of derivative instruments, including any effect of
master netting agreements or collateral, see Note 17. See Note 2 for a discussion of the types of derivatives we
use and the reasons for them. We do not designate any of our commodity derivative instruments as hedges for
accounting purposes. Our interest rate derivative instruments that were terminated in 2012 had been designated
as fair value accounting hedges.

The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where
they appear on the consolidated balance sheets as of December 31, 2015 and 2014:

(In millions)

Balance Sheet Location

Commodity derivatives

Other current assets

Other current liabilities

Deferred credits and other liabilities(a)

(In millions)

Balance Sheet Location

Commodity derivatives

Other current assets

(a)

Includes embedded derivatives.

December 31, 2015

Asset

Liability

113

December 31, 2014

Asset

Liability

317

180

Derivatives not Designated as Accounting Hedges

Derivatives that are not designated as accounting hedges may include commodity derivatives used to hedge price
risk on (1) inventories, (2) fixed price sales of refined products, (3) the acquisition of foreign-sourced crude oil,
(4) the acquisition of ethanol for blending with refined products, (5) sale of NGLs, (6) the purchase of natural gas
and (7) purchase of electricity.

The table below summarizes open commodity derivative contracts for crude oil and refined products as of
December 31, 2015.

Crude oil(a)

Exchange-traded

OTC

(a)

100 percent of the exchange-traded contracts expire in the first quarter of 2016.

Position

Total Barrels
(In thousands)

Long

Short

14,517

(22,989)

(110)

142

Refined Products(a)

Exchange-traded

OTC

Position

Total Gallons
(In thousands)

Long

Short

221,256

(203,700)

(43,838)

(a)

100 percent of the exchange-traded contracts expire in the first quarter of 2016.

The following table summarizes the effect of all commodity derivative instruments in our consolidated
statements of income:

(In millions)

Income Statement Location

Sales and other operating revenues

Cost of revenues

Total

Gain (Loss)

2015

2014

2013

294

313

456

493

(180)

(168)

143

19. Debt

Our outstanding borrowings at December 31, 2015 and 2014 consisted of the following:

(In millions)

Marathon Petroleum Corporation:

Senior notes, 3.500%, due March 2016

Bank revolving credit facility due 2017

Term loan agreement due 2019

Senior notes, 2.700% due December 2018

Senior notes, 3.400% due December 2020

Senior notes, 5.125% due March 2021

Senior notes, 3.625%, due September 2024

Senior notes, 6.500%, due March 2041

Senior notes, 4.750%, due September 2044

Senior notes, 5.850% due December 2045

Senior notes, 5.000%, due September 2054

MPLX LP:

MPLX term loan facility due 2019

MPLX bank revolving credit facility due 2020

MPLX senior notes, 5.500%, due February 2023

MPLX senior notes, 4.500%, due July 2023

MPLX senior notes, 4.875%, due December 2024

MPLX senior notes, 4.000%, due February 2025

MPLX senior notes, 4.875%, due June 2025

MarkWest senior notes, 4.500% - 5.500%

Capital lease obligations due 2016-2028

Trade receivables securitization facility due December 2016

Total

Unamortized debt issuance costs(a)

Unamortized discount(b)

Fair value adjustments(c)

Amounts due within one year

December 31,

2015

2014

700

600

650

1,000

750

1,250

800

250

400

250

877

710

989

1,149

500

1,189

348

12,475

(51)

(499)

(29)

750

700

1,000

750

1,250

800

400

250

385

372

6,657

(35)

(26)

(27)

Total long-term debt due after one year

11,896

6,575

(a) We adopted the updated FASB debt issuance cost standard as of June 30, 2015 and applied the changes retrospectively to the prior period

presented. We reclassified unamortized debt issuance costs from other noncurrent assets to long-term debt.

(b)

(c)

2015 includes $465 million discount related to the difference between the fair value and the principal amount of the assumed MarkWest
debt.

In 2012, we terminated our interest rate swap agreements with a notional amount of $500 million that had been entered into as fair value
accounting hedges on our 3.50 percent senior notes due in March 2016. The $20 million gain on the termination of our interest rate swap
agreements was amortized over the remaining life of the 3.50 percent senior notes. As a result of the December 2015 extinguishment of
our obligation for the 3.50 percent senior notes, the remaining unamortized gain was credited to net interest and other financial income
(costs).

144

The following table shows five years of scheduled debt payments.

(In millions)

2016

2017

2018

2019

2020

630

977

1,560

MPC Bank Revolving Credit Facility

We have a $2.5 billion unsecured bank revolving credit facility (“revolving credit facility”) in place with a
maturity date of September 14, 2017. Our revolving credit facility includes letter of credit issuing capacity of up
to $2.0 billion and swingline loan capacity of up to $100 million. We may increase our borrowing capacity under
our revolving credit facility by up to an additional $500 million, subject to certain conditions including the
consent of the lenders whose commitments would be increased. In addition, the maturity date may be extended
for up to two additional one-year periods subject to the approval of lenders holding greater than 50 percent of the
commitments then outstanding, provided that the commitments of any non-consenting lenders will terminate on
the then-effective maturity date.

Borrowings under our revolving credit facility bear interest, at our election, at either the Adjusted LIBO Rate (as
defined in our revolving credit facility) plus a margin or the Alternate Base Rate (as defined in our revolving
credit facility), plus a margin. We are charged various fees and expenses in connection with our revolving credit
facility, including administrative agent fees, commitment fees on the unused portion of our borrowing capacity
and fees related to issued and outstanding letters of credit. The applicable margin to the benchmark interest rates
and the margin to the benchmark commitment fees payable under our revolving credit facility fluctuate from
time-to-time based on our credit ratings.

Our revolving credit facility contains certain representations and warranties, affirmative and restrictive covenants
and events of default that we consider to be usual and customary for arrangements of this type, including a
financial covenant that requires us to maintain a ratio of Consolidated Net Debt to Total Capitalization (each as
defined in our revolving credit facility) of no greater than 0.65 to 1.00 as of the last day of each fiscal quarter.
Other covenants, among other things, restrict our ability to incur debt, create liens on our assets or enter into
transactions with affiliates. As of December 31, 2015, we were in compliance with the covenants contained in the
revolving credit facility.

There were no borrowings or letters of credit outstanding at December 31, 2015.

MPC Term Loan Agreement

On August 26, 2014, we entered into a $700 million five-year senior unsecured term loan credit agreement
(“term loan agreement”) with a syndicate of lenders to fund a portion of the purchase price for the acquisition of
Hess’ Retail Operations and Related Assets. The term loan was drawn in full on September 24, 2014. The term
loan agreement matures on September 24, 2019 and may be prepaid at any time without premium or penalty. We
pay certain customary fees under the term loan agreement, including an annual administrative fee to the
administrative agent.

Borrowings under the term loan agreement bear interest, at our election, at either the Adjusted LIBO Rate (as
defined in the term loan agreement) plus a margin or the Alternate Base Rate (as defined in the term loan
agreement) plus a margin. The applicable margin to the benchmark interest rates fluctuate from time-to-time
based on our credit ratings. The borrowings under this facility during 2015 were at an average interest rate of 1.3
percent.

145

The term loan agreement contains representation and warranties, affirmative and negative covenants and events
of default that are substantially similar to those contained in our revolving credit facility, which we consider to be
usual and customary for an agreement of this type. Among other things, our term loan agreement requires us to
maintain, as of the last day of each fiscal quarter, a ratio of Consolidated Net Debt to Total Capitalization (as
defined in the term loan agreement) of no greater than 0.65 to 1.00. As of December 31, 2015, we were in
compliance with the covenants contained in the term loan agreement.

MPC Senior Notes

On December 14, 2015, we completed a public offering of $1.5 billion in aggregate principal amount of
unsecured senior notes (“MPC senior notes”), consisting of $600 million aggregate principal amount of senior
notes due 2018, $650 million aggregate principal amount of senior notes due 2020 and $250 million aggregate
principal amount of senior notes due 2045. The net proceeds from the offering of the MPC senior notes were
$1.49 billion, after deducting underwriting discounts and offering expenses. We used a majority of the net
proceeds from this offering to fund the extinguishment of our obligation for the $750 million aggregate principal
amount of our 3.500% senior notes due 2016. During December 2015, $763 million was deposited with the
trustee and under the terms of the senior notes indenture we relieved our obligation related to these notes,
including principal and interest to the maturity date. As a result, we recorded a loss on extinguishment of debt of
$5 million. We intend to use the remaining net proceeds for general corporate purposes, which may include
investments in and advances to our affiliates and subsidiaries, including MPLX. Interest on each series of MPC
senior notes is payable semi-annually in arrears on June 15 and December 15, commencing on June 15, 2016.

The MPC senior notes are unsecured and unsubordinated obligations of ours and rank equally with all our other
existing and future unsecured and unsubordinated indebtedness.

MPLX Credit Agreement

MPLX is party to a credit agreement, dated as of November 20, 2014, and amended as of October 27, 2015
(“MPLX credit agreement”), providing for a $2 billion bank revolving credit facility with a maturity date of
December 4, 2020 and an outstanding $250 million term loan facility with a maturity date of November 20, 2019.

The MPLX credit agreement includes letter of credit issuing capacity of up to $250 million and swingline loan
capacity of up to $100 million. The revolving 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 the lenders
whose commitments would increase. In addition, the maturity date of the bank revolving credit facility may be
extended up from time-to-time during its term to a date that is one year after the then-effective maturity date,
subject to the approval of lenders holding the majority of the loans and commitments then outstanding, provided
that the commitments of any non-consenting lenders will be terminated on the then-effective maturity date.

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 2015 were at an average interest rate of 1.7
percent.

Borrowings under the MPLX credit agreement bear interest, at our election, at the Adjusted LIBO Rate or the
Alternate Base Rate (as defined in the MPLX credit agreement) plus a specified margin. MPLX is charged
various fees and expenses in connection with the agreement, including administrative agent fees, commitment
fees on the unused portion of the borrowing capacity and fees with respect to issued and outstanding letters of
credit. The applicable margins to the benchmark interest rates and the commitment fees payable under the MPLX
credit agreement fluctuate from time-to-time based on MPLX’s credit ratings.

146

includes certain representations and warranties, affirmative and restrictive
The MPLX credit agreement
covenants and events of default that we consider to be usual and customary for an agreement of this type,
including a financial covenant that requires MPLX to maintain a ratio of Consolidated Total Debt as of the end of
each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX credit agreement) for the prior four
fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain
acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital
projects undertaken during the relevant period. Other covenants, among other things, restrict MPLX and certain
of its subsidiaries from incurring debt, creating liens on its assets and entering into transactions with affiliates. As
of December 31, 2015, MPLX was in compliance with the covenants contained in the MPLX credit agreement.

In connection with the closing of the MarkWest Merger, MarkWest’s existing 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’s bank revolving credit facility and $93 million in cash. During 2015,
MPLX borrowed $992 million under the bank revolving credit facility, at an average interest rate of 1.6 percent,
per annum, and repaid $500 million of these borrowings. At December 31, 2015, MPLX had $877 million of
borrowings and $8 million of letters of credit outstanding under the bank revolving credit facility, resulting in
total unused loan availability of $1.1 billion.

MPLX and MarkWest Senior Notes

In connection with the MarkWest Merger, MPLX 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 and cash of $1 for each
$1,000 of principal amount exchanged in an exchange offer and consent solicitation undertaken by MPLX and
MarkWest.

After giving effect to the exchange offer and consent solicitation referred to above, as of December 31, 2015,
MarkWest had outstanding approximately $40 million aggregate principal amount of 5.500% senior notes due
February 15, 2023, approximately $11 million aggregate principal amount of 4.500% senior notes due July 15,
2023, approximately $1 million aggregate principal amount of 4.875% senior notes due December 1, 2024 and
approximately $11 million aggregate principal amount of 4.875% senior notes due June 1, 2025. Interest on each
series of the MarkWest senior notes is payable semi-annually in arrears on February 15th and August 15th of each
year with respect to the 5.500% 2023 senior notes, on January 15th and July 15th of each year with respect to the
4.500% 2023 senior notes and on June 1st and December 1st of each year with respect to the 4.875% 2024 senior
notes and the 4.875% 2025 senior notes.

The new MPLX notes are unsecured senior obligations of MPLX and rank equally in right of payment with all of
its other senior unsecured debt and are structurally subordinate to the secured and unsecured debt of MPLX’s
subsidiaries, including any debt of MarkWest that remains outstanding.

147

after deducting underwriting discounts, were used to repay the amounts outstanding under the MPLX bank
revolving credit facility, as well as for general partnership purposes. Interest is payable semi-annually in arrears
on February 15th and August 15th of each year.

Trade Receivables Securitization Facility

On December 18, 2013, we entered into a three-year, $1.3 billion trade receivables securitization facility (“trade
receivables facility”), with a group of financial institutions that act as committed purchasers, conduit purchasers,
letter of credit issuers and managing agents under the trade receivables facility. The trade receivables facility is
evidenced by a Receivables Purchase Agreement and a Second Amended and Restated Receivables Sale
Agreement. In October 2015, we reduced the maximum capacity under the trade receivables facility from $1.3
billion to $1.0 billion.

The trade receivables facility consists of one of our wholly-owned subsidiaries, Marathon Petroleum Company
LP (“MPC LP”), selling or contributing on an on-going basis all of its trade receivables (including trade
receivables acquired from Marathon Petroleum Trading Canada LLC, a wholly-owned subsidiary of MPC LP),
together with all related security and interests in the proceeds thereof, without recourse, to another wholly-
owned, bankruptcy-remote special purpose subsidiary, MPC Trade Receivables Company LLC (“TRC”), in
exchange for a combination of cash, equity or a subordinated note issued by TRC to MPC LP. TRC, in turn, has
the ability to finance its purchase of the receivables from MPC LP by selling undivided ownership interests in
qualifying trade receivables, together with all related security and interests in the proceeds thereof, without
recourse, to the purchasing group in exchange for cash proceeds. The trade receivables facility also provides for
the issuance of letters of credit up to $1.0 billion, provided that the aggregate credit exposure of the purchasing
group, including outstanding letters of credit, may not exceed the lessor of $1.0 billion or the balance of our
eligible trade receivables at any one time.

The Receivables Purchase Agreement and Second Amended and Restated Receivables Sale Agreement include
representations and covenants that we consider usual and customary for arrangements of this type. Trade
receivables are subject to customary criteria, limits and reserves before being deemed to qualify for sale by TRC
pursuant to the trade receivables facility. In addition, further purchases of qualified trade receivables under the
trade receivables facility are subject to termination, and TRC may be subject to default fees, upon the occurrence
of certain amortization events that are included in the Receivables Purchase Agreement, which we consider to be
usual and customary for arrangements of this type. At December 31, 2015, we were in compliance with the
covenants contained in the Receivables Purchase Agreement and Second Amended and Restated Receivables
Sale Agreement.

As of December 31, 2015, eligible trade receivables supported borrowings and letter of credit issuances of $668
million. There were no borrowings or letters of credit outstanding under the trade receivables facility at
December 31, 2015.

148

20. Supplemental Cash Flow Information

(In millions)

2015

2014

2013

Net cash provided by operating activities included:

Interest paid (net of amounts capitalized)

Net income taxes paid to taxing authorities

Non-cash investing and financing activities:

Capital lease obligations increase

Property, plant and equipment sold

Property, plant and equipment acquired

Acquisition:

Fair value of MPLX units issued(a)

Payable to MPLX Class B unitholders

Contingent consideration

Payable to seller

(a)

See Note 5.

$ 272

1,605

$ 166

1,362

7,326

$ 161

1,099

600

The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect
cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures:

(In millions)

2015

2014

2013

Additions to property, plant and equipment per consolidated statements of cash flows

1,998

$ 1,480

$ 1,206

Non-cash additions to property, plant and equipment

Asset retirement expenditures(a)

Increase in capital accruals

Total capital expenditures before acquisitions

Acquisitions(b)

Total capital expenditures

2,098

11,397

1,581

2,744

1,279

1,386

$ 13,495

$ 4,325

$ 2,665

(a)

(b)

Included in All other, net – Operating activities on the consolidated statements of cash flows.

149

21. Accumulated Other Comprehensive Loss

The following table shows the changes in accumulated other comprehensive loss by component. Amounts in
parentheses indicate debits.

(In millions)

Pension
Benefits

Other
Benefits

Gain on
Cash Flow
Hedge

Workers
Compensation

Total

Balance as of December 31, 2013

(161)

(50)

Other comprehensive income (loss) before

reclassifications

(119)

(53)

Amounts reclassified from accumulated

other comprehensive loss:

Amortization – prior service credit(a)

– actuarial loss(a)

– settlement loss(a)

Other(b)

Tax effect

Other comprehensive income (loss)

(46)

(38)

(56)

Balance as of December 31, 2014

(217)

(4)

(54)

(104)

(1)

(204)

(170)

(50)

(1)

(37)

(109)

(313)

(In millions)

Pension
Benefits

Other
Benefits

Gain on
Cash Flow
Hedge

Workers
Compensation

Total

Balance as of December 31, 2014

(217)

(104)

Other comprehensive income (loss) before

reclassifications

(44)

Amounts reclassified from accumulated

other comprehensive loss:

Amortization – prior service credit(a)

– actuarial loss(a)

– settlement loss(a)

Tax effect

Other comprehensive income (loss)

(46)

(3)

(38)

(4)

(1)

Balance as of December 31, 2015

(255)

(70)

(313)

(1)

(14)

(1)

(50)

(4)

(5)

(318)

(a)

(b)

These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 22.

This amount was reclassified out of accumulated other comprehensive loss and is included in selling, general and administrative
expenses on the consolidated statements of income.

150

22. Defined Benefit Pension and Other Postretirement Plans

We have noncontributory defined benefit pension plans covering substantially all employees. Benefits under
these plans have been based primarily on age, years of service and final average pensionable earnings. The years
of service component of this formula was frozen as of December 31, 2009. Benefits for service beginning
January 1, 2010 are based on a cash balance formula with an annual percentage of eligible pay credited based
upon age and years of service. Eligible Speedway employees accrue benefits under a defined contribution plan
for service years beginning January 1, 2010.

We also have other postretirement benefits covering most employees. Health care benefits are provided through
comprehensive hospital, surgical and major medical benefit provisions subject to various cost-sharing features.
Retiree life insurance benefits are provided to a closed group of retirees. Other postretirement benefits are not
funded in advance.

Obligations and funded status – The accumulated benefit obligation for all defined benefit pension plans was
$1,918 million and $2,009 million as of December 31, 2015 and 2014.

The following summarizes our defined benefit pension plans that have accumulated benefit obligations in excess
of plan assets.

(In millions)

Projected benefit obligations

Accumulated benefit obligations

Fair value of plan assets

December 31,

2015

2014

1,997

2,075

1,918

1,570

2,009

1,744

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The following summarizes the projected benefit obligations and funded status for our defined benefit pension and
other postretirement plans:

(In millions)

Change in benefit obligations:

Benefit obligations at January 1

Service cost

Interest cost

Actuarial (gain) loss

Benefits paid

Other(a)

Pension Benefits
2014
2015

Other Benefits

2015

2014

2,075

1,927

812

$ 687

101

(63)

(187)

257

(271)

(63)

(24)

800

(23)

812

(331)

$ (800)

$ (812)

(17)

(29)

(27)

(314)

(331)

(771)

(785)

$ (800)

$ (812)

Benefit obligations at December 31

1,997

2,075

Change in plan assets:

Fair value of plan assets at January 1

1,744

1,800

Actual return on plan assets

Employer contributions

Benefits paid from plan assets

Fair value of plan assets at December 31

Funded status of plans at December 31

Amounts recognized in the consolidated balance sheets:

Current liabilities

Noncurrent liabilities

Accrued benefit cost

Pretax amounts recognized in accumulated other comprehensive

(33)

(187)

1,570

(427)

(19)

(408)

(427)

175

(271)

1,744

loss:(b)

Net loss

Prior service credit

723

710

120

$ 191

(323)

(369)

(9)

(26)

(a)

Includes adjustments related to the MarkWest Merger in 2015 and the acquisition of Hess’ Retail Operations and Related Assets in 2014.

(b) Amounts exclude those related to LOOP and Explorer, equity method investees with defined benefit pension and postretirement plans for
which net losses of $19 million and $2 million were recorded in accumulated other comprehensive loss in 2015, reflecting our ownership
share.

152

Components of net periodic benefit cost and other comprehensive loss – The following summarizes the net
periodic benefit costs and the amounts recognized as other comprehensive loss for our defined benefit pension
and other postretirement plans.

(In millions)

Components of net periodic benefit cost:

Service cost

Interest cost

Expected return on plan assets

Amortization – prior service credit

– actuarial loss

– settlement loss

Pension Benefits
2014

2013

2015

Other Benefits
2014

2015

2013

$ 101

(98)

(46)

(107)

(46)

(107)

(45)

(4)

Net periodic benefit cost(a)

156

175

Other changes in plan assets and benefit obligations
recognized in other comprehensive loss (pretax):

Actuarial (gain) loss

Prior service cost (credit)(b)

Amortization of actuarial loss

Amortization of prior service cost

Other

Total recognized in other comprehensive loss

Total recognized in net periodic benefit cost

and other comprehensive loss

$ 143

188

$ (317)

$ (63)

$ 17

(55)

(147)

(161)

(8)

(2)

(3)

$ (433)

$ (54)

$ 22

243

$ (258)

$ 146

(a) Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

(b)

Includes adjustments related to the MarkWest Merger in 2015, plan amendments approved in 2013 and adjustments due to changes made
to the defined pension plans and the post-65 medical plan coverage effective January 1, 2013.

Lump sum payments to employees retiring in 2015, 2014 and 2013 exceeded the plan’s total service and interest
costs expected for those years. Settlement losses are required to be recorded when lump sum payments exceed
total service and interest costs. As a result, pension settlement expenses were recorded in 2015, 2014 and 2013
related to our cumulative lump sum payments made during those years.

The estimated net gain/loss and prior service credit for our defined benefit pension plans that will be amortized
from accumulated other comprehensive loss into net periodic benefit cost in 2016 are $38 million and $46
million. The estimated net loss and prior service credit for our other defined benefit postretirement plans that will
be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2016 is $3 million and
$3 million, respectively.

153

Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at
December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for
2015, 2014 and 2013.

Pension Benefits
2014

2013

2015

Other Benefits
2014

2013

2015

Weighted-average assumptions used to determine benefit obligation:

Discount rate

Rate of compensation increase

4.00% 3.65% 4.30% 4.50% 4.15% 4.95%

3.70% 3.70% 3.70% 3.70% 3.70% 3.70%

Weighted-average assumptions used to determine net periodic benefit

cost:

Discount rate

3.70% 4.05% 3.88% 4.30% 4.95% 4.11%

Expected long-term return on plan assets(a)

6.75% 7.00% 7.50%

Rate of compensation increase

3.70% 3.70% 5.00% 3.70% 3.70% 5.00%

(a)

Effective January 1, 2016, the expected long-term rate of return on plan assets is 6.50 percent due to a continuation of a change in our
primary plan investment strategy, which began January 1, 2014.

Expected long-term return on plan assets

The overall expected long-term return on plan assets assumption is determined based on an asset rate-of-return
modeling tool developed by a third-party investment group. The tool utilizes underlying assumptions based on
actual returns by asset category and inflation and takes into account our asset allocation to derive an expected
long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook.
The assumptions for equity and fixed income investments are developed using a building-block approach,
reflecting observable inflation information and interest rate information available in the fixed income markets.
Long-term assumptions for other asset categories are based on historical results, current market characteristics
and the professional judgment of our internal and external investment teams.

Assumed health care cost trend

The following summarizes the assumed health care cost trend rates.

Health care cost trend rate assumed for the following year:

Medical: Pre-65

Prescription drugs

Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):

Medical: Pre-65

Prescription drugs

Year that the rate reaches the ultimate trend rate:

Medical: Pre-65

Prescription drugs

December 31,
2014

2015

2013

7.50%

7.00%

5.00%

8.00%

7.00%

5.00%

8.00%

7.00%

5.00%

2021

2020

2018

Effective 2013, as a result of changes in the post-65 medical plan coverage of the Marathon Petroleum Health
Plan and the Marathon Petroleum Retiree Health Plan, increases are the lower of the trend rate or four percent.

154

Assumed health care cost trend rates have a significant effect on the amounts reported for defined benefit retiree
health care plans. A one percentage point change in assumed health care cost trend rates would have the
following effects:

(In millions)

Effect on total of service and interest cost components

Effect on other postretirement benefit obligations

Plan investment policies and strategies

1-Percentage-
Point Increase

1-Percentage-
Point Decrease

(5)

(39)

The investment policies for our pension plan assets reflect the funded status of the plans and expectations
regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the
assets in accordance with the legal requirements of all applicable laws; (2) diversify plan investments across asset
classes to achieve an optimal balance between risk and return and between income and growth of assets through
capital appreciation; and (3) source benefit payments primarily through existing plan assets and anticipated future
returns.

The investment goals are implemented to manage the plans’ funded status volatility and minimize future cash
contributions. The asset allocation strategy will change over time in response to changes primarily in funded
status, which is dictated by current and anticipated market conditions, the independent actions of our investment
committee, required cash flows to and from the plans and other factors deemed appropriate. Such changes in
asset allocation are intended to allocate additional assets to the fixed income asset class should the funded status
improve. The fixed income asset class shall be invested in such a manner that its interest rate sensitivity
correlates highly with that of the plans’ liabilities. Other asset classes are intended to provide additional return
with associated higher levels of risk. Investment performance and risk is measured and monitored on an ongoing
basis through quarterly investment meetings and periodic asset and liability studies. At December 31, 2015, the
primary plan’s targeted asset allocation was 51 percent equity, private equity, real estate, and timber securities
and 49 percent fixed income securities.

Fair value measurements

Plan assets are measured at fair value. The following provides a description of the valuation techniques employed
for each major plan asset category at December 31, 2015 and 2014.

Cash and cash equivalents – Cash and cash equivalents include a collective fund serving as the investment
vehicle for the cash reserves and cash held by third-party investment managers. The collective fund is valued at
net asset value (“NAV”) on a scheduled basis using a cost approach, and is considered a Level 2 asset. Cash and
cash equivalents held by third-party investment managers are valued using a cost approach and are considered
Level 2.

Equity – Equity investments includes common stock, mutual and pooled funds. Common stock investments are
valued using a market approach, which are priced daily in active markets and are considered Level 1. Mutual and
pooled equity funds are well diversified portfolios, representing a mix of strategies in domestic, international and
emerging market strategies. Mutual funds are publicly registered, valued at NAV on a daily basis using a market
approach and are considered Level 1 assets. Pooled funds are valued at NAV using a market approach and are
considered Level 2 assets.

Fixed Income – Fixed income investments include corporate bonds, U.S. dollar treasury bonds and municipal
bonds. These securities are priced on observable inputs using a combination of market, income and cost
approaches. These securities are considered Level 2 assets. Fixed income also includes a well diversified bond
portfolio structured as a pooled fund. This fund is valued at NAV on a daily basis using a combination of market,
income and cost approaches. It is considered a Level 2 asset.

155

Private Equity – Private equity investments include interests in limited partnerships which are valued using
information provided by external managers for each individual investment held in the fund. These holdings are
considered Level 3.

Real Estate – Real estate investments consist of interests in limited partnerships. These holdings are either
appraised or valued using investment manager’s assessment of assets held. These holdings are considered
Level 3.

Other – Other investments include two limited liability companies (“LLCs”) with no public market. The LLCs
were formed to acquire timberland in the northwest U.S. These holdings are either appraised or valued using
investment manager’s assessment of assets held. These holdings are considered Level 3. Other investments
classified as Level 1 include publicly traded depository receipts.

The following tables present the fair values of our defined benefit pension plans’ assets, by level within the fair
value hierarchy, as of December 31, 2015 and 2014.

(In millions)

Cash and cash equivalents

Equity:

Common stocks

Mutual funds

Pooled funds

Fixed income:

Corporate

Government

Pooled funds

Private equity

Real estate

Other

Level 1

December 31, 2015
Level 3

Level 2

142

399

516

103

193

Total

142

399

516

103

193

Total investments, at fair value

201

1,238

131

1,570

(In millions)

Cash and cash equivalents

Equity:

Common stocks

Mutual funds

Pooled funds

Fixed income:

Corporate

Government

Pooled funds

Private equity

Real estate

Other

Level 1

December 31, 2014
Level 3

Level 2

155

442

554

254

Total

155

442

554

254

Total investments, at fair value

220

1,380

144

1,744

156

The following is a reconciliation of the beginning and ending balances recorded for plan assets classified as
Level 3 in the fair value hierarchy:

(In millions)

Beginning balance

Actual return on plan assets:

Realized

Unrealized

Purchases

Sales

Ending balance

(In millions)

Beginning balance

Actual return on plan assets:

Realized

Unrealized

Purchases

Sales

Ending balance

Cash Flows

2015

Private
Equity

Real
Estate

Other

Total

144

(1)

(20)

(3)

(15)

(2)

(6)

(35)

131

2014

Private
Equity

Real
Estate

Other

Total

137

(13)

(16)

(29)

144

Contributions to defined benefit plans – Our funding policy with respect to the funded pension plans is to
contribute amounts necessary to satisfy minimum pension funding requirements, including requirements of the
Pension Protection Act of 2006, plus such additional, discretionary, amounts from time to time as determined
appropriate by management. In 2015, we made pension contributions totaling $35 million. We have no required
funding for 2016, but may make voluntary contributions at our discretion. Cash contributions to be paid from our
general assets for the unfunded pension and postretirement plans are estimated to be approximately $145 million
and $28 million in 2016.

Estimated future benefit payments – The following gross benefit payments, which reflect expected future service,
as appropriate, are expected to be paid in the years indicated.

(In millions)

2016

2017

2018

2019

2020

2021 through 2025

Pension Benefits Other Benefits

185

184

185

183

175

834

253

157

Contributions to defined contribution plans – We also contribute to several defined contribution plans for eligible
employees. Contributions to these plans totaled $94 million, $86 million and $76 million in 2015, 2014 and 2013,
respectively.

Multiemployer Pension Plan

We contribute to one multiemployer defined benefit pension plan under the terms of a collective-bargaining
agreement that covers some of our union-represented employees. The risks of participating in this multiemployer
plan are different from single-employer plans in the following aspects:

• Assets contributed to the multiemployer plan by one employer may be used to provide benefits to

employees of other participating employers.

•

If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be
borne by the remaining participating employers.

If we choose to stop participating in the multiemployer plan, we may be required to pay that plan an
amount based on the underfunded status of the plan, referred to as a withdrawal liability.

Our participation in this plan for 2015, 2014 and 2013 is outlined in the table below. The “EIN” column provides
the Employee Identification Number for the plan. The most recent Pension Protection Act zone status available
in 2015 and 2014 is for the plan’s year ended December 31, 2013 and December 31, 2012, respectively. The zone
status is based on information that we received from the plan and is certified by the plan’s actuary. Among other
factors, plans in the red zone are generally less than 65 percent funded. The “FIP/RP Status Pending/
Implemented” column indicates a financial improvement plan or a rehabilitation plan has been implemented. The
last column lists the expiration date of the collective-bargaining agreement to which the plan is subject. There
have been no significant changes that affect the comparability of 2015, 2014 and 2013 contributions. Our portion
of the contributions does not make up more than five percent of total contributions to the plan.

Pension Fund

EIN

2015

2014

Implemented

2015

2014

2013

Imposed

Agreement

Pension Protection FIP/RP Status

Expiration Date of

Act Zone Status

Pending/ MPC Contributions (In millions) Surcharge Collective - Bargaining

Central States,

Southeast and
Southwest Areas
Pension Plan(a)

36-6044243

Red

Implemented

January 31, 2019

(a)

This agreement has a minimum contribution requirement of $291 per week per employee for 2016. A total of 272 employees participated
in the plan as of December 31, 2015.

Multiemployer Health and Welfare Plan

We contribute to one multiemployer health and welfare plan that covers both active employees and retirees.
Through the health and welfare plan employees receive medical, dental, vision, prescription and disability
coverage. Our contributions to this plan totaled $7 million, $6 million and $5 million for 2015, 2014 and 2013.

23. Stock-Based Compensation Plans

Description of the Plans

Effective April 26, 2012, our employees and non-employee directors became eligible to receive equity awards
under the Marathon Petroleum Corporation 2012 Incentive Compensation Plan (“MPC 2012 Plan”). The MPC
2012 Plan authorizes the Compensation Committee of our board of directors (“Committee”) to grant non-
qualified or incentive stock options, stock appreciation rights, stock awards (including restricted stock and
restricted stock unit awards), cash awards and performance awards to our employees and non-employee
directors. Under the MPC 2012 Plan, no more than 50 million shares of our common stock may be delivered and

158

no more than 20 million shares of our common stock may be the subject of awards that are not stock options or
stock appreciation rights. In the sole discretion of the Committee, 20 million shares of our common stock may be
granted as incentive stock options. Shares issued as a result of awards granted under these plans are funded
through the issuance of new MPC common shares.

Prior to April 26, 2012, our employees and non-employee directors were eligible to receive equity awards under
the Marathon Petroleum Corporation 2011 Second Amended and Restated Incentive Compensation Plan (“MPC
2011 Plan”).

Stock-based awards under the Plans

We expense all share-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.

Stock Options – We grant stock options to certain officer and non-officer employees. All of the stock options
granted in 2015 fell under the MPC 2012 Plan. Stock options awarded under the MPC 2011 Plan and the MPC
2012 Plan represent the right to purchase shares of our common stock at its fair market value, which is the
closing price of MPC’s common stock on the date of grant. Stock options have a maximum term of ten years
from the date they are granted, and vest over a requisite service period of three years. We use the Black Scholes
option-pricing model to estimate the fair value of stock options granted, which requires the input of subjective
assumptions.

Restricted Stock and Restricted Stock Units – We grant restricted stock and restricted stock units to employees
and non-employee directors. In general, restricted stock and restricted stock units granted to employees vest over
a requisite service period of three years. Restricted stock and restricted stock unit awards granted after 2011 to
officers are subject to an additional one year holding period after the completion of the three-year requisite
service period. Prior to vesting, restricted stock recipients who received grants prior to 2012 have the right to
vote such stock and receive dividends at the same time regular shareholders are paid. Restricted stock recipients
who received grants in 2012 and after have the right to vote such stock; however, dividends are accrued and will
be paid upon vesting. Restricted stock units granted to non-employee directors are considered to vest
immediately at the time of the grant for accounting purposes, as they are non-forfeitable, but are not issued until
the director’s departure from the board of directors. Restricted stock unit recipients do not have the right to vote
such shares and receive dividend equivalents payable upon vesting. The non-vested shares are not transferable
and are held by our transfer agent. The fair values of restricted stock are equal to the market price of our common
stock on the grant date.

Performance Units – We grant performance unit awards to certain officer employees. Performance units are
dollar dominated. The target value of all performance units is $1.00, with actual payout up to $2.00 per unit (up
to 200% of target). Performance units issued under the MPC 2012 Plan have a 36-month requisite service period.
The payout value of these awards will be determined by the relative ranking of the total shareholder return
(“TSR”) of MPC common stock compared to the TSR of a select group of peer companies, as well as the
Standard & Poor’s 500 Energy Index fund over an average of four measurement periods. These awards will be
settled 25 percent in MPC common stock and 75 percent in cash. The number of shares actually distributed will
be determined by dividing 25 percent of the final payout by the closing price of MPC common stock on the day
the Committee certifies the final TSR rankings, or the next trading day if the certification is made outside of
normal trading hours. 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 that settle in
shares are accounted for as equity awards.

159

Total Stock-Based Compensation Expense

The following table reflects activity related to our stock-based compensation arrangements:

(In millions)

Stock-based compensation expense

Tax benefit recognized on stock-based compensation expense

Cash received by MPC upon exercise of stock option awards

Tax benefit received for tax deductions for stock awards exercised

Stock Option Awards

2015

2014

2013

The Black Scholes option-pricing model values used to value stock option awards granted were determined based
on the following weighted average assumptions:

Weighted average exercise price per share

Expected life in years

Expected volatility

Expected dividend yield

Risk-free interest rate

2015

2014

2013

50.85

42.51

42.32

6.0

33%

2.0%

1.7%

5.8

36%

1.9%

1.8%

6.0

40%

2.0%

1.0%

Weighted average grant date fair value of stock option awards granted

13.44

12.69

13.57

The expected life of stock options granted is based on historical data and represents the period of time that
options granted are expected to be held prior to exercise. The 2015 assumption for expected volatility of our
stock price reflects a weighting of 50 percent of our common stock implied volatility and 50 percent of MPC’s
common stock historical volatility. Prior to 2014, we used a weighting of our common stock implied volatility
and the historical volatility of a selected group of peers. Expected dividend yield is based on annualized
dividends at the date of grant. The risk-free interest rate for periods within the expected life of the option is based
on the U.S. Treasury yield curve in effect at the time of the grant.

The following is a summary of our common stock option activity in 2015:

Number of
of Shares(a)

Weighted Average
Exercise Price

Weighted Average
Remaining
Contractual Terms
(in years)

Aggregate
Intrinsic Value
(in millions)

Outstanding at December 31, 2014

Granted

Exercised

Forfeited, canceled or expired

Outstanding at December 31, 2015

Vested and expected to vest at

December 31, 2015

Exercisable at December 31, 2015

9,502,876

1,103,684

(1,827,245)

(54,684)

8,724,631

8,718,834

6,806,015

22.74

50.85

18.06

40.67

27.16

27.11

21.47

(a)

Includes an immaterial number of stock appreciation rights.

160

6.0

5.0

216

207

The intrinsic value of options exercised by MPC employees during 2015, 2014 and 2013 was $60 million, $48
million and $60 million, respectively.

As of December 31, 2015, unrecognized compensation cost related to stock option awards was $7 million, which
is expected to be recognized over a weighted average period of 1.5 years.

Restricted Stock Awards

The following is a summary of restricted stock award activity of our common stock in 2015:

Shares of Restricted Stock (“RS”)

Restricted Stock Units (“RSU”)

Number of
Shares

Weighted Average
Grant Date Fair
Value

Outstanding at December 31, 2014

1,030,146

Granted

RS’s Vested/RSU’s Issued

Forfeited

Outstanding at December 31, 2015

627,135

(537,020)

(45,718)

1,074,543

38.62

50.64

34.25

41.41

47.70

Number of
Units

822,186

81,685

(389,801)

(850)

513,220

Weighted Average
Grant Date Fair
Value

18.65

49.87

17.32

44.77

24.59

Of the 513,220 restricted stock units outstanding, 491,287 are vested and have a weighted average grant date fair
value of $23.44. These vested but unissued units are held by our non-employee directors and certain officers, are
non-forfeitable and are issuable upon the director’s departure from our board of directors or officers end of
employment with the company.

The following is a summary of the values related to restricted stock and restricted stock unit awards held by MPC
employees and non-employee directors:

Restricted Stock

Restricted Stock Units

Intrinsic Value of
Awards Vested
During the Period
(in millions)

Weighted Average
Grant Date Fair
Value of Awards
Granted During
the Period

Intrinsic Value
of Awards
Vested During
the Period
(in millions)

Weighted Average
Grant Date Fair
Value of Awards
Granted During
the Period

50.64

43.82

43.53

49.87

42.95

36.74

2015

2014

2013

As of December 31, 2015, unrecognized compensation cost related to restricted stock awards was $35 million,
which is expected to be recognized over a weighted average period of 1.5 years. There was no material
unrecognized compensation cost related to restricted stock unit awards.

Performance Unit Awards

The following table presents a summary of the 2015 activity for performance unit awards to be settled in shares:

Outstanding at December 31, 2014

Granted

Exercised

Canceled

Outstanding at December 31, 2015

161

Number of Units

Weighted
Average Grant
Date Fair Value

5,791,825

2,389,450

(2,035,833)

6,145,442

0.88

0.95

0.85

0.92

The number of shares that would be issued upon target vesting, using the closing price of our common stock on
December 31, 2015 would be 118,546 shares.

As of December 31, 2015, unrecognized compensation cost related to equity-classified performance unit awards
was $2 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 these
assumptions:

Risk-free interest rate

Look-back period

Expected volatility

2015

2014

2013

0.95%

0.63%

0.35%

2.84 years

30.38%

38.51%

41.67%

Grant date fair value of performance units granted

0.95

0.85

0.95

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. The look-back period reflects the remaining performance period at
the grant date. The assumption for the expected volatility of our stock price reflects the average MPC common
stock historical volatility.

MPLX Awards

Our wholly-owned subsidiary and the general partner of MPLX, MPLX GP LLC (“MPLX GP”), maintains a
unit-based compensation plan for officers, directors and employees (including any other individual who may be
considered an “employee” under a Registration Statement on Form S-8 or any successor form) of MPLX GP.

The MPLX 2012 Incentive Compensation Plan (“MPLX Plan”) permits various types of equity awards including
but not limited to grants of phantom units and performance units. Awards granted under the MPLX Plan will be
settled with MPLX units. Compensation expense for these awards were not material to our consolidated financial
statements for the years ended December 31, 2015, 2014 and 2013.

162

24. Leases

Lessee

We lease a wide variety of facilities and equipment under operating leases, including land and building space,
office equipment, storage facilities and transportation equipment. Most long-term leases include renewal options
and, in certain leases, purchase options. Future minimum commitments as of December 31, 2015, for capital
lease obligations and for operating lease obligations having initial or remaining non-cancelable lease terms in
excess of one year are as follows:

(In millions)

2016

2017

2018

2019

2020

Later years

Total minimum lease payments

Less imputed interest costs

Present value of net minimum lease payments

Operating lease rental expense was:

(In millions)

Rental expense

Lessor

Capital
Lease
Obligations

Operating
Lease
Obligations

282

212

186

161

138

475

1,454

251

498

150

348

2015

2014

2013

331

256

213

As a result of the MarkWest Merger, there are certain natural gas gathering, transportation and processing
agreements in which MPLX is considered to be the lessor under several implicit operating lease arrangements in
accordance with US GAAP. MPLX’s primary implicit
lease operations relate to a natural gas gathering
agreement in the Marcellus region 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 2024 and will continue thereafter on a year to year basis until terminated by
either party. Other significant implicit leases relate to a natural gas processing agreement in the Marcellus region
and a natural gas processing agreement in the Northeast region for which we earn 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.

163

Our revenue from implicit lease arrangements, excluding executory costs, totaled approximately $16 million in
2015 and nothing in 2014 and 2013. The implicit lease arrangements related to the processing facilities contain
contingent rental provisions whereby we receive additional fees if the producer customer exceeds the monthly
minimum processed volumes. During the year ended December 31, 2015, we received less than $1 million in
contingent lease payments and none for the year ended December 31, 2014. The following is a schedule of
minimum future rentals on the non-cancelable operating leases as of December 31, 2015:

(In millions)

2016

2017

2018

2019

2020

Later years

Total minimum lease payments

174

184

185

186

185

588

1,502

The following schedule summarizes our investment in assets held for operating lease by major classes as of
December 31, 2015:

(In millions)

Natural gas gathering and NGL transportation pipelines and facilities

Natural gas processing facilities

Construction in progress

Property, plant and equipment

Less accumulated depreciation

Total property, plant and equipment

25. Commitments and Contingencies

619

753

110

1,482

1,477

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. For matters for which we have not recorded an accrued liability, we are unable
to estimate a range of possible loss because the issues involved have not been fully developed through pleadings
and discovery. However, the ultimate resolution of some of these contingencies could, individually or in the
aggregate, be material.

Environmental matters – We are subject to federal, state, local and foreign 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 and certain other locations
including presently or formerly owned or operated retail marketing sites. Penalties may be imposed for
noncompliance.

At December 31, 2015 and 2014, accrued liabilities for remediation totaled $163 million and $185 million. It is
not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the
penalties if any that may be imposed. Receivables for recoverable costs from certain states, under programs to
assist companies in clean-up efforts related to underground storage tanks at presently or formerly owned or
operated retail marketing sites, were $70 million and $67 million at December 31, 2015 and 2014, respectively.

164

We are involved in a number of environmental enforcement matters arising in the ordinary course of business.
While the outcome and impact on us cannot be predicted with certainty, management believes the resolution of
these environmental matters will not,
individually or collectively, have a material adverse effect on our
consolidated results of operations, financial position or cash flows.

Litigation Relating to the MarkWest Merger – In July 2015, a purported class action lawsuit asserting claims
challenging the MarkWest Merger was filed in the Court of Chancery of the State of Delaware by a purported
unitholder of MarkWest. In August 2015, two similar putative class action lawsuits were filed in the Court of
Chancery of the State of Delaware by plaintiffs who purport to be unitholders of MarkWest. On September 9,
2015, these lawsuits were consolidated into one action pending in the Court of Chancery of the State of
Delaware, now captioned In re MarkWest Energy Partners, L.P. Unitholder Litigation. On October 1, 2015, the
plaintiffs filed a consolidated complaint against the individual members of the board of directors of MarkWest
Energy GP, L.L.C. (the “MarkWest GP Board”), MPLX, MPLX GP, MPC and Sapphire Holdco LLC, a wholly-
owned subsidiary of MPLX, asserting in connection with the MarkWest Merger and related disclosures that,
among other things, (i) the MarkWest GP Board breached its duties in approving the MarkWest Merger with
MPLX and (ii) MPC, MPLX, MPLX GP, and Sapphire Holdco LLC aided and abetted such breaches. On
February 4, 2016, the Court approved a stipulation and proposed order to dismiss all claims with prejudice as to
the named plaintiffs, but for the Court to retain jurisdiction to adjudicate an application for a mootness fee by the
plaintiffs’ counsel for an award of attorneys’ fees and reimbursement of expenses. We intend to vigorously
defend against any application for a mootness fee and do not expect the resolution of such matter to have a
material adverse effect.

MarkWest Environmental Proceeding – On July 6, 2015, officials from the United States Environmental
Protection Agency and the United States Department of Justice entered a pipeline launcher/receiver site utilized
for pipeline pigging operations in Washington County, Pennsylvania of MarkWest Liberty Midstream &
Resources, L.L.C., a wholly-owned subsidiary of MPLX (“MarkWest Liberty Midstream”), pursuant to a search
warrant issued by the United States District Court for the Western District of Pennsylvania. At the conclusion of
the search, the governmental officials presented MarkWest Liberty Midstream with a subpoena to provide
documents related to the design, construction, operation, maintenance, modification, inspection, assessment,
repair of, and/or emissions from MarkWest Liberty Midstream’s pipeline facilities located in Pennsylvania.
MarkWest Liberty Midstream is providing information in response to the subpoena and related requests for
information from the relevant agencies, and is in discussions with the relevant agencies regarding issues
associated with the search and subpoena and its operations of, or supplementary permitting obligations for, its
pipeline facilities in the Northeast. Immediately following the July 6, 2015 search, MarkWest Liberty Midstream
commenced its own assessment of its operations of launcher/receiver facilities. MarkWest Liberty Midstream’s
review to date has determined that other than potentially having to obtain minor source permits at a relatively
small number of individual sites, MarkWest Liberty Midstream’s operations have been conducted in a manner
fully protective of its employees and the public, and in substantial compliance with applicable laws and
regulations. It is possible that, in connection with any potential civil or criminal enforcement action associated
with this matter, MarkWest Liberty Midstream will incur material assessments, penalties or fines, incur material
defense costs and expenses, be required to modify our operations or construction activities which could increase
operating costs and capital expenditures, or be subject to other obligations or restrictions that could restrict or
prohibit our activities, any or all of which could adversely affect our consolidated results of operations, financial
position or cash flows. The amount of any potential assessments, penalties, fines, requirements, modifications,
costs or expenses that may be incurred in connection with any potential enforcement action cannot be reasonably
estimated at this time.

Other Lawsuits – In May 2015, the Kentucky attorney general filed a lawsuit against our wholly-owned
subsidiary, MPC LP, in the United States District Court for the Western District of Kentucky asserting claims
under federal and state antitrust statutes, the Kentucky Consumer Protection Act, and state common law. The
complaint, as amended in July 2015, alleges that MPC LP used deed restrictions, supply agreements with
customers and exchange agreements with competitors to unreasonably restrain trade in areas within Kentucky

165

and seeks declaratory relief, unspecified damages, civil penalties, restitution and disgorgement of profits. At this
early stage, the ultimate outcome of this litigation remains uncertain, and neither the likelihood of an unfavorable
outcome nor the ultimate liability, if any, can be determined, and we are unable to estimate a reasonably possible
loss (or range of loss) for this matter. We intend to vigorously defend ourselves in this matter.

In May 2007, the Kentucky attorney general filed a lawsuit against us and Marathon Oil in state court in Franklin
County, Kentucky for alleged violations of Kentucky’s emergency pricing and consumer protection laws following
Hurricanes Katrina and Rita in 2005. The lawsuit alleges that we overcharged customers by $89 million during
September and October 2005. The complaint seeks disgorgement of these sums, as well as penalties, under
Kentucky’s emergency pricing and consumer protection laws. We are vigorously defending this litigation. We
believe that this is the first lawsuit for damages and injunctive relief under the Kentucky emergency pricing laws to
progress this far and it contains many novel issues. In May 2011, the Kentucky attorney general amended his
complaint to include a request for immediate injunctive relief as well as unspecified damages and penalties related
to our wholesale gasoline pricing in April and May 2011 under statewide price controls that were activated by the
Kentucky governor on April 26, 2011 and which have since expired. The court denied the attorney general’s request
for immediate injunctive relief, and the remainder of the 2011 claims likely will be resolved along with those dating
from 2005. If the lawsuit is resolved unfavorably in its entirety, it could materially impact our consolidated results
of operations, financial position or cash flows. However, management does not believe the ultimate resolution of
this litigation will have a material adverse effect.

We are 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 us cannot be predicted with certainty, we believe that the
resolution of these other lawsuits and proceedings will not have a material adverse effect on our consolidated
financial position, results of operations or cash flows.

Guarantees – We have provided certain guarantees, direct and indirect, of the indebtedness of other companies.
Under the terms of most of these guarantee arrangements, we would be required to perform should the
guaranteed party fail to fulfill its obligations under the specified arrangements. In addition to these financial
guarantees, we also have various performance guarantees related to specific agreements.

Guarantees related to indebtedness of equity method investees – We hold interests in an offshore oil port, LOOP,
and a crude oil pipeline system, LOCAP. Both LOOP and LOCAP have secured various project financings with
throughput and deficiency agreements. Under the agreements, we are required to advance funds if the investees
are unable to service their debt. Any such advances are considered prepayments of future transportation charges.
The duration of the agreements vary but tend to follow the terms of the underlying debt, which extend through
2037. Our maximum potential undiscounted payments under these agreements for the debt principal totaled $172
million as of December 31, 2015.

We hold an interest in a refined products pipeline through our investment in Centennial, and have guaranteed our
portion of the payment of Centennial’s principal, interest and prepayment costs, if applicable, under a Master
Shelf Agreement, which is scheduled to expire in 2024. The guarantee arose in order for Centennial to obtain
adequate financing. Our maximum potential undiscounted payments under this agreement for debt principal
totaled $34 million as of December 31, 2015.

In connection with our 50 percent ownership in Crowley Ocean Partners, we have agreed to conditionally
guarantee our portion of the obligations of the joint venture and its subsidiaries under a senior secured term loan
agreement. The term loan agreement provides for loans of up to $325 million to finance the acquisition of four
product tankers. MPC’s liability under the guarantee for each vessel is conditioned upon the occurrence of
certain events, including if we cease to maintain an investment grade credit rating or the charter for the relevant
product tanker ceases to be in effect and is not replaced by a charter with an investment grade company on
certain defined commercial terms. As of December 31, 2015, our maximum potential undiscounted payments
under this agreement for debt principal associated with the first two vessels totaled $81 million.

166

Marathon Oil indemnifications – In conjunction with the Spinoff, we have entered into arrangements with
Marathon Oil providing indemnities and guarantees with recorded values of $2 million as of December 31, 2015,
which consist of unrecognized tax benefits related to MPC, its consolidated subsidiaries and the RM&T Business
operations prior to the Spinoff which are not already reflected in the unrecognized tax benefits described in Note
12, and other contingent liabilities Marathon Oil may incur related to taxes. Furthermore, the separation and
distribution agreement and other agreements with Marathon Oil
the Spinoff provide for cross-
indemnities between Marathon Oil and us. In general, Marathon Oil is required to indemnify us for any liabilities
relating to Marathon Oil’s historical oil and gas exploration and production operations, oil sands mining
operations and integrated gas operations, and we are required to indemnify Marathon Oil for any liabilities
relating to Marathon Oil’s historical refining, marketing and transportation operations. The terms of these
indemnifications are indefinite and the amounts are not capped.

to effect

Other guarantees – We have entered into other guarantees with maximum potential undiscounted payments
totaling $83 million as of December 31, 2015, which primarily consist of a commitment to contribute cash to an
equity method investee for certain catastrophic events, up to $50 million per event, in lieu of procuring insurance
coverage and leases of assets containing general lease indemnities and guaranteed residual values.

General guarantees associated with dispositions – Over the years, we have sold various assets in the normal
course of our 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 us to perform upon the occurrence of a triggering event or condition.
These guarantees and indemnifications are part of the normal course of selling assets. We are 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, 2015 and 2014, our contractual commitments
to acquire property, plant and equipment and advance funds to equity method investees totaled $1.6 billion and
$1.7 billion. The contractual commitments at December 31, 2015 includes $331 million of contingent
consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets, $630 million for
contributions to North Dakota Pipeline and $69 million for contributions to Crowley Ocean Partners. The
contractual commitments at December 31, 2014 included the $520 million contingent consideration associated
with the acquisition of the Galveston Bay Refinery and Related Assets, $703 million for contributions to North
Dakota Pipeline and $185 million for contributions to Illinois Extension Pipeline. See Note 5 for additional
information on our investments on our investments in North Dakota Pipeline, Illinois Extension Pipeline and
Crowley Ocean Partners. See Note 17 for additional information on the contingent consideration.

Certain natural gas processing and gathering arrangements require us 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, 2015, management does not believe there are any indications that we 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.

26. Subsequent Event

On February 3, 2016, we announced that we have offered to contribute our inland marine business to MPLX in
exchange for MPLX securities. The transaction is expected to close in the second quarter of 2016, pending
requisite approvals.

167

Selected Quarterly Financial Data (Unaudited)

(In millions, except per share data)

1st Qtr.

2nd Qtr.

3rd Qtr.

4th Qtr.

1st Qtr.

2nd Qtr.

3rd Qtr.

4th Qtr.

2015

2014

Revenues

$17,191

$20,537

$18,716

$15,607

$23,285

$26,844

$25,438

$22,250

Income from operations

1,470

1,335

1,549

Net income

Net income attributable to MPC

903

891

839

826

958

948

338

168

187

361

207

199

1,369

1,062

1,259

864

855

679

672

805

798

Net income attributable to MPC per

share:(a)

Basic

Diluted

Dividends paid per share

1.63

1.52

1.77

0.35

0.34

1.49

1.19

1.44

1.62

0.25

1.51

0.25

1.76

0.32

0.35

0.32

0.34

0.21

1.48

0.21

1.18

0.25

1.43

0.25

(a) We completed a two-for-one stock split in June 2015. All historical per share data has been retroactively restated on a post-split basis.

168

Supplementary Statistics (Unaudited)

(In millions)

Income from Operations by segment

Refining & Marketing(a)

Speedway(a)

Midstream(b)

Items not allocated to segments:

Corporate and other unallocated items(b)

Pension settlement expenses

Impairment

Income from operations

Capital Expenditures and Investments(c)(d)

Refining & Marketing

Speedway

Midstream

Corporate and Other(e)

Total

2015

2014

2013

4,186

3,609

3,206

673

289

(308)

(4)

(144)

4,692

1,143

501

14,447

192

544

280

(286)

(96)

4,051

1,104

2,981

543

110

375

210

(271)

(95)

3,425

2,094

296

234

165

16,283

4,738

2,789

(a)

(b)

The Refining & Marketing and Speedway segments in 2015 include inventory lower of cost or market charge of $345 million and $25
million, respectively.

Included in the Midstream segment for 2015, 2014 and 2013 are $20 million, $19 million and $20 million of corporate overhead
expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public
offering. Corporate overhead expenses are not currently allocated to other segments.

(d)

(e)

Includes capitalized interest of $37 million, $27 million and $28 million for 2015, 2014 and 2013, respectively.

169

Supplementary Statistics (Unaudited)

MPC Consolidated Refined Product Sales Volumes (thousands of

barrels per day)(a)(b)

Refining & Marketing Operating Statistics(b)

Refining & Marketing refined product sales volume (thousands of

barrels per day)(c)

Refining & Marketing gross margin (dollars per barrel)(d)(e)
Crude oil capacity utilization percent(f)
Refinery throughputs (thousands of barrels per day):(g)

Crude oil refined
Other charge and blendstocks

Total

Sour crude oil throughput percent
WTI-priced crude oil throughput percent
Refined product yields (thousands of barrels per day):(g)

Gasoline
Distillates
Propane
Feedstocks and special products
Heavy fuel oil
Asphalt

Total

Refinery direct operating costs (dollars per barrel):(h)

Planned turnaround and major maintenance
Depreciation and amortization
Other manufacturing(i)

Total

Refining & Marketing Operating Statistics By Region – Gulf Coast(b)

Refinery throughputs (thousands of barrels per day):(j)

Crude oil refined
Other charge and blendstocks

Total

Sour crude oil throughput percent
WTI-priced crude oil throughput percent
Refined product yields (thousands of barrels per day):(j)

Gasoline
Distillates
Propane
Feedstocks and special products
Heavy fuel oil
Asphalt

Total

Refinery direct operating costs (dollars per barrel):(h)

Planned turnaround and major maintenance
Depreciation and amortization
Other manufacturing(i)

Total

170

2015

2014

2013

2,301

2,138

2,086

2,289
15.25
99

1,711
177

1,888

55
20

913
603
36
281
31
55

2,125
15.05
95

1,622
184

1,806

52
19

869
580
35
276
25
54

2,075
13.24
96

1,589
213

1,802

53
21

921
572
37
221
31
54

1,919

1,839

1,836

1.13
1.39
4.15

6.67

1,060
184

1,244

68
6

534
392
26
286
15
16

1.80
1.41
4.86

8.07

991
182

1,173

64
3

508
368
23
274
13
13

1.20
1.36
4.14

6.70

964
195

1,159

65
7

551
365
23
215
19
13

1,269

1,199

1,186

0.81
1.09
3.88

5.78

1.82
1.15
4.73

7.70

1.00
1.09
3.98

6.07

Supplementary Statistics (Unaudited)

Refining & Marketing Operating Statistics By Region – Midwest

Refinery throughputs (thousands of barrels per day):(j)

Crude oil refined
Other charge and blendstocks

Total

Sour crude oil throughput percent
WTI-priced crude oil throughput percent
Refined product yields (thousands of barrels per day):(j)

Gasoline
Distillates
Propane
Feedstocks and special products
Heavy fuel oil
Asphalt

Total

Refinery direct operating costs (dollars per barrel):(h)

Planned turnaround and major maintenance
Depreciation and amortization
Other manufacturing(i)

Total

Speedway Operating Statistics(k)

Convenience stores at period-end
Gasoline and distillate sales (millions of gallons)
Gasoline & distillate gross margin (dollars per gallon)(e)(l)
Merchandise sales (in millions)
Merchandise gross margin (in millions)
Merchandise gross margin percent
Same store gasoline sales volume (period over period)
Same store merchandise sales (period over period)(m)

Midstream Operating Statistics

Crude oil and refined product pipeline throughputs (thousands of barrels per

day)(n)

Gathering system throughput (million cubic feet per day)(o)
Natural gas processed (million cubic feet per day)(o)
C2 (ethane) + NGLs (natural gas liquids) fractionated (mbpd)(o)

2015

2014

2013

631
45

676

33
44

361
212
13
43
13
41

683

1.66
1.78
4.76

8.20

2,746
3,942
0.1775
3,611
975
27.0%
(0.7)%
5.0%

$
$
$

625
54

679

35
42

371
207
14
41
12
41

686

1.47
1.74
4.21

7.42

1,478
3,146
0.1441
3,135
825
26.3%
0.5%
4.3%

$
$
$

2,119

2,204

651
39

690

34
43

379
211
12
38
17
39

696

1.64
1.83
4.36

7.83

2,766
6,038
0.1823
4,879
1,368
28.0%
(0.3)%
4.1%

2,191
3,075
5,468
307

$
$
$

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

Total average daily volumes of refined product sales to wholesale, branded and retail (Speedway segment) customers.
Includes the results of the Galveston Bay Refinery and Related Assets from the February 1, 2013 acquisition date.
Includes intersegment sales.
Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs.
Excludes the lower of cost or market adjustment.
Based on calendar day capacity, which is an annual average that includes downtime for planned maintenance and other normal operating
activities.
Excludes inter-refinery volumes of 46 mbpd, 43 mbpd and 36 mbpd for 2015, 2014 and 2013, respectively.
Per barrel of total refinery throughputs.
Includes utilities, labor, routine maintenance and other operating costs.
Includes inter-refinery transfer volumes.
Includes the impact of Hess’ Retail Operations and Related Assets from the September 30, 2014 acquisition date.
The price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing
fees, divided by gasoline and distillate sales volume.

(m) Excludes cigarettes. Same store comparison includes only locations owned at least 13 months.
(n) On owned common-carrier pipelines, excluding equity method investments.
(o)

Includes amounts related to unconsolidated equity method investments. Includes the results of the MarkWest assets beginning on the
Dec. 4, 2015 acquisition date.

171

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as
defined in Rules 13(a)-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934, as amended) was
carried out under the supervision and with the participation of our management, including our chief executive
officer and chief financial officer. Based upon that evaluation, the chief executive officer and chief financial
officer concluded that the design and operation of these disclosure controls and procedures were effective as of
December 31, 2015, the end of the period covered by this Annual Report on Form 10-K.

Internal Control over Financial Reporting and Changes in Internal Control over Financial Reporting

See Item 8. Financial Statements and Supplementary Data – Management’s Report on Internal Control over
Financial Reporting and – Report of Independent Registered Public Accounting Firm, which reports are
incorporated herein by reference.

During the quarter ended December 31, 2015, MPLX, a consolidated subsidiary of MPC, completed a merger
with MarkWest Energy Partners, L.P. The scope of our assessment of the effectiveness of disclosure controls and
procedures does not include MarkWest Energy Partners, L.P. There have been no other changes in our internal
control over financial reporting that have materially affected, or are reasonably likely to materially affect, our
internal control over financial reporting.

Item 9B. Other Information

None.

172

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information concerning our directors required by this item is incorporated by reference to the material appearing
under the sub-heading “Proposal No. 1 – Election of Class II Directors” located under the heading “Proposals of
the Board” in our Proxy Statement for the 2016 Annual Meeting of Shareholders. Information concerning our
executive officers is included in Part I, Item 1 of this Annual Report on Form 10-K.

Our board of directors has established the Audit Committee and determined our “Audit Committee Financial
Experts.” The related information required by this item is incorporated by reference to the material appearing
under the sub-heading “Audit Committee Financial Expert” located under the heading “The Board of Directors
and Corporate Governance” in our Proxy Statement for the 2016 Annual Meeting of Shareholders.

We have adopted a Code of Ethics for Senior Financial Officers, which applies to our Chief Executive Officer,
Chief Financial Officer, Vice President and Controller, Treasurer and other persons performing similar functions.
It is available on our website at http://ir.marathonpetroleum.com by selecting “Corporate Governance” and
clicking on “Code of Ethics for Senior Financial Officers.”

Section 16(a) Beneficial Ownership Reporting Compliance

Information regarding compliance with Section 16(a) of the Securities Exchange Act of 1934 is set forth under
the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement for the 2016
Annual Meeting of Shareholders, which is incorporated herein by reference.

Item 11. Executive Compensation

Information required by this item is incorporated by reference to the material appearing under the heading
“Executive Compensation;” under the sub-headings “Compensation Committee” and “Compensation Committee
Interlocks and Insider Participation” located under the heading “The Board of Directors and Corporate
Governance;” under the heading “Compensation of Directors;” and under the heading “Compensation Committee
Report” in our Proxy Statement for the 2016 Annual Meeting of Shareholders.

173

Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters

Information concerning security ownership of certain beneficial owners and management required by this item is
incorporated by reference to the material appearing under the headings “Security Ownership of Certain
Beneficial Owners” and “Security Ownership of Directors and Executive Officers” in our Proxy Statement for
the 2016 Annual Meeting of Shareholders.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2015 with respect to shares of our common stock
that may be issued under the MPC 2012 Plan and the MPC 2011 Plan. On April 29, 2015, our board of directors
approved a two-for-one stock split in the form of a stock dividend, which was distributed on June 10, 2015 to
shareholders of record at the close of business on May 20, 2015. The MPC 2012 Plan and the MPC 2011 Plan
were each amended effective June 10, 2015 to increase the number of shares of our common stock available for
awards under the respective plans from 25 million to 50 million and to increase the number of shares of our
common stock that may be subject to awards that are not stock options or stock appreciation rights from no more
than 10 million to no more than 20 million.

Plan category

Number of
securities to be
issued upon
exercise of
outstanding
options,
warrants and
rights(a)

Weighted-
average
exercise
price of
outstanding
options,
warrants
and rights(b)

Number of
securities
remaining
available for
future issuance
under equity
compensation
plans(c)

Equity compensation plans approved by stockholders

9,474,944

27.16

45,221,220

Equity compensation plan not approved by stockholders

Total

(a)

Includes the following:

9,474,944

N/A

45,221,220

8,724,631 stock options granted pursuant to the MPC 2012 Plan and the MPC 2011 Plan and not forfeited, cancelled or expired as
of December 31, 2015.

513,220 restricted stock units granted pursuant to the MPC 2012 Plan and the MPC 2011 Plan for shares unissued and not forfeited,
cancelled or expired as of December 31, 2015.

237,093 shares as the maximum potential number of shares that could be issued in settlement of performance units outstanding as of
December 31, 2015 pursuant to the MPC 2012 Plan, based on the closing price of our common stock on December 31, 2015 of
$51.84 per share. The number of shares reported for this award vehicle may overstate dilution. See Note 23 for more information on
performance unit awards granted under the MPC 2012 Plan.

In addition to the awards reported above, 1,074,543 shares of restricted stock have been issued pursuant to the MPC 2012 Plan and were
outstanding as of December 31, 2015.

(b) Restricted stock, restricted stock units and performance units are not taken into account in the weighted-average exercise price as such

awards have no exercise price.

(c) Reflects the shares available for issuance pursuant to the MPC 2012 Plan. All granting authority under the MPC 2011 Plan was revoked
following the approval of the MPC 2012 Plan by shareholders on April 25, 2012. No more than 17,973,884 of the shares reported in this
column may be issued for awards other than stock options or stock appreciation rights. The number of shares reported in this column
assumes 237,093 as the maximum potential number of shares that could be issued pursuant to the MPC 2012 Plan in settlement of
performance units outstanding as of December 31, 2015, based on the closing price of our common stock on December 31, 2015, of
$51.84 per share. The number of shares assumed for this award vehicle may understate the number of shares available for issuance
pursuant to the MPC 2012 Plan. See Note 23 for more information on performance unit awards granted pursuant to the MPC 2012 Plan.
Shares related to grants made pursuant to the MPC 2012 Plan that are forfeited, cancelled or expire unexercised become immediately
available for issuance under the MPC 2012 Plan.

174

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information required by this item is incorporated by reference to the material appearing under the heading
“Certain Relationships and Related Person Transactions,” and under the sub-heading “Board and Committee
Independence” under the heading “The Board of Directors and Corporate Governance” in our Proxy Statement
for the 2016 Annual Meeting of Shareholders.

Item 14. Principal Accountant Fees and Services

Information required by this item is incorporated by reference to the material appearing under the heading
“Independent Registered Public Accounting Firm’s Fees, Services and Independence” in our Proxy Statement for
the 2016 Annual Meeting of Shareholders.

175

Item 15. Exhibits and Financial Statement Schedules

A. Documents Filed as Part of the Report

PART IV

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.

3. Exhibits:

Exhibit
Number

Exhibit Description

Form Exhibit

Filing
Date

SEC
File No.

Filed
Herewith

Furnished
Herewith

Incorporated by Reference

2.1†

2.2†

2.3†

2.4†

2.5†

2.6

2.7

3.1

3.2

4.1

Plan of Acquisition, Reorganization, Arrangement,
Liquidation or Succession

Separation and Distribution Agreement, dated as of May 25,
2011, among Marathon Oil Corporation, Marathon Oil Company
and Marathon Petroleum Corporation

Purchase and Sale Agreement, dated as of October 7, 2012, by
and among BP Products North America Inc. and BP Pipelines
(North America) Inc., as the Sellers and Marathon Petroleum
Company LP, as the Buyer

Purchase Agreement by and between Speedway LLC and Hess
Corporation, dated as of May 21, 2014

Amendment No. 1 effective as of September 30, 2014, to the
Purchase Agreement by and between Speedway LLC and Hess
Corporation, dated as of May 21, 2014

Agreement and Plan of Merger, dated as of July 11, 2015, by and
among MPLX LP, Sapphire Holdco LLC, MPLX GP LLC,
MarkWest Energy Partners, L.P. and, for certain limited
purposes set forth therein, Marathon Petroleum Corporation.

Amendment to Agreement and Plan of Merger, dated as of
November 10, 2015, by and among MPLX LP, Sapphire Holdco
LLC, MPLX GP LLC, MarkWest Energy Partners, L.P. and
Marathon Petroleum Corporation.

Amendment Number 2 to Agreement and Plan of Merger, dated
as of November 16, 2015, by and among MPLX LP, Sapphire
Holdco LLC, MPLX GP LLC, MarkWest Energy Partners, L.P.
and Marathon Petroleum Corporation.

Articles of Incorporation and Bylaws

2.1

5/26/2011

001-35054

8-K

2.1

10/9/2012

001-35054

8-K

2.1

5/27/2014

001-35054

8-K

2.2

10/6/2014

001-35054

8-K

2.1

7/16/2015

001-35054

8-K

2.1

11/12/2015 001-35054

8-K

2.1

11/17/2015 001-35054

Restated Certificate of Incorporation of Marathon Petroleum
Corporation

8-K

3.1

6/22/2011

001-35054

Amended and Restated Bylaws of Marathon Petroleum
Corporation

Instruments Defining the Rights of Security Holders,
Including Indentures

10-Q 3.2

8/8/2012

001-35054

Indenture dated as of February 1, 2011 between Marathon
Petroleum Corporation and The Bank of New York Mellon Trust
Company, N.A., as Trustee

4.1

5/26/2011

001-35054

176

Exhibit
Number

Exhibit Description

Form Exhibit

Filing
Date

SEC
File No.

Filed
Herewith

Furnished
Herewith

Incorporated by Reference

4.2

4.3

4.4

4.5

4.6

4.7

4.8

4.9

4.10

4.11

10.1

10.2

10.3

10.4

Form of the terms of the 3 1⁄2% Senior Notes due 2016, 5 1⁄8%
Senior Notes due 2021 and 6 1⁄2% Senior Notes due 2041 of
Marathon Petroleum Corporation (including Form of Notes)

First Supplemental Indenture, dated as of September 5, 2014, by
and between Marathon Petroleum Corporation and The Bank of
New York Mellon Trust Company, N.A., as trustee (including
Form of Notes)

Second Supplemental Indenture, dated as of December 14, 2015,
by and between Marathon Petroleum Corporation and the Bank
of New York Mellon Trust Company, N.A., as trustee (including
Form of Notes)

4.2

5/26/2011

001-35054

10-Q 4.1

11/3/2014

001-35054

8-K

4.1

12/14/2015 001-35054

Indenture, dated February 12, 2015, between MPLX LP and The
Bank of New York Mellon Trust Company, N.A., as Trustee

8-K

4.1

2/12/2015

001-35714

8-K

4.2

2/12/2015

001-35714

8-K

4.2

12/22/2015 001-35714

8-K

4.3

12/22/2015 001-35714

8-K

4.4

12/22/2015 001-35714

8-K

4.5

12/22/2015 001-35714

8-K

4.1

12/22/2015 001-35714

10.1

5/26/2011

001-35054

10.2

5/26/2011

001-35054

8-K 10.1

7/1/2011

001-35054

8-K 10.1

12/23/2013 001-35054

First Supplemental Indenture, dated February 12, 2015, between
MPLX LP and The Bank of New York Mellon Trust Company,
N.A., as Trustee (including Form of Notes)

Second Supplemental Indenture, dated as of December 22, 2015,
by and between MPLX LP and the Bank of New York Mellon
Trust Company, N.A. (including Form of Note)

Third Supplemental Indenture, dated as of December 22, 2015,
by and between MPLX LP and the Bank of New York Mellon
Trust Company, N.A. (including Form of Note)

Fourth Supplemental Indenture, dated as of December 22, 2015,
by and between MPLX LP and the Bank of New York Mellon
Trust Company, N.A. (including Form of Note)

Fifth Supplemental Indenture, dated as of December 22, 2015, by
and between MPLX LP and the Bank of New York Mellon Trust
Company, N.A. (including Form of Note)

Registration Rights Agreement dated as of 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

Material Contracts

Tax Sharing Agreement dated as of May 25, 2011 by and among
Marathon Oil Corporation, Marathon Petroleum Corporation and
MPC Investment LLC

Employee Matters Agreement dated as of May 25, 2011 by and
between Marathon Oil Corporation and Marathon Petroleum
Corporation

Amendment to Employee Matters Agreement, dated as of
June 30, 2011 by and between Marathon Oil Corporation and
Marathon Petroleum Corporation

Receivables Purchase Agreement, dated as of December 18,
2013, by and among MPC Trade Receivables Company, LLC,
Marathon Petroleum Company LP, The Bank of Tokyo-
Mitsubishi UFJ, Ltd., New York Branch, as administrative agent
and sole lead arranger, certain committed purchasers and conduit
purchasers that are parties thereto from time to time and certain
other parties thereto from time to time as managing agents and
letter of credit issuers.

177

Exhibit
Number

10.5

10.6

10.7

10.8

10.9

10.10

10.11 *

10.12 *

10.13 *

Exhibit Description

Form Exhibit

Filing
Date

SEC
File No.

Filed
Herewith

Furnished
Herewith

Incorporated by Reference

Second Amended and Restated Receivables Sale Agreement,
dated as of December 18, 2013, by and between Marathon
Petroleum Company LP and MPC Trade Receivables Company
LLC

Revolving Credit Agreement, dated as of September 14, 2012, by
and among MPC, as borrower, JPMorgan Chase Bank, N.A., as
administrative agent, each of J.P. Morgan Securities LLC,
Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner &
Smith Incorporated, Morgan Stanley Senior Funding, Inc., RBS
Securities Inc. and UBS Securities LLC, as joint lead arrangers
and joint bookrunners, Citigroup Global Markets Inc., as
syndication agent, each of Bank of America, N.A., Morgan
Stanley Senior Funding, Inc., The Royal Bank of Scotland PLC
and USB AG, Stamford Branch, as documentation agents, and
several other commercial lending institutions that are parties
thereto.

First Amendment, dated December 20, 2012, to the Revolving
Credit Agreement, dated as of September 14, 2012, by and
among MPC, as borrower, the commercial financial institutions
that are lending parties thereto, and JPMorgan Chase Bank, N.A.,
as administrative agent.

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 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.

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.

8-K 10.2

12/23/2013 001-35054

8-K 10.1

9/20/2012

001-35054

8-K 10.1

12/20/2012 001-35054

8-K 10.1

11/26/2014 001-35054

8-K 10.1

11/6/2012

001-35054

8-K 10.2

11/6/2012

001-35054

Marathon Petroleum Corporation Second Amended and Restated
2011 Incentive Compensation Plan

S-3

4.3

12/7/2011 333-175286

Marathon Petroleum Corporation Policy for Recoupment of
Annual Cash Bonus Amounts

10-K 10.10

2/29/2012

001-35054

Marathon Petroleum Corporation Deferred Compensation Plan
for Non-Employee Directors

10-K 10.13

2/28/2013

001-35054

10.14 *

Marathon Petroleum Amended and Restated Excess Benefit Plan 10-K 10.14

2/27/2015

001-35054

10.15 *

Marathon Petroleum Amended and Restated Deferred
Compensation Plan

10-K 10.13

2/29/2012

001-35054

178

Exhibit
Number

10.16 *

Exhibit Description

Form Exhibit

Filing
Date

SEC
File No.

Filed
Herewith

Furnished
Herewith

Incorporated by Reference

Marathon Petroleum Corporation Executive Tax, Estate, and
Financial Planning Program

10-K 10.14

2/29/2012

001-35054

10.17 *

Speedway Excess Benefit Plan

10-K 10.15

2/29/2012

001-35054

10.18 *

Speedway Deferred Compensation Plan

10-K 10.16

2/29/2012

001-35054

10.19 *

10.20 *

10.21 *

10.22 *

10.23 *

10.24 *

10.25 *

10.26 *

10.27 *

10.28 *

10.29 *

10.30 *

10.31 *

Form of Marathon Petroleum Corporation Amended and
Restated 2011 Incentive Compensation Plan – Section 16 Officer
Restricted Stock Award Agreement (3 year pro rata vesting)

Form of Marathon Petroleum Corporation Amended and
Restated 2011 Incentive Compensation Plan – Section 16 Officer
Restricted Stock Award Agreement (3 year cliff vesting)

Form of Marathon Petroleum Corporation Amended and
Restated 2011 Incentive Compensation Plan Nonqualified Stock
Option Award Agreement – Section 16 Officer

Form of Marathon Petroleum Corporation 2011 Incentive
Compensation Plan Supplemental Restricted Stock Award
Agreement – Section 16 Officer

Form of Marathon Petroleum Corporation 2011 Incentive
Compensation Plan Supplemental Nonqualified Stock Option
Award Agreement – Section 16 Officer

Form of Marathon Petroleum Corporation 2011 Incentive
Compensation Plan Supplemental Restricted Stock Unit Award
Agreement – Non-Employee Director

Form of Marathon Petroleum Corporation Amended and
Restated 2011 Incentive Compensation Plan – Performance Unit
Award Agreement

8-K 10.4

7/7/2011

001-35054

8-K 10.5

7/7/2011

001-35054

8-K 10.6

7/7/2011

001-35054

8-K 10.1

12/7/2011

001-35054

8-K 10.2

12/7/2011

001-35054

10-K 10.22

2/29/2012

001-35054

10-K 10.23

2/29/2012

001-35054

Marathon Petroleum Corporation Amended and Restated
Executive Change in Control Severance Benefits Plan

10-K 10.26

2/28/2013

001-35054

Form of Marathon Petroleum Corporation Performance Unit
Award Agreement – 2012-2014 Performance Cycle

10-Q 10.3

5/9/2012

001-35054

Form of Marathon Petroleum Corporation Restricted Stock
Award Agreement – Officer

10-Q 10.4

5/9/2012

001-35054

Form of Marathon Petroleum Corporation Nonqualified Stock
Option Award Agreement – Officer

10-Q 10.5

5/9/2012

001-35054

Marathon Petroleum Corporation 2012 Incentive Compensation
Plan

S-8

4.3

4/27/2012 333-181007

Amended and Restated Marathon Petroleum Annual Cash Bonus
Program

10-K 10.31

2/27/2015

001-35054

10.32 *

MPC Non-Employee Director Phantom Unit Award Policy

10-K 10.32

2/28/2013

001-35054

10.33 *

10.34 *

10.35 *

10.36 *

Form of Marathon Petroleum Corporation Performance Unit
Award Agreement – 2013-2015 Performance Cycle

10-Q 10.1

5/9/2013

001-35054

Form of Marathon Petroleum Corporation Restricted Stock
Award Agreement – Officer

10-Q 10.2

5/9/2013

001-35054

Form of Marathon Petroleum Corporation Nonqualified Stock
Option Award Agreement – Officer

10-Q 10.3

5/9/2013

001-35054

MPLX LP – Form of MPC Officer Phantom Unit Award
Agreement

10-Q 10.4

5/9/2013

001-35054

179

Exhibit
Number

10.37 *

10.38 *

10.39 *

10.40

10.41*

10.42 *

10.43

Exhibit Description

Form Exhibit

Filing
Date

SEC
File No.

Filed
Herewith

Furnished
Herewith

Incorporated by Reference

MPLX LP – Form of MPC Officer Performance Unit Award
Agreement – 2013-2015 Performance Cycle

10-Q 10.5

5/9/2013

001-35054

Amendment to Certain Outstanding MPC Restricted Stock
Award Agreements and Performance Unit Award Agreements of
Garry L. Peiffer

10-K 10.38

2/28/2014

001-35054

Form of Marathon Petroleum Corporation Performance Unit
Award Agreement – 2014-2016 Performance Cycle

10-Q 10.1

5/5/2014

001-35054

8-K 10.1

8/29/2014

001-35054

Term Loan Agreement, dated August 26, 2014, by and among
Marathon Petroleum Corporation, as borrower, The Royal Bank
of Scotland PLC, as administrative agent, each of RBS Securities
Inc., The Bank of Tokyo-Mitsubishi UFJ, Ltd. Barclays Bank
PLC, Citigroup Global Markets Inc., and Morgan Stanley Senior
Funding, Inc., as joint lead arrangers and joint bookrunners. The
Bank of Tokyo-Mitsubishi UFJ, Ltd., as syndication agent, each
of Barclays Bank PLC, Citigroup Global Markets Inc. and
Morgan Stanley Senior Funding, Inc., as documentation agents,
and several other commercial lending institutions that are parties
thereto

First Amendment to the Marathon Petroleum Corporation
Amended and Restated 2011 Incentive Compensation Plan

10-Q 10.1

8/3/2015

001-35054

First Amendment to the Marathon Petroleum Corporation 2012
Incentive Compensation Plan

10-Q 10.2

8/3/2015

001-35054

Amendment Agreement, dated as of October 27, 2015, to Credit
Agreement, dated November 20, 2014 by and among MPLX LP,
Citibank, N.A., Wells Fargo Bank, National Association, and the
other institutions named on the signature pages thereto.

8-K 10.1

11/2/2015

001-35054

10.44 *

Retention Agreement, by and between Marathon Petroleum
Company LP and Randy S. Nickerson, dated November 13, 2015

10.45 *

Marathon Petroleum Thrift Plan

10.46

Loan Agreement, by and between MPLX LP and MPC
Investment LLC, dated December 4, 2015

8-K 10.1

12/10/2015 001-35054

12.1

14.1

21.1

23.1

24.1

31.1

31.2

32.1

32.2

Computation of Ratio of Earnings to Fixed Charges

Code of Ethics for Senior Financial Officers

10-K 14.1

2/29/2012

001-35054

List of Subsidiaries

Consent of Independent Registered Public Accounting Firm

Power of Attorney of Directors and Officers of Marathon
Petroleum Corporation

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

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

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

Certification of Senior Vice President and Chief Financial
Officer pursuant to 18 U.S.C. Section 1350.

180

Exhibit
Number

Exhibit Description

Form Exhibit

Filing
Date

SEC
File No.

Filed
Herewith

Furnished
Herewith

Incorporated by Reference

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase.

101.DEF

XBRL Taxonomy Extension Definition Linkbase.

101.LAB

XBRL Taxonomy Extension Label Linkbase.

†

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.

181

SIGNATURES

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.

February 26, 2016

MARATHON PETROLEUM CORPORATION

By:

/s/ John J. Quaid

John J. Quaid
Vice President and Controller

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on February 26, 2016 on behalf of the registrant and in the capacities indicated.

Signature

Title

/s/ Gary R. Heminger

Gary R. Heminger

/s/ Timothy T. Griffith

Timothy T. Griffith

President and Chief Executive Officer and Director
(Principal Executive Officer)

Senior Vice President and Chief Financial Officer
(Principal Financial Officer)

/s/ John J. Quaid

John J. Quaid

Evan Bayh

Charles E. Bunch

David A. Daberko

*
Steven A. Davis

William L. Davis

Donna A. James

James E. Rohr

Frank M. Semple

Vice President and Controller
(Principal Accounting Officer)

Director

182

Signature

John W. Snow

John P. Surma

Thomas J. Usher

Title

Director

Chairman of the Board and Director

* 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 registrant, which is being filed herewith on
behalf of such directors and officers.

By:

/s/ Gary R. Heminger

February 26, 2016

Gary R. Heminger
Attorney-in-Fact

183

CORPORATE INFORMATION

Corporate Headquarters
539 South Main St.
Findlay, OH 45840

Marathon Petroleum Corporation Website
www.marathonpetroleum.com

Investor Relations Office
539 South Main St.
Findlay, OH 45840
MPCInvestorRelations@marathonpetroleum.com

Lisa Wilson, Director
Investor Relations
(419) 421-2071

Teresa Homan, Manager
Investor Relations
(419) 421-2965

Notice of Annual Meeting
The 2016 Annual Meeting of Shareholders
will be held in Findlay, Ohio, on April 27, 2016.

Independent Accountants
PricewaterhouseCoopers LLP
One Seagate, Suite 1800
Toledo, OH 43604-1574

Stock Exchange Listing
New York Stock Exchange

Common Stock Symbol
MPC

Principal Stock Transfer Agent
Computershare
Shareholder correspondence should be mailed to:
P.O. Box 30170
College Station, TX 77842-3170
Overnight correspondence should be mailed to:
211 Quality Circle, Suite 210
College Station, TX 77845
(866) 820-7494 (toll free – U.S., Canada, Puerto Rico)
(781) 575-2176 (other non-U.S. jurisdictions)
web.queries@computershare.com

Annual Report on Form 10-K
Additional copies of the Marathon Petroleum
Corporation 2015 Annual Report may be obtained
by contacting:
Public Affairs
539 South Main St.
Findlay, OH 45840
(419) 421-3577

Dividends
Dividends on common stock, as may be declared by
the board of directors, are typically paid mid-month in
March, June, September and December.

Dividend Checks Not Received / Electronic Deposit
If you do not receive your dividend check on the
appropriate payment date, we suggest that you wait
at least 10 days after the payment date to allow for
any delay in mail delivery. After that time, advise
Computershare by phone or in writing to issue a
replacement check. You may contact Computershare
to authorize electronic deposit of your dividends into
your bank account.

Dividend Reinvestment and Direct Stock Purchase Plan
The Dividend Reinvestment and Direct Stock Purchase Plan provides
stockholders with a convenient way to purchase additional shares of
Marathon Petroleum Corporation common stock through investment
of cash dividends or through optional cash payments. Stockholders of
record can request a copy of the Plan Prospectus and an authorization
form from Computershare. Beneficial holders should contact their
brokers.

Book-entry Form of Stock Ownership
Marathon Petroleum Corporation exclusively maintains book-entry
form of stockholder ownership. Account statements issued by stock
transfer agent, Computershare, shall serve as stockholders’ record of
ownership. Questions regarding stock ownership should be directed
to Computershare.

Taxpayer Identification Number
Federal law requires that each stockholder provide a certified taxpayer
identification number (TIN) for his/her stockholder account. For
individual stockholders, your TIN is your Social Security number. If
you do not provide a certified TIN, Computershare may be required to
withhold 28 percent for federal income taxes from your dividends.

Address Change
It is important that you notify Computershare immediately, by phone,
in writing or by fax, when you change your address. Seasonal
addresses can be entered for your account.

Stock Return Performance Graph
The following performance graph compares the cumulative total
return, assuming the reinvestment of dividends, of a $100 investment
in our common stock from June 30, 2011, (the effective date of our
spinoff from Marathon Oil Corporation) to Dec. 31, 2015, compared
to the cumulative total return of a $100 investment in the S&P 500
Index and an index of peer companies (selected by us) for the same
period. Our peer group consists of the following companies that
engage in domestic refining operations: BP PLC, Royal Dutch Shell
PLC, Chevron Corporation, HollyFrontier Corporation, Phillips 66
(ConocoPhillips prior to May 1, 2012), Tesoro Corporation, ExxonMobil
Corporation, and Valero Energy Corporation.

The following performance graph is not “soliciting material” and will not be deemed
to be filed with the Securities and Exchange Commission (SEC) or incorporated
by reference into any of MPC’s filings with the SEC, except to the extent that we
specifically incorporate it by reference into any such filings.

Comparison of Cumulative Total Return
on $100 Invested in MPC Common Stock
on June 30, 2011 vs. S&P 500 Index and Peer Group Index

$300

$250

$200

$150

$100

$50

$0
6/30/11

MPC

12/31/11

12/31/12

12/31/13

12/31/14

12/31/15

Peer Group Index

Standard & Poor’s 500 Index
Total Return

On the back cover: MPC’s refinery
in Texas City, Texas

MARATHON PETROLEUM CORPORATION
539 South Main St.
Findlay, OH 45840

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,”
“estimate,” “expect,” “forecast,” “goal,” “intend,” “objective,” “opportunity,” “plan,” “position,” “potential,” “predict,” “project,” “seek,” “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 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. 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, 2015, 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.