2017
A N N U A L R E P O R T
1
T A B L E O F C O N T E N T S
1 LETTER TO OUR SHAREHOLDERS
4
FINANCIAL
HIGHLIGHTS
OUR BUSINESSES
6
MIDSTREAM
REFINING
CHEMICALS
MARKETING
AND SPECIALTIES
7 OUR VALUE CHAIN
8
OUR STRATEGY
OPERATING EXCELLENCE
GROWTH
RETURNS
DISTRIBUTIONS
HIGH-PERFORMING ORGANIZATION
EXECUTIVE
LEADERSHIP TEAM
20
BOARD OF
DIRECTORS
NON-GAAP RECONCILIATIONS
22
23
26
FORM 10-K
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GREG C. GARLAND
CHAIRMAN AND CHIEF EXECUTIVE OFFICER
TO OUR
SHAREHOLDERS,
In 2017, we celebrated
five years as a stand-alone
company. Reflecting on this
milestone, it is important to
thank our 14,600 dedicated
Phillips 66 employees for
successfully executing the
company’s strategy to deliver
superior shareholder value
while proudly demonstrating our
company’s vision of Providing
Energy, Improving Lives. Since
our company’s inception, we
have achieved a 257 percent
total cumulative shareholder
return and distributed $16.4
billion to shareholders in
dividends, share repurchases
and share exchanges.
Our 2017 operating and
financial results were strong.
We delivered earnings of $5.1
billion, adjusted earnings of
$2.3 billion and operating cash
flow of $3.6 billion. Our adjusted
earnings increased 51 percent
over the prior year, reflecting
improved Refining margins and
new Midstream growth projects
placed into service.
We returned $3 billion to
Phillips 66 shareholders in 2017
through dividends and share
repurchases. We increased our
dividend for the seventh time
since the company’s formation
and our Board of Directors
approved a new $3 billion share
repurchase program, bringing
total authorizations to $12 billion.
We have accomplished
these results while running
our operations in a safe,
reliable and environmentally
responsible manner. Our
combined workforce recordable
injury rate was 0.14, a record
for our company. We had the
lowest number of reportable
environmental events in our
history, and our process safety
performance Tier 1 rate of 0.03
was industry-leading.
2017 PHILLIPS 66 ANNUAL REPORT
11
ON THE COVER:
CPCHEM'S NEW
WORLD-SCALE
3.3 BILLION-
POUND-PER-YEAR
ETHANE CRACKER
AT THE CEDAR
BAYOU FACILITY IN
BAYTOWN, TEXAS.
2017 PHILLIPS 66 ANNUAL REPORT
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Our commitment to operating
excellence is further
demonstrated by our refineries
running at a 95 percent
utilization rate during a year
of heavy turnarounds.
In 2017, Phillips 66 provided $28
million to support organizations
promoting education,
environmental sustainability,
and community safety and
preparedness, including more
than $4 million in disaster
relief funding. Our employees
volunteered 73,000 hours of
their time in support of worthy
causes, and many on the Texas
Gulf Coast responded to the
challenges and devastating
effects from Hurricane Harvey.
In Midstream, we continue
to invest in growth projects
integrated with our existing
infrastructure. Our Midstream
business is favorably positioned
to benefit from continued oil and
gas production growth in the
United States. We are investing
in pipeline projects to transport
hydrocarbons from high-growth
production basins to Gulf
Coast market centers. At our
Beaumont Terminal, we continue
to expand our crude oil storage
capacity and export capabilities
to capitalize on growing export
demand. Within our NGL
business, we are optimizing
operations at our Sweeny Hub
on the Gulf Coast to position the
facility to benefit from improving
market conditions.
We participate in the chemicals
business through our joint venture
investment in CPChem. We
believe there are attractive growth
opportunities in the United States
to leverage existing infrastructure
and benefit from growing
production of cost-advantaged
feedstocks. In 2017, CPChem
achieved major milestones at its
U.S. Gulf Coast Petrochemicals
Project with the mechanical
completion of a world-scale
ethane cracker and startup of
two polyethylene units. This
project is expected to generate
significant cash flows as it ramps
up operations during 2018.
In Refining, we invest in high-
return, quick payout projects
to enhance margins. During
2017, we increased heavy
crude processing capability
at our Billings Refinery and
completed a diesel recovery
project at our Ponca City
Refinery. At both the Bayway
and Wood River refineries, FCC
unit modernization projects are
underway to increase clean
product yields.
Our Marketing business
generates high returns with
a low capital intensity. In the
United States, we are seeing
solid results from our re-imaged
branded site designs through
increased sales volumes. In
Europe, we continue to increase
the number of retail sites in
countries where we have a
strong market share.
As we move into 2018, our
strategy for long-term value
creation is the same as when
we started more than five
years ago: capturing growth
opportunities in our Midstream
and Chemicals businesses
and enhancing returns from
our existing assets in the
Refining and Marketing
businesses. Shareholder
distributions are fundamental
to our long-term strategy,
and we remain committed
to a secure, competitive and
growing dividend complemented
with share repurchases. Our
strategy is underpinned by a
strong foundation of operating
excellence and a high-
performing organization.
In closing, we are proud of what
the company has accomplished
for Phillips 66 shareholders.
We take your investment in
the company seriously and
thank you for the trust you
have placed in us. We have
been steadfast in our strategy,
providing outstanding value
to our shareholders, and
remaining true to our vision of
Providing Energy, Improving
Lives. We believe Phillips 66 is
a compelling investment and
that the company’s sustainable
operations will continue to
deliver benefits to you and our
stakeholders for years to come.
Greg C. Garland
Chairman and Chief Executive Officer
2
2017 PHILLIPS 66 ANNUAL REPORT
33
2017 PHILLIPS 66 ANNUAL REPORT
F I N A N C I A L H I G H L I G H T S
(Millions of Dollars, Except Per Share Amounts)
Sales and other operating revenues
Income before income taxes
Net income
Net income attributable to Phillips 66
Per share of common stock
Basic
Diluted
Cash and cash equivalents
Total assets
Long-term debt
Total equity
Cash from operating activities
Cash dividends declared per common share
Adjusted earnings
Adjusted earnings per share
2017
$102,354
3,555
5,248
5,106
9.90
9.85
3,119
54,371
10,069
27,428
3,648
2.73
$2,269
$4.38
2016
$84,279
2,191
1,644
1,555
2.94
2.92
2,711
51,653
9,588
23,725
2,963
2.45
$1,498
$2.82
2015
$98,975
6,044
4,280
4,227
7.78
7.73
3,074
48,580
8,843
23,938
5,713
2.18
$4,193
$7.67
TOTAL SHAREHOLDER RETURN
300%
200
100
0
5/31/12
12/31/13 12/31/14
12/31/15
12/31/16 12/31/17
PSX +257%
Peers* +179%
S&P 100 +111%
*Andeavor; Celanese Corporation; Delek US Holdings, Inc.; Eastman Chemical
Co.; Enterprise Products Partners, LP; HollyFrontier Corporation; Huntsman
Corporation; LyondellBasell Industries N.V.; Marathon Petroleum Corporation;
Oneok, Inc.; PBF Energy Inc.; Targa Resources Corp.; Valero Energy
Corporation; and Westlake Chemical Corp.
5,000
ADJUSTED EARNINGS
($ in millions)
4,193
2,269
1,498
15
16
17
ADJUSTED RETURN ON CAPITAL
EMPLOYED (ROCE)
(%)
14
8
5
15
16
17
Our 2017 earnings were $5.1
billion, or $9.85 per share, which
included a $2.7 billion benefit
from U.S. tax reform, primarily
associated with the revaluation
of the company’s net deferred
tax liabilities. Adjusted earnings
were $2.3 billion or $4.38 per
share. These amounts were
up significantly from 2016. The
increase in adjusted earnings
was primarily due to an
improvement in realized Refining
margins, as well as increased
Midstream earnings from new
growth projects. The increase
was partially offset by lower
realized Marketing margins.
During 2017, we generated $3.6
billion of cash from operations,
compared with $3.0 billion in
2016. We funded $1.8 billion
of capital expenditures, paid
$1.4 billion of dividends and
repurchased $1.6 billion of
shares. Our ending cash
balance was $3.1 billion.
Total debt at year-end was
$10.1 billion, resulting in a
debt-to-capital ratio of 27 percent.
Our strong investment grade
credit rating and balance sheet
reflect our commitment to
financial flexibility.
Our financial discipline, with
a focus on prudent capital
allocation, is fundamental
to value creation and has
enabled us to deliver strong
shareholder distributions.
For 2018, we are funding a
$2.3 billion capital budget,
which includes $1.4 billion of
growth capital and $0.9 billion of
sustaining capital. Approximately
$1.0 billion of the growth capital
is for Midstream projects, with
$0.4 billion for high-return
Refining and Marketing projects.
Our proportional share of capital
expenditures by our major joint
ventures is expected to be $0.9
billion. We expect our major joint
ventures to remain self-funded.
CAPITAL STRUCTURE
($B)
27.4
PSX equity $B
23.9
23.7
30%
26%
10.1
27%
22%
10.1
27%
25%
8.9
PSX noncontrolling interest
attributable to PSXP $B
PSX debt $B
PSXP third-party debt $B
PSX debt-to-capital
excluding PSXP
Consolidated debt-to-capital
15
16
17
2018 CONSOLIDATED CAPITAL BUDGET
Midstream
Growth
$2.3
BILLION
Sustaining
Phillips 66 Midstream Growth
Phillips 66 Partners Growth
Returns
$1.4 BILLION
GROWTH CAPITAL
• Pipeline and terminal investments
• Fractionation and processing capability
• Export capacity
• Yield and feedstock enhancements
$0.9 BILLION
SUSTAINING CAPITAL
• Maintaining safe, reliable assets
CONSOLIDATED CAPITAL
EXPENDITURES
($B)
5.8
2.8
1.8
15
16
17
PSX
PSXP
4
5
2017 PHILLIPS 66 ANNUAL REPORT O U R B U S I N E S S E S
O U R V A L U E C H A I N
Phillips 66 is a diversified energy manufacturing and logistics company. With a portfolio of Midstream,
Chemicals, Refining, and Marketing and Specialties businesses, the company processes, transports,
stores and markets fuels and products globally. Phillips 66 Partners, the company’s master limited
partnership, is integral to the portfolio. Headquartered in Houston, the company has 14,600 employees
committed to safety and operating excellence.
We have an integrated network of businesses and assets across the value chain downstream of the
wellhead. Our diverse portfolio is well-positioned to benefit from continued oil and gas production
growth in the United States.
Phillips 66
Phillips 66 Partners
CPChem
DCP Midstream
GLOBAL MARKETS
CRUDE OIL
Crude Pipelines,
Marine, Shipping
and Rail
Refineries
Product Pipelines,
Terminals and
Marine
Marketing
WELLHEAD
NGL and
Natural Gas
Gathering and
Processing
LIQUIDS AND
NATURAL GAS
Petrochemicals
Pipelines
Fractionation
and Storage
LPG Export
and Marketing
CPCHEM'S NEW ETHANE CRACKER AT CEDAR BAYOU
MIDSTREAM
REFINING
Our Midstream segment provides
crude oil and refined product
transportation, terminaling and
processing services, as well as
natural gas liquids (NGL) and liquefied
petroleum gas (LPG) transportation,
storage, processing and marketing
services, mainly in the United States.
This segment includes our master
limited partnership, Phillips 66 Partners
LP, as well as our 50 percent equity
investment in DCP Midstream, LLC.
21,000 MILES OF
PIPELINE SYSTEMS
CHEMICALS
The Chemicals segment consists of
our 50 percent joint venture interest in
Chevron Phillips Chemical Company
LLC (CPChem), which manufactures
and markets petrochemicals and
plastics worldwide. CPChem has cost-
advantaged assets concentrated in
North America and the Middle East.
30 GLOBAL
MANUFACTURING FACILITIES
Our Refining segment refines crude
oil and other feedstocks into petroleum
products such as gasoline, distillates
and aviation fuels at 13 refineries in
the United States and Europe. Our
Refining business focuses on operating
excellence and margin enhancement.
2.1 MILLION BPD OF CRUDE
THROUGHPUT CAPACITY
MARKETING AND
SPECIALTIES
Our Marketing and Specialties
segment markets refined petroleum
products such as gasoline, distillates
and aviation fuels, mainly in the
United States and Europe.
The segment also includes the
manufacturing and marketing of
specialty products such as base oils
and lubricants.
7,550 BRANDED
U.S. OUTLETS
1,630 BRANDED
INTERNATIONAL OUTLETS
6
2017 PHILLIPS 66 ANNUAL REPORT
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2017 PHILLIPS 66 ANNUAL REPORT
O U R S T R A T E G Y
The Phillips 66 strategic priorities of growth, returns and distributions are supported by a strong
foundation of operating excellence and a high-performing organization. We believe our strategy,
which is the same today as when we started in 2012, creates long-term shareholder value. We
made progress executing our key strategic priorities during 2017, achieving numerous milestones
and successes.
GROWTH
RETURNS
DISTRIBUTIONS
Reshaping our portfolio by
capturing growth opportunities in
Midstream and Chemicals
Enhancing returns
by maximizing earnings from
existing assets and investing
capital efficiently
Committed to dividend growth,
share repurchases and
financial strength
OPERATING EXCELLENCE
HIGH-PERFORMING ORGANIZATION
Committed to safety, reliability and environmental
stewardship while protecting shareholder value
Building capability, pursuing excellence and
doing the right thing
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OPERATING
EXCELLENCE
At Phillips 66, we are committed
to safe, efficient and reliable
operations with a focus on
environmental stewardship.
The strength of our health,
safety and environmental policy,
processes and systems is
demonstrated by our continually
improving record and industry-
leading results.
Our 2017 combined workforce
recordable injury rate of 0.14
was a record for us and is
approximately 25 times better
on average than the rest of
U.S. manufacturing.
Our process safety performance
Tier 1 rate of 0.03 is industry-
leading and is down 50 percent
over the last five years. We
also had the lowest number of
reportable environmental events
in our history.
In our Refining business, we
focus on being a safe, efficient,
reliable and low-cost operator.
We achieved a 95 percent
capacity utilization in our largest
ever turnaround year while also
facing hurricane impacts at our
Gulf Coast facilities.
In Midstream, through ongoing
optimization efforts, we improved
our operating performance at the
Sweeny Hub.
In our Chemicals business,
CPChem’s global Olefins and
Polyolefins (O&P) capacity
utilization rate was 87 percent,
TOTAL RECORDABLE RATES
(Incidents per 200,000 hours worked)
which was heavily impacted by
hurricane downtime. CPChem
persevered through the hurricane
damages at its Cedar Bayou
facility, which has returned to
normal operations.
Our operating costs increased
in 2017 primarily due to new
growth projects placed in
service, and higher turnaround
and utility expense. We are
looking across the enterprise
and along our value chain to
identify opportunities for cost
savings and efficiencies. We
believe that we can increase
our use of technology to be
even more agile and work
more efficiently.
1.5
Phillips 66
CPChem
DCP
1.0
0.5
0
.66
.54
.46
.19
.15
.14
.28 .30
.14
15
16
17
15
16
17
15
16
17
Industry average
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S A F E T Y R E C O G N I T I O N
The American Fuel and Petrochemical Manufacturers recognized 11 refineries for exemplary safety
performance during 2017, six of which were Phillips 66 refineries. Our Lake Charles Refinery received the
Distinguished Safety Award, the industry’s highest level of safety recognition, for its leading performance
in process and personal safety. Our Bayway, Billings, Rodeo, Santa Maria and Sweeny locations each
received the Elite Silver Award, which recognizes the top 5 percent of all sites in the industry for attaining
the highest safety performance.
REFINING ENVIRONMENTAL METRICS
(No. of events)
REFINING CAPACITY UTILIZATION
(%)
OPERATING COSTS AND SG&A
($B)
R E D U C I N G E M I S S I O N S
279
264
242
5
2
5
91
96
95
6.4
6.0 5.9
15
16
17
15
16
17
15
16
17
Planned maintenance
and turnarounds
10
Phillips 66 tracks emissions of sulfur oxides (SOx), nitrous oxides (NOx) and particulate matter (PM)
produced during the manufacturing of fuels. We have invested over $6 billion in refining and environmental
projects and improvements, including investments to reduce emissions through flare gas recovery
systems, wet gas scrubbers, and heater and boiler projects. Since 2012, we have achieved a substantial
reduction in SOx, NOx and PM emissions.
Phillips 66 is committed to managing greenhouse gas (GHG) emissions through investments in public
and private research to advance energy solutions. As part of the GHG focus, we monitor emissions
from our operations while seeking ways to lower them through increased energy efficiency. We conduct
research in alternative energy, processing improvement and product innovation through our research
and development technology center in Bartlesville, Oklahoma.
2017 PHILLIPS 66 ANNUAL REPORT
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2017 PHILLIPS 66 ANNUAL REPORT
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BEAUMONT
Explorer
B a y o u
B r i d g e
PASADENA
MONT BELVIEU
Lake
Charles
Louisiana Crude
Gathering System
Bayou Bridge
SORRENTO
CAVERN
Alliance
River Parish
NGL System
P H I L L I P S 6 6 P A R T N E R S
Phillips 66 Partners is an integral part of our Midstream
growth strategy, providing an attractive source of funding
as a master limited partnership. Phillips 66 Partners
can grow through organic investment opportunities,
acquisitions or through dropdown transactions from
Phillips 66. Phillips 66 Partners is positioned to deliver
a 30 percent five-year distribution compound average
growth rate through 2018.
BEAUMONT TERMINAL
Sweeny
l s
l
S a n d H i
SWEENY FRACTIONATOR
CLEMENS CAVERNS
LPG EXPORT TERMINAL
Terminal (PSX)
Terminal (PSXP)
Pipeline (PSX)
Pipeline (CPChem owned; PSX operated)
Underground storage facility (PSX)
Pipeline (PSXP)
Underground storage facility (PSXP)
Pipeline under construction (PSXP)
Fractionator (PSX)
Fractionator (PSXP)
Third-party terminal
Phillips 66 refinery
CPChem ethylene and/or polyethylene facility
CPChem USGC Petrochemical Project
GROWTH
Our Midstream business provides
growth opportunities at attractive
rates of return. We focus on
Midstream growth projects that
can be integrated with our existing
assets and infrastructure.
Our Beaumont Terminal is
strategically located on the U.S.
Gulf Coast with connections to 11
crude oil pipelines. During 2017,
we commissioned 2.2 million
barrels of additional storage,
bringing the terminal’s total crude
and products storage capacity to
11.1 million barrels. An additional
3.5 million barrels of crude
storage is under construction that
is expected to be commissioned
in 2018, and will bring the
terminal’s total capacity to 14.6
million barrels. Expansion of the
terminal’s export capability to
600,000 barrels per day (BPD)
was completed in the fourth
quarter of 2017.
Phillips 66 Partners owns a
25 percent interest in the
Bakken Pipeline, which
transports crude oil from the
Bakken/Three Forks production
area in North Dakota to delivery
points in Patoka, Illinois, and
Nederland, Texas, including our
Beaumont Terminal. Operations
on the 1,915-mile pipeline
started up during mid-2017, and
the pipeline has a capacity of
approximately 525,000 BPD.
The Sand Hills Pipeline
transports NGL from the
Permian and Eagle Ford
basins to fractionation facilities
along the Texas Gulf Coast,
including Phillips 66 Partners’
Sweeny Fractionator and the
Mont Belvieu market hub. Sand
Hills is owned two-thirds by
DCP Midstream and one-third
by Phillips 66 Partners. Sand
Hills’ capacity was expanded
to 365,000 BPD during the first
quarter of 2018, with plans to
further expand to 450,000 BPD in
the second half of 2018.
Phillips 66 Partners owns a
40 percent interest in the Bayou
Bridge Pipeline, which transports
crude oil from our Beaumont
Terminal to Lake Charles,
Louisiana. An extension of the
pipeline from Lake Charles to
the market center in St. James,
Louisiana, is currently under
construction and is expected to
be completed during the second
half of 2018. The Bayou Bridge
Pipeline facilitates the delivery of
advantaged crude oil to our Lake
Charles and Alliance refineries.
Our energy manufacturing
center in Sweeny, Texas,
integrates complex refining
capability, petrochemicals
production, NGL fractionation,
and storage and export facilities.
The hub includes our Freeport
LPG Export Terminal and
Phillips 66 Partners’ 100,000
BPD Sweeny Fractionator. We
continue to focus on optimizing
the facilities to lower costs
and improve operating rates.
Further expansion of the
fractionation capacity is in the
developmental stage.
In our Chemicals business,
CPChem is investing in growth
projects designed to capture
the benefit of lower-cost
petrochemical feedstocks on
the U.S. Gulf Coast to meet the
growing global demand for high-
quality plastics and chemical
intermediates. CPChem’s
U.S. Gulf Coast (USGC)
Petrochemicals Project is located
across two sites, in Old Ocean
and Cedar Bayou, Texas.
The USGC project includes
a 3.3 billion-pound-per-year
ethane cracker, which produces
ethylene, and two polyethylene
units, each with the capacity to
produce 1.1 billion pounds of
resin per year.
The polyethylene units have
started up and transitioned
to commercial operations.
The ethane cracker began
commissioning in the first quarter
of 2018 and is expected to ramp
to full production in the second
quarter. The project increases
CPChem’s global ethylene
and polyethylene capacity by
approximately one-third.
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2017 PHILLIPS 66 ANNUAL REPORT
RETURNS
Our Refining business focuses on
operating safely and reliably while
optimizing to improve margins.
Exercising cost and capital
discipline is essential to our
strategy. We invest our capital in
quick payout, high-return projects,
primarily to improve clean product
yield and increase advantaged
feedstock capability.
In the second quarter of 2017,
we increased heavy crude
processing capability at our
Billings Refinery to 100 percent
with the startup of a new vacuum
distillation unit. At the Ponca City
Refinery, we completed a diesel
recovery project in the fourth
quarter that increases clean
product yield.
We are modernizing FCC units
at both the Bayway and Wood
River refineries to increase clean
product production. We expect
the projects to be complete
during the second quarter of
2018. At our Lake Charles
Refinery, we are completing
modifications to run more
domestic crude to reduce our
feedstock costs.
Our Marketing business
generates stable earnings with
a low capital intensity. Our
independently owned U.S.
Marketing branded sites are
closely aligned with our refining
and logistics assets and provide
ratable pull through for our inland
and West Coast refineries.
In the United States, we
successfully rolled out a
signature image design for
our Phillips 66, 76 and Conoco
brands. During 2017, we
revitalized over 400 sites with
our signature image, bringing
the total number of re-imaged
sites to almost 1,300. Re-imaged
sites, on average, are achieving
a 3 percent increase in fuel
sales volumes.
GLOBAL CLEAN
PRODUCT YIELD*
(%)
84.4 84.6
85.5
BILLINGS REFINERY
We continue to grow and
generate high returns in
European Marketing through our
branded JET and COOP retail
businesses. These are high-
volume, efficient operations with
strong market share in Germany,
Austria and Switzerland. During
2017, we completed construction
of 30 new JET branded sites and
12 new COOP sites.
In the Specialties business,
finished lubricants are marketed
under our premium Phillips 66,
Kendall and Red Line brands.
Our strategy is to grow volumes
through the higher margin
marketer business, focusing
on fewer, stronger brands and
new premium products. We
are the third-largest lubricants
manufacturer in the United
States and receive industry high
rankings for supplier satisfaction.
15
16
17
*Yields exclude refineries
that have been sold in all
periods presented.
WEST COAST
364 MBD*
CENTRAL
CORRIDOR
493 MBD*
ATLANTIC
BASIN/EUROPE
537 MBD*
EUROPE
GULF COAST
752 MBD*
Phillips 66 and Phillips 66 Partners pipelines
Phillips 66 and Phillips 66 Partners facilities
Phillips 66 refinery
Phillips 66 joint venture refinery
*Refining net crude throughput capacity, effective Jan. 1, 2018
14
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With a continued focus on technology, we successfully launched new branded mobile phone
applications with mobile payment capabilities. This is a conduit for customers to purchase fuel
and products at Phillips 66, Conoco and 76 branded sites.
2017 PHILLIPS 66 ANNUAL REPORT Y
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REFINING RETURN
PROJECTS, COMPLETED
IN 2017 AND CURRENTLY
UNDER CONSTRUCTION,
ARE EXPECTED TO DELIVER
25,000 BPD
OF ADDITIONAL CLEAN
PRODUCTS BY THE END
OF 2018.
DISTRIBUTIONS
Returning capital to shareholders,
through a secure, competitive
and growing dividend, along with
share repurchases, is a strategic
priority for us.
During 2017, we distributed
$1.4 billion in dividends
and $1.6 billion in share
repurchases. Since the formation
of our company in 2012, we
have returned $16.4 billion
to shareholders through
dividends, share repurchases
and share exchanges.
Our Board of Directors
approved a new $3 billion
share repurchase program in
October 2017, which increased
our total authorization for share
repurchases to $12 billion. From
our formation through the end
of 2017, we repurchased or
exchanged 142 million shares,
representing 23 percent of our
original shares outstanding.
In May 2017, Phillips 66
increased the quarterly dividend
11 percent to $0.70 per share.
This is our seventh increase
since formation, representing a
30 percent compound annual
growth rate.
SHARE COUNT AND CAPITAL RETURNED
626 MILLION
TOTAL CAPITAL
RETURNED
$16.4 BILLION
502 MILLION
3Q 2012
4Q 2013 4Q 2014 4Q 2015
4Q 2016
4Q 2017
Number of shares outstanding
Capital returned*
* Through share purchases, share exchanges and dividends
DIVIDEND GROWTH
(Quarterly ¢/share)
30% CAGR
70
¢
¢20
23¢
3Q 2012
4Q 2013 4Q 2014 4Q 2015
4Q 2016
4Q 2017
16
2017 PHILLIPS 66 ANNUAL REPORT
17
17
2017 PHILLIPS 66 ANNUAL REPORT
55 NEW
DEPENDENT
SCHOLARSHIPS,
BRINGING THE
TOTAL NUMBER OF
RECIPIENTS TO
230
691 ORGANIZATIONS
RECEIVED VOLUNTEER GRANTS
1,621 ORGANIZATIONS RECEIVED
MONETARY MATCHING GIFTS
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PHILLIPS 66 PROVIDED
$28 MILLION IN
FINANCIAL SUPPORT
TO ORGANIZATIONS
PROMOTING EDUCATION
AND LITERACY, SAFETY
AND PREPAREDNESS,
ENVIRONMENTAL
SUSTAINABILITY AND
CIVIC ENRICHMENT. THIS
INCLUDED MORE THAN
$4 MILLION IN
DISASTER RELIEF FUNDING
L TO R: EMPLOYEES ASSEMBLE BABY FOOD BAGS FOR THE HOUSTON FOOD BANK.
EMPLOYEES VOLUNTEER AT A HABITAT FOR HUMANITY EVENT AND AT HERMANN PARK, HOUSTON.
HIGH-PERFORMING
ORGANIZATION
Our values of safety, honor
and commitment guide how
we make decisions, conduct
business and engage with
stakeholders. We have a high-
performing organization that is
defined by culture, capability
and performance. This forms the
basis for our relationships with
colleagues, customers, partners
and communities.
Our employees are held
accountable to the highest
ethical standards. We value an
inclusive and diverse workforce,
which is reflected in our many
Employee Resource Groups
(ERGs), with 30 percent of
employees participating with at
least one group. Our ERGs focus
on raising cultural awareness,
professional development,
recruiting and outreach, and
community involvement.
Our employees participated
in many worthwhile volunteer
activities such as mentoring
students in the classroom,
teaching STEM and literacy
activities at summer camps,
installing residential smoke
alarms for the American Red
Cross, assembling child safety
kits for local Crime Stoppers,
building houses for Habitat for
Humanity, cleaning local parks,
volunteering for local Special
Olympics, and hosting waste
disposal and recycling days.
During the past year, our
employees demonstrated what
a high-performing organization
looks like with their response
to Hurricane Harvey. They did
extraordinary things to help their
families, friends and neighbors.
And they worked to safeguard our
assets and communities. Through
these efforts, we were able to
ensure critical energy products
were supplied to first responders,
businesses and consumers.
We are very proud of how our
employees responded to the
challenges caused by this storm.
73,000 HOURS VOLUNTEERED BY
EMPLOYEES DURING 2017
18
2017 PHILLIPS 66 ANNUAL REPORT
19
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2017 PHILLIPS 66 ANNUAL REPORT
B O A R D O F D I R E C T O R S
GREG C. GARLAND
Mr. Garland serves as Chairman and CEO of Phillips 66. He was
appointed Senior Vice President, Exploration and Production-
Americas for ConocoPhillips in 2010. He was previously President
and CEO of Chevron Phillips Chemical Company LLC (CPChem)
from 2008 to 2010, having served as Senior Vice President,
Planning and Specialty Products, CPChem, from 2000 to 2008. Mr.
Garland also serves on the boards of Amgen Inc. and Phillips 66
Partners GP LLC, the general partner of Phillips 66 Partners LP. (2)
GARY K. ADAMS
Mr. Adams is the former chief advisor of chemicals for IHSMarkit. He
started his chemical industry career with Union Carbide. After 15 years
serving in a number of positions at Union Carbide, Mr. Adams joined
Chemical Market Associates Inc. (CMAI). He served as President, CEO
and Chairman of the Board of CMAI from 1997 until its acquisition by IHS
in 2011. Mr. Adams is a director of Trecora Resources and previously
served on the boards of Westlake Chemical Partners LP from 2014 to
2016 and Phillips 66 Partners LP from 2013 to 2016. (3,5)
J. BRIAN FERGUSON
Mr. Ferguson retired as Chairman of Eastman Chemical Company
in 2010 and as CEO of Eastman in 2009. He became the Chairman
and CEO of Eastman in 2002. He served on the board of NextEra
Energy, Inc. from 2005 to 2013 and currently serves on the board of
Owens Corning. (1,2,4,5)
WILLIAM R. LOOMIS, JR.
Mr. Loomis has been an independent financial advisor since 2009. He
was a general partner and Managing Director of Lazard Freres & Co.
from 1984 to 2002, the CEO of Lazard LLC from 2000 to 2001 and a
Limited Managing Director of Lazard LLC from 2002 to 2004. Mr. Loomis
served as a director of L Brands Inc. from 2005 to 2016. (1,2,4,5)
JOHN E. LOWE
Mr. Lowe served as assistant to the CEO of ConocoPhillips, a
position he held from 2008 until May 2012. He previously held a
series of executive positions with ConocoPhillips, including Executive
Vice President, Exploration and Production, from 2007 to 2008, and
Executive Vice President, Commercial, from 2006 to 2007. Mr. Lowe
is a Senior Executive Advisor to Tudor, Pickering, Holt & Co. He
served on the board of Agrium Inc. from 2010 to 2015 and currently
serves on the boards of TransCanada Corporation and Apache
Corporation, where he is Non-Executive Chairman. (1,2,5)
DENISE L. RAMOS
Ms. Ramos has served as the Chief Executive Officer, President
and a director of ITT Inc. (formerly ITT Corporation) since October
2011. She previously served as Senior Vice President and Chief
Financial Officer of ITT. Prior to joining ITT, Ms. Ramos served as
Chief Financial Officer for Furniture Brands International from 2005
to 2007. From 2000 to 2005, Ms. Ramos served as Senior Vice
President and Corporate Treasurer at Yum! Brands, Inc. and Chief
Financial Officer for the U.S. division of KFC Corporation. Ms. Ramos
began her career in 1979 at Atlantic Richfield Company (ARCO),
where she spent more than 20 years serving in a number of finance
positions including Corporate General Auditor and Assistant Treasurer.
Ms. Ramos served on the board of Praxair, Inc. from 2014 to 2016.
She serves on the board of trustees for the Manufacturers Alliance
for Productivity and Innovation, and is a member of the Business
Council. (1,4,5)
VICTORIA J. TSCHINKEL
Ms. Tschinkel currently serves as the Vice-Chairwoman of 1000
Friends of Florida and previously was its Chairwoman. In addition,
Ms. Tschinkel is a director of the National Fish and Wildlife
Foundation, serving on the Gulf Benefits Committee. She served
as State Director of the Florida Nature Conservancy from 2003 to
2006, was senior environmental consultant to Landers & Parsons,
a Tallahassee, Florida law firm, from 1987 to 2002, and was the
Secretary of the Florida Department of Environmental Regulation
from 1981 to 1987. (1,5)
HAROLD W. MCGRAW III
Mr. McGraw is Chairman Emeritus of S&P Global Inc. (previously
McGraw Hill Financial), having served as Chairman of the Board
from 1999 until 2015, as President and Chief Executive Officer from
1998 to November 2013 and as President and Chief Operating
Officer starting in 1993. Mr. McGraw is the Honorary Chairman of
the International Chamber of Commerce. He currently serves on the
board of United Technologies Corporation. (3,5)
GLENN F. TILTON
Mr. Tilton served as Chairman of the Midwest of JPMorgan
Chase & Co. from 2011 to 2014. From 2002 to 2010, he served
as Chairman, President and CEO of UAL Corporation, a holding
company, and United Air Lines, Inc., an air transportation company
and wholly owned subsidiary of UAL Corporation. Mr. Tilton
previously spent more than 30 years in increasingly senior roles
with Texaco Inc., including Chairman and CEO in 2001. He served
as Non-Executive Chairman of the Board of United Continental
Holdings Inc. from 2010 to 2013 and currently serves on the boards
of Abbott Laboratories and AbbVie Inc. (as lead director). (2,3,5)
MARNA C. WHITTINGTON
Dr. Whittington was CEO of Allianz Global Investors Capital, a
diversified global investment firm, from 2002 until her retirement in
January 2012. She was Chief Operating Officer of Allianz Global
Investors, the parent company of Allianz Global Investors Capital,
from 2001 to 2011. Prior to that, she was Managing Director and
Chief Operating Officer of Morgan Stanley Asset Management. Dr.
Whittington started in the investment management industry in 1992,
joining Philadelphia-based Miller Anderson & Sherrerd. Previously,
she was Executive Vice President and CFO of the University of
Pennsylvania, from 1984 to 1992. Earlier, she served as Budget
Director and, subsequently, Secretary of Finance for the State of
Delaware. Dr. Whittington served on the board of Rohm & Haas
Company from 1989 to 2009 and currently serves on the boards of
Macy’s, Inc. and Oaktree Capital Group, LLC. (2,3,4,5)
L TO R: JOHN LOWE, MARNA WHITTINGTON, BRIAN FERGUSON, HAROLD MCGRAW, GREG GARLAND,
GLENN TILTON, VICTORIA TSCHINKEL, DENISE RAMOS, WILLIAM LOOMIS, GARY ADAMS
(1) MEMBER OF THE AUDIT AND FINANCE COMMITTEE
(2) MEMBER OF THE EXECUTIVE COMMITTEE
(3) MEMBER OF THE HUMAN RESOURCES AND COMPENSATION COMMITTEE
(4) MEMBER OF THE NOMINATING AND GOVERNANCE COMMITTEE
(5) MEMBER OF THE PUBLIC POLICY COMMITTEE
AS OF MARCH 1, 2018
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2017 PHILLIPS 66 ANNUAL REPORT E X E C U T I V E L E A D E R S H I P T E A M
N O N - G A A P R E C O N C I L I A T I O N S
RECONCILIATION OF EARNINGS TO ADJUSTED EARNINGS
(Millions of dollars)
Net income attributable to Phillips 66 (earnings)
Pre-tax adjustments:
Impairments by equity affiliates
Pending claims and settlements
Certain tax impacts *
Lower-of-cost-or-market inventory adjustments
Asset dispositions
Pension settlement expense
Recognition of deferred logistics commitments
Equity affiliate ownership restructuring
Railcar lease residual value deficiencies and related costs
Gain on consolidation of business
Hurricane-related costs
Tax impact of adjustments**
U.S. tax reform
Other tax impacts
Adjusted earnings
Earnings per share of common stock (dollars)
Adjusted earnings per share of common stock (dollars)†
*Pre-tax impact only. Tax-only adjusted items included in "other tax impacts."
2017
$5,106
64
(60)
(23)
-–
-–
83
-–
-–
-–
(423)
210
47
(2,735)
-–
$2,269
$9.85
$4.38
2016
$1,555
95
(117)
(32)
-–
-–
-–
30
33
40
-–
-–
4
-–
(110)
$1,498
$2.92
$2.82
2015
$4,227
390
30
(9)
53
(280)
80
-–
-–
-–
-–
-–
(181)
-–
(117)
$4,193
$7.73
$7.67
**We generally tax effect taxable U.S.-based special items using a combined federal and state statutory income tax rate of approximately
38 percent. Taxable special items attributable to foreign locations likewise use a local statutory income tax rate. Nontaxable events reflect
zero income tax. These events include, but are not limited to, most goodwill impairments, transactions legislatively exempt from income
tax, transactions related to entities for which we have made an assertion that the undistributed earnings are permanently reinvested, or
transactions occurring in jurisdictions with a valuation allowance.
†Weighted-average diluted shares outstanding and income allocated to participating securities, if applicable, in the adjusted earnings per
share calculation are the same as those used in the GAAP diluted earnings per share calculation.
RECONCILIATION OF ROCE TO ADJUSTED ROCE
(Millions of dollars) Numerator
Net income
After-tax interest expense
GAAP ROCE earnings
After-tax special items
Adjusted ROCE earnings
(Millions of dollars) Denominator
GAAP average capital employed *
* Total equity plus total debt
GAAP ROCE (percent)
Adjusted ROCE (percent)
2017
$5,248
285
5,533
(2,837)
2,696
2016
$1,644
220
1,864
(57)
1,807
2017
2016
$35,700
$33,344
15%
8%
6%
5%
2015
$4,280
201
4,481
(34)
4,447
2015
$31,749
14%
14%
STANDING L TO R: JEFF DIETERT, ZHANNA GOLODRYGA, JAY CHURCHILL, TIM ROBERTS
SEATED L TO R: KEVIN MITCHELL, BOB HERMAN, GREG GARLAND, PAULA JOHNSON, SONYA REED
Greg C. Garland, Chairman and Chief Executive Officer
Jay D. Churchill, Senior Vice President, Health, Safety and Environment, and Projects
Jeff A. Dietert, Vice President, Investor Relations
Zhanna Golodryga, Senior Vice President, Chief Digital and Administrative Officer
Robert A. Herman, Executive Vice President, Refining
Paula A. Johnson, Executive Vice President, Legal and Government Affairs, General Counsel, Corporate Secretary
Kevin J. Mitchell, Executive Vice President, Finance and Chief Financial Officer
Sonya M. Reed, Senior Vice President, Human Resources, Communications and Public Affairs
Timothy D. Roberts, Executive Vice President, Marketing and Commercial
22
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2017 PHILLIPS 66 ANNUAL REPORT
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PHILLIPS 66
FORM 10-K
2017
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X]
For the fiscal year ended
[ ]
For the transition period from
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
December 31, 2017
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
to
Commission file number: 001-35349
Phillips 66
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
45-3779385
(I.R.S. Employer
Identification No.)
2331 CityWest Blvd., Houston, Texas 77042
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: 281-293-6600
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, $0.01 Par Value
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
[X] Yes [ ] No
[ ] Yes [X] No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing requirements for the past 90 days.
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 during the preceding 12
months (or for such shorter period that the registrant was required to submit and post such files).
[X] Yes [ ] No
[X] Yes [ ] 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 the 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.
[X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller
reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule
12b-2 of the Exchange Act.
Large accelerated filer [X]
Emerging growth company [ ]
Accelerated filer [ ]
Non-accelerated filer [ ]
Smaller reporting company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for
complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
[ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
[ ] Yes [X] No
The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2017, the last business day of the registrant’s most
recently completed second fiscal quarter, based on the closing price on that date of $82.69, was $42.3 billion. The registrant, solely for the purpose of
this required presentation, had deemed its Board of Directors and executive officers to be affiliates, and deducted their stockholdings in determining
the aggregate market value.
The registrant had 501,237,339 shares of common stock outstanding at January 31, 2018.
Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 9, 2018 (Part III).
26
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2017 PHILLIPS 66 ANNUAL REPORT
Item
TABLE OF CONTENTS
PART I
1 and 2. Business and Properties
Corporate Structure
Segment and Geographic Information
Midstream
Chemicals
Refining
Marketing and Specialties
Technology Development
Competition
General
1A. Risk Factors
1B. Unresolved Staff Comments
3. Legal Proceedings
4. Mine Safety Disclosures
Executive Officers of the Registrant
PART II
5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
6. Selected Financial Data
7. Management's Discussion and Analysis of Financial Condition and Results of Operations
7A. Quantitative and Qualitative Disclosures About Market Risk
Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the Private
Securities Litigation Reform Act of 1995
8. Financial Statements and Supplementary Data
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
9A. Controls and Procedures
9B. Other Information
PART III
10. Directors, Executive Officers and Corporate Governance
11. Executive Compensation
12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
13. Certain Relationships and Related Transactions, and Director Independence
14. Principal Accounting Fees and Services
15. Exhibits, Financial Statement Schedules
16. Form 10-K Summary
Signatures
PART IV
29
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[This Page Intentionally Left Blank]
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2017 PHILLIPS 66 ANNUAL REPORT [This Page Intentionally Left Blank]
Unless otherwise indicated, “the company,” “we,” “our,” “us” and “Phillips 66” are used in this report to refer to the
businesses of Phillips 66 and its consolidated subsidiaries. Unless the context requires otherwise, references to “DCP
Midstream” include the consolidated operations of DCP Midstream, LLC, including DCP Midstream, LP, the master
limited partnership formed by DCP Midstream, LLC.
This Annual Report on Form 10-K contains forward-looking statements including, without limitation, statements relating
to our plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of
the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,”
“continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,”
“objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify
forward-looking statements. The company does not undertake to update, revise or correct any forward-looking
information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking
statements should be read in conjunction with the company’s disclosures under the heading “CAUTIONARY
STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995.”
PART I
Items 1 and 2. BUSINESS AND PROPERTIES
CORPORATE STRUCTURE
Phillips 66, headquartered in Houston, Texas, was incorporated in Delaware in 2011 in connection with, and in
anticipation of, a restructuring of ConocoPhillips that separated its downstream businesses into an independent, publicly
traded company named Phillips 66. The two companies were separated by ConocoPhillips distributing to its stockholders
all the shares of common stock of Phillips 66 after the market closed on April 30, 2012 (the Separation). Phillips 66 stock
trades on the New York Stock Exchange under the “PSX” stock symbol.
Our business is organized into four operating segments:
1) Midstream—Provides crude oil and refined products transportation, terminaling and processing services, as well
as natural gas, natural gas liquids (NGL) and liquefied petroleum gas (LPG) transportation, storage, processing
and marketing services, mainly in the United States. This segment includes our master limited partnership
(MLP), Phillips 66 Partners LP (Phillips 66 Partners), as well as our 50 percent equity investment in DCP
Midstream, LLC (DCP Midstream).
2) Chemicals—Consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC
(CPChem), which manufactures and markets petrochemicals and plastics on a worldwide basis.
3) Refining—Refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and
aviation fuels) at 13 refineries in the United States and Europe.
4) Marketing and Specialties—Purchases for resale and markets refined petroleum products, mainly in the United
States and Europe. In addition, this segment includes the manufacturing and marketing of specialty products
(such as base oils and lubricants), as well as power generation operations.
Corporate and Other includes general corporate overhead, interest expense, our investment in new technologies and
various other corporate activities. Corporate assets include all cash and cash equivalents.
At December 31, 2017, Phillips 66 had approximately 14,600 employees.
30
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2017 PHILLIPS 66 ANNUAL REPORT SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment and geographic information, see Note 26—Segment Disclosures and Related Information, in the
Notes to Consolidated Financial Statements, which is incorporated herein by reference.
MIDSTREAM
The Midstream segment consists of three business lines:
• Transportation—Transports crude oil and other feedstocks to our refineries and other locations, delivers refined
products to market, and provides terminaling and storage services for crude oil and petroleum products.
• NGL and Other—Transports, stores, fractionates and markets NGL in the United States, exports LPG and
provides other fee-based processing services.
• DCP Midstream—Gathers, processes, transports and markets natural gas and transports, fractionates and markets
NGL.
The Beaumont Terminal in Nederland, Texas, is the largest terminal in the Phillips 66 portfolio. During 2017, we
continued to invest in the terminal by adding 0.9 million barrels of crude storage capacity and 1.3 million barrels of
products storage. At December 31, 2017, including these additions, the terminal capacity was 11.1 million barrels, of
which 7.4 million barrels was crude oil storage capacity and 3.7 million barrels was refined product storage capacity. We
have 3.5 million barrels of incremental crude storage capacity under construction that will be commissioned throughout
2018. In addition, during the fourth quarter of 2017, we completed expansion of the terminal’s export facilities from
400,000 to 600,000 barrels per day (BPD). We have also initiated a variety of other projects aimed at increasing storage
and throughput capabilities as we continue the expansion of the Beaumont terminal to 16 million barrels.
The Bakken Pipeline went into commercial service in June 2017. The pipeline is approximately 1,915 miles long with an
estimated capacity of 525,000 BPD at December 31, 2017. Phillips 66 Partners has a 25 percent interest in the Bakken
Pipeline, through its 25 percent interests in both the Dakota Access and ETCO joint ventures. Energy Transfer Partners,
L.P. (ETP) and MarEn Bakken Company LLC also have 38.25 percent and 36.75 percent interests, respectively, in the
Bakken Pipeline, with ETP serving as the operator. The Dakota Access section of the Bakken Pipeline is approximately
1,172 miles long and delivers crude oil from the Bakken/Three Forks production area in North Dakota to a storage and
terminaling hub outside of Patoka, Illinois, which includes an interconnection with the ETCO pipeline. The ETCO
pipeline section of the Bakken Pipeline is approximately 743 miles long and transports crude oil from the Midwest to
Phillips 66 and ETP storage terminals located in Nederland, Texas.
Phillips 66 Partners
In 2013, we formed Phillips 66 Partners, an MLP, to own, operate, develop and acquire primarily fee-based crude oil,
refined petroleum products and NGL pipelines and terminals, as well as other midstream assets. At December 31, 2017,
we owned a 55 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while the
public owned a 43 percent limited partner interest and 13.8 million perpetual convertible preferred units.
The Bayou Bridge Pipeline joint venture delivers crude oil from Nederland, Texas, to Lake Charles, Louisiana. At
December 31, 2017, this pipeline had capacity of approximately 480,000 BPD. Phillips 66 Partners has a 40 percent
interest in the joint venture, and ETP has a 60 percent interest and serves as the operator. The remaining section of the
pipeline, which is being constructed, will deliver crude oil from Lake Charles to St. James, Louisiana, and is expected to
be completed in the second half of 2018.
The Sacagawea Pipeline is owned by the joint venture Sacagawea Pipeline Company, LLC, in which Paradigm Pipeline
LLC holds a 99 percent interest. Phillips 66 Partners and Paradigm Energy Partners, LLC each own a 50 percent interest
in Paradigm Pipeline LLC. In August 2017, a new origin point on the Sacagawea Pipeline near New Town, North
Dakota, was established, enabling crude to flow from this origin point to the Bakken Pipeline at Johnson’s Corner, Keene
Terminal, Palermo Terminal, and North Dakota Pipeline at Stanley, North Dakota.
Phillips 66 Partners and Plains All American Pipeline, L.P. each own a 50 percent interest in the STACK Pipeline LLC
joint venture, which owns and operates a crude oil storage terminal and a common carrier pipeline that transports crude
oil from the Sooner Trend, Anadarko Basin, Canadian and Kingfisher Counties (STACK) play in northwestern Oklahoma
to Cushing, Oklahoma. During the fourth quarter of 2017, this joint venture completed an expansion project to loop the
existing pipeline and extend further into the STACK play, which increased capacity by 150,000 BPD.
Headquartered in Houston, Texas, Phillips 66 Partners’ assets and equity investments currently consist of crude oil,
refined petroleum products and NGL transportation, terminaling and storage systems, as well as crude oil and NGL
processing facilities, that are geographically dispersed throughout the United States. The majority of Phillips 66 Partners’
assets are integral to Phillips 66-operated refineries.
During 2017, Phillips 66 Partners expanded its business by acquiring from us:
• A 25 percent interest in both Dakota Access, LLC (Dakota Access) and Energy Transfer Crude Oil Company,
LLC (ETCO), which collectively own the Bakken Pipeline.
• A 100 percent interest in Merey Sweeny, L.P. (MSLP), a limited partnership that owns a delayed coker and
performs crude oil processing at our Sweeny Refinery.
This acquisition closed in October 2017. See Note 27—Phillips 66 Partners LP, in the Notes to the Consolidated
Financial Statements, for more information on this transaction.
The operations and financial results of Phillips 66 Partners are included in Midstream’s Transportation and NGL and
Other business lines, based on the nature of the activity within the partnership.
Transportation
We own or lease various assets to provide terminaling and storage of crude oil, refined products, natural gas and NGL.
These assets include pipeline systems; petroleum products, crude oil and LPG terminals; a petroleum coke handling
facility; marine vessels; railcars and trucks.
Pipelines and Terminals
At December 31, 2017, our Transportation business managed over 21,000 miles of crude oil, natural gas, NGL and
petroleum product pipeline systems in the United States, including those partially owned or operated by affiliates. We
owned or operated 40 finished product terminals, 38 storage locations, 5 LPG terminals, 19 crude oil terminals and 1
petroleum coke exporting facility.
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2017 PHILLIPS 66 ANNUAL REPORT Name
Origination/Terminus
Interest
Size
Length
(Miles)
Gross Capacity
(MBD)
NGL
Chisholm
Powder River
River Parish NGL †
Sand Hills**†
Skelly-Belvieu
Southern Hills**†
Sweeny NGL
TX Panhandle Y1/Y2
LPG
Blue Line
Brown Line †
Conway to Wichita
Medford †
Sweeny LPG Lines
Natural Gas
Rockies Express***
Kingfisher, OK/Conway, KS
Sage Creek, WY/Borger, TX
Southeast Louisiana
Permian Basin/Mont Belvieu, TX
Skellytown, TX/Mont Belvieu, TX
U.S. Midcontinent/Mont Belvieu, TX
Brazoria, TX/Sweeny, TX
Sher-Han, TX/Borger, TX
Borger, TX/East St. Louis, IL
Ponca City, OK/Wichita, KS
Conway, KS/Wichita, KS
Ponca City, OK/Medford, OK
Sweeny, TX/Mont Belvieu & Freeport,
TX
50%
100
100
33
50
33
100
100
100
100
100
100
100
4”-10”
6”-8”
4”-20”
20”
8”
20”
20”
3”-10”
8”-12”
8”, 10”
12”
4”-6”
10”-20”
202
705
510
1,190
571
941
18
299
688
76
55
42
246
West to East
East to West
† Owned by Phillips 66 Partners; Phillips 66 held a 57 percent ownership interest in Phillips 66 Partners at December 31, 2017.
* Total pipeline system is 419 miles. Phillips 66 has an ownership interest in multiple segments totaling 49 miles.
Meeker, CO/Clarington, OH
Clarington, OH/Moultrie, IL
36”-42”
24”, 42”
25
25
1,712
670
42
14
133
315
45
140
204
61
29
26
38
10
942
1.8 Bcf/d
2.6 Bcf/d
** Operated by DCP Midstream, LP; Phillips 66 Partners holds a direct one-third ownership interest in the pipeline entities.
*** Total pipeline system consists of three zones for a total of 1,712 miles. The third zone of the pipeline is bi-directional and can transport 2.6 Bcf/d of
natural gas from east-to-west.
The following table depicts our ownership interest in major pipeline systems as of December 31, 2017:
Name
Origination/Terminus
Interest
Size
Length
(Miles)
Gross Capacity
(MBD)
Crude and Feedstocks
Bakken Pipeline †
Bayou Bridge †
Clifton Ridge †
Cushing †
Eagle Ford Gathering †
Eagle Ford Gathering †
Glacier †
Line O †
Line 80 †
Line 100
Line 200
Line 300
Line 400
Louisiana Crude Gathering
North Texas Crude †
Oklahoma Mainline †
Sacagawea †
STACK PL †
Sweeny Crude
WA Line †
West Texas Gathering †
Petroleum Products
ATA Line †
Borger to Amarillo †
Borger-Denver
Cherokee East †
Cherokee North †
Cherokee South †
Cross Channel Connector †
Explorer †
Gold Line †
Harbor
Heartland*
LAX Jet Line
Los Angeles Products
Paola Products †
Pioneer
Richmond
SAAL †
SAAL †
Seminoe †
Standish †
Sweeny to Pasadena †
Torrance Products
Watson Products Line
Yellowstone
North Dakota/Nederland, TX
Nederland, TX/Lake Charles, LA
Clifton Ridge, LA/Westlake, LA
Cushing, OK/Ponca City, OK
Helena, TX
Tilden, TX/Whitsett, TX
Cut Bank, MT/Billings, MT
Cushing, OK/Borger, TX
Gaines, TX/Borger, TX
Taft, CA/Lost Hills, CA
Lost Hills, CA/Rodeo, CA
Nipomo, CA/Arroyo Grande, CA
Arroyo Grande, CA/Lost Hills, CA
Rayne, LA/Westlake, LA
Wichita Falls, TX
Wichita Falls, TX/Ponca City, OK
Keene, ND/Stanley, ND
Cashion, OK/Cushing, OK
Sweeny, TX/Freeport, TX
Odessa, TX/Borger, TX
Permian Basin
Amarillo, TX/Albuquerque, NM
Borger, TX/Amarillo, TX
McKee, TX/Denver, CO
Medford, OK/Mount Vernon, MO
Ponca City, OK/Arkansas City, KS
Ponca City, OK/Oklahoma City, OK
Pasadena, TX/Galena Park, TX
Texas Gulf Coast/Chicago, IL
Borger, TX/East St. Louis, IL
Woodbury, NJ/Linden, NJ
McPherson, KS/Des Moines, IA
Wilmington, CA/Los Angeles, CA
Torrance, CA/Los Angeles, CA
Paola, KS/Kansas City, KS
Sinclair, WY/Salt Lake City, UT
Rodeo, CA/Richmond, CA
Amarillo, TX/Abernathy, TX
Abernathy, TX/Lubbock, TX
Billings, MT/Sinclair, WY
Marland Junction, OK/Wichita, KS
Sweeny, TX/Pasadena, TX
Wilmington, CA/Torrance, CA
Wilmington, CA/Long Beach, CA
Billings, MT/Moses Lake, WA
25%
40
100
100
100
100
79
100
100
100
100
100
100
100
100
100
50
50
100
100
100
30”
30”
20”
18”
6”
6”-10”
8”-12”
10”
8”, 12”
8”, 10”, 12”
12”, 16”
8”, 10”, 12”
8”, 10”, 12”
4”-8”
2”-16”
12”
16”
8”-16”
12”, 24”, 30”
12”, 14”
4”-14”
50
100
70
100
100
100
100
22
100
33
50
50
100
100
50
100
33
54
100
100
100
100
100
46
6”, 10”
8”, 10”
6”-12”
10”, 12”
10”
8”
20”
24”, 28”
8”-16”
16”
8”, 6”
8”
6”, 12”
8”, 10”
8”, 12”
6”
6”
6”
6”-10”
18”
12”, 18”
10”, 12”
20”
6”-10”
1,915
49
10
62
6
22
865
276
237
79
228
69
147
80
224
217
95
149
56
289
757
293
93
405
287
29
90
5
1,830
681
80
49
19
22
106
562
14
102
19
342
92
120
8
9
710
525
480
260
130
20
34
126
37
28
54
93
48
40
25
28
100
175
250
265
104
115
34
76
38
55
57
46
180
660
120
171
30
50
112
96
63
26
33
30
33
72
294
161
238
66
4
34
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35
2017 PHILLIPS 66 ANNUAL REPORT
The following table depicts our ownership interest in finished product terminals as of December 31, 2017:
The following table depicts our ownership interest in crude and other terminals as of December 31, 2017:
Facility Name
Location
Albuquerque †
Amarillo †
Beaumont
Billings
Bozeman
Casper †
Colton
Denver
Des Moines
East St. Louis †
Glenpool †
Great Falls
Hartford †
Helena
Jefferson City †
Kansas City †
La Junta
Lincoln
Linden †
Los Angeles
Lubbock †
Missoula
Moses Lake
Mount Vernon †
North Salt Lake
Oklahoma City †
Pasadena †
Ponca City †
Portland
Renton
Richmond
Rock Springs
Sacramento
Sheridan †
Spokane
Tacoma
Tremley Point †
Westlake
Wichita Falls
Wichita North †
† Owned by Phillips 66 Partners; Phillips 66 held a 57 percent ownership interest in Phillips 66 Partners at December 31, 2017.
New Mexico
Texas
Texas
Montana
Montana
Montana
California
Colorado
Iowa
Illinois
Oklahoma
Montana
Illinois
Montana
Missouri
Kansas
Colorado
Nebraska
New Jersey
California
Texas
Montana
Washington
Missouri
Utah
Oklahoma
Texas
Oklahoma
Oregon
Washington
California
Wyoming
California
Wyoming
Washington
Washington
New Jersey
Louisiana
Texas
Kansas
Gross Storage
Capacity (MBbl)
244
277
3,700
88
113
365
211
310
206
2,085
588
198
1,075
178
110
1,294
101
219
429
116
179
368
186
363
738
352
3,210
51
664
228
334
125
141
86
351
307
1,593
128
303
679
Interest
100%
100
100
100
100
100
100
100
50
100
100
100
100
100
100
100
100
100
100
100
100
50
50
100
50
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
Gross Rack Capacity
(MBD)
18
29
8
16
13
7
21
43
15
78
19
12
25
10
16
66
10
21
121
75
17
29
13
46
41
48
65
23
33
20
28
19
13
15
24
17
39
16
15
19
Gross Storage
Capacity (MBbl)
Interest
Location
7,400
270
721
3,410
700
2,144
2,577
523
490
237
523
206
142
1,200
335
112
152
309
240
100%
100
50
100
100
100
100
100
50
100
100
70
100
100
100
100
100
100
100
Texas
Montana
Texas
Louisiana
Oklahoma
Texas
Texas
California
North Dakota
California
Texas
North Dakota
Louisiana
Oklahoma
California
California
Louisiana
California
Texas
Facility Name
Crude and Feedstocks
Beaumont
Billings †
Borger
Clifton Ridge †
Cushing †
Freeport
Jones Creek
Junction
Keene †
McKittrick
Odessa †
Palermo †
Pecan Grove †
Ponca City †
Santa Margarita
Santa Maria
Tepetate
Torrance
Wichita Falls †
Petroleum Coke
Lake Charles
Rail
Bayway †
Beaumont
Ferndale †
Missoula
Palermo †
Thompson Falls
Marine
Beaumont
Clifton Ridge †
Hartford †
Pecan Grove †
Portland
Richmond
Tacoma
Tremley Point †
NGL Facilities
1,000
Freeport
1,500
River Parish †
Clemens †
9,000
† Owned by Phillips 66 Partners; Phillips 66 held a 57 percent ownership interest in Phillips 66 Partners at December 31, 2017.
* Rail in thousands of barrels daily (MBD); Marine and NGL Facilities in thousands of barrels per hour.
Texas
Louisiana
Illinois
Louisiana
Oregon
California
Washington
New Jersey
New Jersey
Texas
Washington
Montana
North Dakota
Montana
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
100
100
100
100
100
100
100
100
Texas
Louisiana
Texas
N/A
N/A
N/A
N/A
N/A
N/A
100
100
100
50
70
50
100
100
100
Louisiana
N/A
50
Gross Loading
Capacity*
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
75
20
30
41
100
42
37
48
3
6
10
3
12
7
36
N/A
N/A
Rockies Express Pipeline LLC (REX)
We own a 25 percent interest in REX, which owns a natural gas pipeline system with approximately 1,712 miles of
transportation pipelines, including laterals, extending from Opal, Wyoming, and Meeker, Colorado, to Clarington, Ohio.
The REX Pipeline delivers natural gas to markets, primarily in the Midwest, from both the Rocky Mountain region and
the Appalachian Basin.
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2017 PHILLIPS 66 ANNUAL REPORT
Marine Vessels
At December 31, 2017, we had 11 international-flagged crude oil and product tankers under time charter contracts, with
capacities ranging in size from 300,000 to 1,100,000 barrels. Additionally, we had under time charter contract two Jones
Act-compliant tankers and 38 tug/barge units. These vessels are used primarily to transport feedstocks or provide product
transportation for certain of our refineries, including delivery of domestic crude oil to our Gulf Coast and East Coast
refineries.
Truck and Rail
Our truck and rail fleets support our feedstock and distribution operations. Rail movements are provided via a fleet of
more than 10,000 owned and leased railcars. Truck movements are provided through numerous third-party trucking
companies, as well as through our 100-percent-owned subsidiary, Sentinel Transportation LLC.
NGL and Other
Our NGL and Other business includes the following:
• A U.S. Gulf Coast NGL market hub comprising the Freeport LPG Export Terminal and Phillips 66 Partners’
100,000 BPD Sweeny Fractionator. These assets are supported by 9 million barrels of gross capacity at Phillips 66
Partners’ Clemens storage facility. We refer to these facilities as the “Sweeny Hub.”
• A 22.5 percent interest in Gulf Coast Fractionators, which owns an NGL fractionation plant in Mont Belvieu,
Texas. We operate the facility, and our net share of its capacity is 32,625 BPD.
During 2017, Phillips 66 Partners continued development of a new 25,000 BPD isomerization unit at our Lake Charles
Refinery to increase production of higher octane gasoline blend components. The project is expected to be completed by
the end of 2019.
DCP Midstream
Our Midstream segment includes our 50 percent equity investment in DCP Midstream, which is headquartered in Denver,
Colorado. As of December 31, 2017, DCP Midstream owned or operated 61 natural gas processing facilities, with a net
processing capacity of approximately 7.8 billion cubic feet per day (Bcf/d). DCP Midstream’s owned or operated natural
gas pipeline systems included gathering services for these facilities, as well as natural gas transmission, and totaled
approximately 63,000 miles of pipeline. DCP Midstream also owned or operated 12 NGL fractionation plants, along with
natural gas and NGL storage facilities, a propane wholesale marketing business and NGL pipeline assets.
The residual natural gas, primarily methane, which results from processing raw natural gas, is sold by DCP Midstream at
market-based prices to marketers and end users, including large industrial companies, natural gas distribution companies
and electric utilities. DCP Midstream purchases or takes custody of substantially all of its raw natural gas from
producers, principally under contractual arrangements that expose DCP Midstream to the prices of NGL, natural gas and
condensate. DCP Midstream also has fee-based arrangements with producers to provide midstream services such as
gathering and processing.
DCP Midstream markets a portion of its NGL to us and CPChem under existing contracts. The primary commitment on
certain contracts began a ratable wind-down period in December 2014 and expires in January 2019. These purchase
commitments are on an “if-produced, will-purchase” basis.
• A 12.5 percent undivided interest in a fractionation plant in Mont Belvieu, Texas. Our net share of its capacity is
30,250 BPD.
During 2017, DCP Midstream completed or advanced the following growth projects:
• A 40 percent undivided interest in a fractionation plant in Conway, Kansas. Our net share of its capacity is
43,200 BPD.
•
•
•
Phillips 66 Partners owns the River Parish NGL logistics system in southeast Louisiana, comprising approximately
500 miles of pipelines and a storage cavern connecting multiple fractionation facilities, refineries and a
petrochemical facility.
Phillips 66 Partners owns a direct one-third interest in both the DCP Sand Hills Pipeline, LLC (Sand Hills) and
DCP Southern Hills Pipeline, LLC, which own pipelines that connect Eagle Ford, Permian and Midcontinent
production to the Mont Belvieu, Texas, market.
Phillips 66 Partners, through its ownership of MSLP, owns a 125,000 BPD capacity vacuum distillation unit and a
70,000 BPD capacity delayed coker unit located at our Sweeny Refinery in Old Ocean, Texas.
The Sweeny Fractionator is located adjacent to our Sweeny Refinery in Old Ocean, Texas, and supplies purity ethane to
the petrochemical industry and LPG to domestic and global markets. Raw NGL supply to the fractionator is delivered
from nearby major pipelines, including the Sand Hills Pipeline. The fractionator is supported by significant infrastructure
including connectivity to two NGL supply pipelines, a pipeline connecting to the Mont Belvieu market center and a
multi-million-barrel salt dome storage facility with access to our LPG export terminal in Freeport, Texas.
The Freeport LPG Export Terminal leverages our fractionation, transportation and storage infrastructure to supply
petrochemical, heating and transportation markets globally. The terminal can simultaneously load two ships with
refrigerated propane and butane at a combined rate of 36,000 barrels per hour. In support of the terminal, a 100,000 BPD
unit to upgrade domestic propane for export was installed near the Sweeny Fractionator. In addition, the terminal exports
10,000 to 15,000 BPD of natural gasoline (C5+) produced at the Sweeny Fractionator.
MSLP processes long residue, which is produced from heavy sour crude oil, for a processing fee. The fuel-grade
petroleum coke and other by-products produced as a result of the processing are retained by our Sweeny Refinery.
•
•
•
•
In the first quarter of 2017, DCP Midstream announced the construction of a 200-million-cubic-feet-per-day
(MMcf/d) natural gas processing plant, the Mewbourn 3 plant, and further expansion of its Grand Parkway
gathering system. Both are located in the Denver-Julesburg (DJ) Basin and are expected to be in service in the
third quarter of 2018.
In the second quarter of 2017, DCP Midstream approved the 200 MMcf/d O'Connor 2 natural gas processing
plant in the DJ Basin. The O'Connor 2 plant and associated gathering infrastructure are expected to be in service
in 2019.
In the second quarter of 2017, DCP Midstream increased capacity in the DJ Basin by up to 40 MMcf/d by
placing additional field compression and plant bypass infrastructure in service.
In the third quarter of 2017, DCP Midstream executed definitive joint-venture agreements on its 25 percent
interest in the development of the Gulf Coast Express pipeline project (GCX project). The GCX project is
designed to transport up to 1.98 Bcf/d of natural gas. The mostly 42-inch pipeline would traverse approximately
500 miles and be placed in service in 2019, pending regulatory approvals.
• DCP Midstream is jointly developing the Cheyenne Connector pipeline with Tallgrass Energy Partners, LP
(Tallgrass) and Western Gas Partners, LP (Western Gas). Tallgrass serves as the operator, and both DCP
Midstream and Western Gas hold an option to invest in this pipeline at a later date. The Cheyenne Connector
pipeline will provide takeaway solutions with capacity of at least 600 MMcf/d for DCP Midstream's DJ Basin
assets, connecting natural gas to REX’s Cheyenne Hub, where it can then be delivered to numerous demand
markets across the country.
• DCP Midstream is currently expanding the Sand Hills Pipeline to 365,000 BPD, which is expected to be
completed in the first quarter of 2018. Further expansion to 450,000 BPD is progressing and is expected to be in
service during the second half of 2018. This expansion includes a partial looping of the pipeline and the addition
of new pump stations.
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2017 PHILLIPS 66 ANNUAL REPORT
Effective January 1, 2017, DCP Midstream and its master limited partnership (then named DCP Midstream Partners, LP,
subsequently renamed DCP Midstream, LP on January 11, 2017, and referred to herein as DCP Partners) closed a
transaction in which DCP Midstream contributed subsidiaries owning all of its operating assets and its existing debt to
DCP Partners, in exchange for approximately 31.1 million DCP Partners units. Following the transaction, we and our co-
venturer retained our 50/50 investment in DCP Midstream, DCP Midstream retained its incentive distribution rights in
DCP Partners through its ownership of the general partner of DCP Partners, and DCP Midstream held a 36 percent
limited partner interest and a 2 percent general partner interest in DCP Partners. See the “Equity Affiliates” section of
“Significant Sources of Capital” in “Management’s Discussion and Analysis of Financial Condition and Results of
Operations” for additional information on this transaction.
CHEMICALS
The Chemicals segment consists of our 50 percent equity investment in CPChem, which is headquartered in The
Woodlands, Texas. At the end of 2017, CPChem owned or had joint-venture interests in 30 global manufacturing
facilities and two U.S. research and development centers.
We structure our reporting of CPChem’s operations around two primary business segments: Olefins and Polyolefins
(O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P business segment produces and markets ethylene
and other olefin products; the ethylene produced is primarily consumed within CPChem for the production of
polyethylene, normal alpha olefins (NAO) and polyethylene pipe. The SA&S business segment manufactures and
markets aromatics and styrenics products, such as benzene, styrene, paraxylene and cyclohexane, as well as polystyrene.
SA&S also manufactures and/or markets a variety of specialty chemical products including organosulfur chemicals,
solvents, catalysts, drilling chemicals and mining chemicals.
The manufacturing of petrochemicals and plastics involves the conversion of hydrocarbon-based raw material feedstocks
into higher-value products, often through a thermal process referred to in the industry as “cracking.” For example,
ethylene can be produced from cracking the feedstocks ethane, propane, butane, natural gasoline or certain refinery
liquids, such as naphtha and gas oil. The produced ethylene has a number of uses, primarily as a raw material in the
production of plastics, such as polyethylene and polyvinyl chloride. Plastic resins, such as polyethylene, are
manufactured in a thermal/catalyst process, and the produced output is used as a further raw material for various
applications, such as packaging and plastic pipe.
CPChem and its equity affiliates have manufacturing facilities located in Belgium, China, Colombia, Qatar, Saudi Arabia,
Singapore and the United States.
The following table reflects CPChem’s petrochemicals and plastics product capacities at December 31, 2017:
O&P
Ethylene
Propylene
High-density polyethylene
Low-density polyethylene
Linear low-density polyethylene
Polypropylene
Normal alpha olefins
Polyalphaolefins
Polyethylene pipe
Total O&P
SA&S
Benzene
Cyclohexane
Paraxylene
Styrene
Polystyrene
Specialty chemicals
Total SA&S
Total O&P and SA&S
Capacities include CPChem’s share in equity affiliates and excludes CPChem’s NGL fractionation capacity.
Millions of Pounds per Year
Worldwide
U.S.
8,110
2,675
5,305
620
1,590
—
2,335
125
590
21,350
1,600
1,060
1,000
1,050
835
439
5,984
27,334
10,585
3,180
7,600
620
1,590
310
2,850
255
590
27,580
2,530
1,455
1,000
1,875
1,070
574
8,504
36,084
In 2017, CPChem continued construction of two polyethylene facilities and an ethane cracker in the U.S. Gulf Coast
region. This project leverages the development of the significant shale resources in the United States. The polyethylene
facilities successfully completed commissioning and start-up in September 2017. The two polyethylene units, each with
an annual capacity of 1.1 billion pounds, are located near CPChem’s Sweeny facility in Old Ocean, Texas. CPChem’s
Cedar Bayou facility in Baytown, Texas, is the location of the 3.3 billion-pound-per-year ethane cracker. Mechanical
completion of the ethane cracker was achieved in December 2017, and commissioning is expected to be completed in the
first quarter of 2018, with a transition to full production during the second quarter of 2018.
In February 2017, CPChem completed the sale of its K-Resin® styrene-butadiene copolymers (SBC) business, which
included the K-Resin® SBC plant in the Yeosu Petrochemical Complex in South Korea.
In April 2017, CPChem completed expansion of the polyalphaolefins capacity at its Cedar Bayou plant by 20 million
pounds per year, or 20 percent. This expansion, together with the NAO capacity added in 2015, allows CPChem to meet
the increasing demand for high-performance lubricants feedstocks.
In October 2017, CPChem completed the sale of its equity investment in Petrochemical Conversion Company, which
included nylon 6,6, nylon compounding, and polymer conversion assets.
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2017 PHILLIPS 66 ANNUAL REPORT
REFINING
Primary crude oil characteristics and sources of crude oil for our refineries are as follows:
Our Refining segment refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and
aviation fuels) at 13 refineries in the United States and Europe.
The table below depicts information for each of our U.S. and international refineries at December 31, 2017:
Thousands of Barrels Daily
Region/
Refinery
Atlantic Basin/
Europe
Bayway
Humber
MiRO*
Location
Interest
Linden, NJ
N. Lincolnshire,
United Kingdom
Karlsruhe,
Germany
100.00%
100.00
18.75
Gulf Coast
Alliance
Lake Charles
Sweeny
Central
Corridor
Wood River
Borger
Ponca City
Billings
West Coast
Ferndale
Los Angeles
San Francisco
Belle Chasse, LA
Westlake, LA
Old Ocean, TX
100.00
100.00
100.00
Roxana, IL
Borger, TX
Ponca City, OK
Billings, MT
50.00
50.00
100.00
100.00
100.00
Ferndale, WA
Carson/
Wilmington, CA
Arroyo Grande/
San Francisco, CA 100.00
100.00
Net Crude Throughput
Capacity
At
December 31
2017
Effective
January 1
Net Clean Product
Capacity**
2018 Gasolines Distillates
241
221
58
520
247
249
247
743
157
73
203
60
493
101
139
258
221
58
537
247
249
256
752
157
73
203
60
493
105
139
120
360
2,116
120
364
2,146
155
95
25
130
100
135
85
50
120
35
65
85
60
130
115
25
120
115
120
60
30
95
30
35
65
65
Clean
Product
Yield
Capability
92%
81
87
87
70
86
81
91
93
90
81
90
85
* Mineraloelraffinerie Oberrhein GmbH.
** Clean product capacities are maximum rates for each clean product category, independent of each other. They are not additive when calculating the clean
product yield capability for each refinery.
Characteristics
Heavy
Sour
Medium
Sour
Sweet
High
TAN*
United
States
Canada
Sources
South
America
Europe
Middle East
& Africa
Bayway
Humber
MiRO
Alliance
Lake Charles
Sweeny
Wood River
Borger
Ponca City
Billings
Ferndale
Los Angeles
San Francisco
* High TAN (Total Acid Number): acid content greater than or equal to 1.0 milligram of potassium hydroxide (KOH) per gram.
Atlantic Basin/Europe Region
Bayway Refinery
The Bayway Refinery is located on the New York Harbor in Linden, New Jersey. Bayway’s facilities include crude
distilling, naphtha reforming, fluid catalytic cracking, solvent deasphalting, hydrodesulfurization and alkylation units.
The complex also includes a polypropylene plant with the capacity to produce up to 775 million pounds per year. The
refinery produces a high percentage of transportation fuels, as well as petrochemical feedstocks, residual fuel oil and
home heating oil. Refined products are distributed to East Coast customers by pipeline, barge, railcar and truck.
Humber Refinery
The Humber Refinery is located on the east coast of England in North Lincolnshire, United Kingdom, approximately 180
miles north of London, United Kingdom. Humber’s facilities include crude distilling, naphtha reforming, fluid catalytic
cracking, hydrodesulfurization, thermal cracking and delayed coking units. The refinery has two coking units with
associated calcining plants, which produce high-value graphite and anode petroleum cokes. The refinery produces a high
percentage of transportation fuels. Humber is the only coking refinery in the United Kingdom, and a major producer of
specialty graphite cokes and anode coke. Approximately 70 percent of the light oils produced by the refinery are
distributed to customers in the United Kingdom by pipeline, railcar and truck, while the other products are exported to
the rest of Europe, West Africa and the United States by waterborne cargo.
MiRO Refinery
The MiRO Refinery is located on the Rhine River in Karlsruhe, Germany, approximately 95 miles south of Frankfurt,
Germany. MiRO is a joint venture in which we own an 18.75 percent interest. Facilities include crude distilling, naphtha
reforming, fluid catalytic cracking, petroleum coking and calcining, hydrodesulfurization, isomerization, ethyl tert-butyl
ether and alkylation units. MiRO produces a high percentage of transportation fuels. Other products include
petrochemical feedstocks, home heating oil, bitumen, anode-grade petroleum coke and petroleum coke. Refined
products are distributed to customers in Germany, Switzerland and Austria by truck, railcar and barge.
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Gulf Coast Region
Alliance Refinery
The Alliance Refinery is located on the Mississippi River in Belle Chasse, Louisiana, approximately 25 miles southeast
of New Orleans, Louisiana. The single-train facility includes crude distilling, naphtha reforming, fluid catalytic cracking,
alkylation, hydrodesulfurization, aromatics and delayed coking units. Alliance produces a high percentage of
transportation fuels. Other products include petrochemical feedstocks, home heating oil and anode-grade petroleum
coke. Refined products are distributed to customers in the southeastern and eastern United States through major
common-carrier pipeline systems and by barge. Refined products are exported primarily to customers in Latin America
by waterborne cargo.
Lake Charles Refinery
The Lake Charles Refinery is located in Westlake, Louisiana, approximately 150 miles east of Houston, Texas. Refinery
facilities include crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrocracking,
hydrodesulfurization and delayed coking units. Refinery facilities also include a specialty coker and calciner. The
refinery produces a high percentage of transportation fuels. Other products include off-road diesel, home heating oil,
feedstock for our Excel Paralubes joint venture in our M&S segment, specialty graphite petroleum coke and petroleum
coke. The majority of the refined products are distributed to customers in the southeastern and eastern United States by
truck, railcar, barge or major common carrier pipelines. Refined products are also exported primarily to customers in
Latin America and West Africa by waterborne cargo.
Sweeny Refinery
The Sweeny Refinery is located in Old Ocean, Texas, approximately 65 miles southwest of Houston, Texas. Refinery
facilities include crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrodesulfurization, and
aromatics units, as well as access to the on-site vacuum tower and delayed coking unit, which effective October 2017
became an asset owned by Phillips 66 Partners. The refinery produces a high percentage of transportation fuels. Other
products include petrochemical feedstocks, home heating oil and petroleum coke. The refinery receives crude oil by
pipeline and via tankers, through wholly and jointly owned terminals on the Gulf Coast, including a deepwater terminal
at Freeport, Texas. Refined products are distributed to customers throughout the Midcontinent region, southeastern and
eastern United States by pipeline, barge and railcar. Refined products are also exported primarily to customers in Latin
America by waterborne cargo.
Central Corridor Region
WRB Refining LP (WRB)
We are the operator and managing partner of WRB, a 50/50 joint venture with Cenovus Energy Inc., which consists of
the Wood River and Borger refineries.
• Wood River Refinery
The Wood River Refinery is located in Roxana, Illinois, about 15 miles northeast of St. Louis, Missouri, at the
confluence of the Mississippi and Missouri rivers. Refinery facilities include crude distilling, naphtha reforming,
fluid catalytic cracking, alkylation, hydrocracking, hydrodesulfurization and delayed coking units. The refinery
produces a high percentage of transportation fuels. Other products include petrochemical feedstocks, asphalt and
petroleum coke. Refined products are distributed to customers by pipeline, railcar, barge and truck and are shipped
to markets throughout the Midcontinent region.
• Borger Refinery
The Borger Refinery is located in Borger, Texas, in the Texas Panhandle, approximately 50 miles north of
Amarillo, Texas. Refinery facilities include crude distilling, naphtha reforming, fluid catalytic cracking,
alkylation, hydrodesulfurization, and delayed coking units, as well as an NGL fractionation facility. It produces a
high percentage of transportation fuels, as well as petroleum coke, NGL’s and solvents. Refined products are
distributed to customers via pipelines from the refinery to West Texas, New Mexico, Colorado and the
Midcontinent region.
Ponca City Refinery
The Ponca City Refinery is located in Ponca City, Oklahoma, approximately 95 miles northwest of Tulsa, Oklahoma. Its
facilities include crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrodesulfurization, and
delayed coking units. It produces a high percentage of transportation fuels and anode-grade petroleum coke. Refined
products are primarily distributed to customers by company-owned and common-carrier pipelines to markets throughout
the Midcontinent region.
Billings Refinery
The Billings Refinery is located in Billings, Montana. Its facilities include crude distilling, naphtha reforming, fluid
catalytic cracking, alkylation, hydrodesulfurization and delayed coking units. The refinery produces a high percentage of
transportation fuels and petroleum coke. Finished petroleum products from the refinery are distributed to customers by
pipeline, railcar and truck. Pipelines transport most of the refined products to markets in Montana, Wyoming, Idaho,
Utah, Colorado and Washington.
West Coast Region
Ferndale Refinery
The Ferndale Refinery is located on Puget Sound in Ferndale, Washington, approximately 20 miles south of the U.S.-
Canada border. Facilities include crude distillation, naphtha reforming, fluid catalytic cracking, alkylation and
hydrodesulfurization units. The refinery produces a high percentage of transportation fuels. Other products include
residual fuel oil, which is supplied to the northwest marine bunker fuel market. Most refined products are distributed to
customers by pipeline and barge to major markets in the northwest United States.
Los Angeles Refinery
The Los Angeles Refinery consists of two linked facilities located five miles apart in Carson and Wilmington, California,
approximately 15 miles southeast of Los Angeles. The Carson facility serves as the front end of the refinery by
processing crude oil, and the Wilmington facility serves as the back end of the refinery by upgrading the intermediate
products to finished products. The facilities include crude distillation, naphtha reforming, fluid catalytic cracking,
alkylation, hydrocracking, and delayed coking units. The refinery produces a high percentage of transportation fuels.
The refinery produces California Air Resources Board (CARB)-grade gasoline. Other products include petroleum coke.
Refined products are distributed to customers in California, Nevada and Arizona by pipeline and truck.
San Francisco Refinery
The San Francisco Refinery consists of two facilities linked by a 200-mile pipeline. The Santa Maria facility is located in
Arroyo Grande, California, 200 miles south of San Francisco, California, while the Rodeo facility is in the San Francisco
Bay Area. Semi-refined liquid products from the Santa Maria facility are shipped by pipeline to the Rodeo facility for
upgrading into finished petroleum products. Facilities include crude distillation, naphtha reforming, hydrocracking,
hydrodesulfurization and delayed coking units, as well as a calciner. The refinery produces a high percentage of
transportation fuels. It also produces CARB-grade gasoline. Other products include petroleum coke. The majority of
the refined products are distributed to customers in California by pipeline and barge. Additional refined products are also
exported to customers in Latin America by waterborne cargo.
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2017 PHILLIPS 66 ANNUAL REPORT
MARKETING AND SPECIALTIES
Our M&S segment purchases for resale and markets refined petroleum products (such as gasolines, distillates and
aviation fuels), mainly in the United States and Europe. In addition, this segment includes the manufacturing and
marketing of specialty products (such as base oils and lubricants), as well as power generation operations.
Marketing
Marketing—United States
In the United States, as of December 31, 2017, we marketed gasoline, diesel and aviation fuel through approximately
7,550 independently owned outlets in 48 states. These sites utilize the Phillips 66, Conoco or 76 brands.
At December 31, 2017, our wholesale operations utilized a network of marketers operating approximately 5,700 outlets.
We place a strong emphasis on the wholesale channel of trade because of its lower capital requirements. In addition, we
held brand-licensing agreements covering approximately 1,050 sites. Our refined products are marketed on both a
branded and unbranded basis. A high percentage of our branded marketing sales are made in the Midcontinent, Rockies
and West Coast regions, where our wholesale marketing operations provide efficient off-take from our refineries. We
continue to utilize consignment fuel arrangements with several marketers whereby we own the fuel inventory and pay the
marketers a fixed monthly fee.
In the Gulf Coast and East Coast regions, most sales are conducted via unbranded sales which do not require a highly
integrated marketing and distribution infrastructure to secure product placement for refinery pull through. We are
expanding our export capability at our U.S. coastal refineries to meet growing international demand and increase
flexibility to provide product to the highest-value markets.
In addition to automotive gasoline and diesel, we produce and market jet fuel and aviation gasoline. At December 31,
2017, aviation gasoline and jet fuel were sold through dealers and independent marketers at approximately 800
Phillips 66-branded locations in the United States.
Marketing—International
We have marketing operations in four European countries. Our European marketing strategy is to sell primarily through
owned, leased or joint-venture retail sites using a low-cost, high-volume approach. We use the JET brand name to
market retail and wholesale products in Austria, Germany and the United Kingdom. In addition, a joint venture in which
we have an equity interest markets products in Switzerland under the COOP brand name.
We also market aviation fuels, LPG, heating oils, transportation fuels, marine bunker fuels, bitumen and fuel coke
specialty products to commercial customers and into the bulk or spot markets in the above countries.
At December 31, 2017, we had 1,324 marketing outlets in our European operations, of which 993 were company owned
and 331 were dealer owned. In addition, through our COOP joint-venture operations in Switzerland, we have interests in
306 additional sites.
Specialties
We manufacture and sell a variety of specialty products, including petroleum coke products, waxes, solvents and
polypropylene. Certain manufacturing operations are included in the Refining segment, while the marketing function for
these products is included in the Specialties business.
Premium Coke, Polypropylene & Solvents
We market high-quality graphite and anode-grade petroleum cokes in the United States, Europe and Asia for use in a
variety of industries that include steel, aluminum, titanium dioxide and battery manufacturing. We also market
polypropylene in North America under the COPYLENE brand name for use in consumer products, and market specialty
solvents that include pentane, iso-pentane, hexane, heptane and odorless mineral spirits for use in the petrochemical,
agriculture and consumer markets.
Excel Paralubes
We own a 50 percent interest in Excel Paralubes, a joint venture which owns a hydrocracked lubricant base oil
manufacturing plant located adjacent to the Lake Charles Refinery. The facility has a nameplate capacity to produce
22,200 BPD of high-quality, clear hydrocracked base oils. The facility’s feedstock is sourced primarily from our Lake
Charles Refinery.
Lubricants
We manufacture and sell automotive, commercial, industrial and specialty lubricants which are marketed worldwide
under the Phillips 66, Kendall and Red Line brands, as well as other private label brands. We also market Group II Pure
Performance base oils globally, as well as import and market Group III Ultra-S base oils through an agreement with
South Korea’s S-Oil corporation.
Other
Power Generation
We own a cogeneration power plant located adjacent to the Sweeny Refinery. The plant generates electricity and
provides process steam to the refinery, as well as merchant power into the Texas market. The plant has a net electrical
output of 440 megawatts and is capable of generating up to 3.6 million pounds per hour of process steam.
TECHNOLOGY DEVELOPMENT
Our Technology organization conducts applied and fundamental research in three areas: 1) support for our current
business, 2) new environmental solutions to address governmental regulations and 3) future growth. Technology
programs include evaluating advantaged crudes; and modeling to reduce energy consumption, increase product yield and
increase reliability. Our sustainability group is focusing efforts on organic photovoltaic polymers, solid oxide fuel cells,
atmospheric modeling and air chemistry, water use and reuse and renewable fuels. Additionally, we monitor emerging
technologies such as electric vehicles and impacts of the digital space on energy consumption, and perform research and
monitoring of developments in battery technology.
COMPETITION
The Midstream segment, through our equity investment in DCP Midstream and our other operations, competes with
numerous integrated petroleum companies, as well as natural gas transmission and distribution companies, to deliver
components of natural gas to end users in commodity natural gas markets. DCP Midstream is one of the leading natural
gas gatherers and processors in the United States based on wellhead volumes, and one of the largest U.S. producers and
marketers of NGL, based on published industry sources. Principal methods of competing include economically securing
the right to purchase raw natural gas for gathering systems, managing the pressure of those systems, operating efficient
NGL processing plants and securing markets for the products produced.
In the Chemicals segment, CPChem is ranked among the top 10 producers of many of its major product lines according
to published industry sources, based on average 2017 production capacity. Petroleum products, petrochemicals and
plastics are typically delivered into the worldwide commodity markets. Our Refining and M&S segments compete
primarily in the United States and Europe. We are one of the largest refiners of petroleum products in the United States
based on published industry sources. Elements of competition for both our Chemicals and Refining segments include
product improvement, new product development, low-cost structures, and efficient manufacturing and distribution
systems. In the marketing portion of the business, competitive factors include product properties and processibility,
reliability of supply, customer service, price and credit terms, advertising and sales promotion, and development of
customer loyalty to branded products.
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2017 PHILLIPS 66 ANNUAL REPORT GENERAL
Item 1A. RISK FACTORS
At December 31, 2017, we held a total of 356 active patents in 18 countries worldwide, including 275 active U.S.
patents. The overall profitability of any business segment is not dependent on any single patent, trademark, license or
franchise.
You should carefully consider the following risk factors in addition to the other information included in this Annual
Report on Form 10-K. Each of these risk factors could adversely affect our business, operating results and financial
condition, as well as affect the value of an investment in our common stock.
Company-sponsored research and development activities charged against earnings were $60 million in both 2017 and
2016 and $65 million in 2015.
Our operating results and future rate of growth are exposed to the effects of changing commodity prices and refining,
marketing and petrochemical margins.
In support of our goal to attain zero incidents, we have implemented a comprehensive Health, Safety and Environmental
(HSE) management system to support consistent management of HSE risks across our enterprise. The management
system is designed to ensure that personal safety, process safety, and environmental impact risks are identified and
mitigation steps are taken to reduce the risk. The management system requires periodic audits to ensure compliance with
government regulations, as well as our internal requirements. Our commitment to continuous improvement is reflected
in annual goal setting and performance measurement.
See the environmental information contained in “Management’s Discussion and Analysis of Financial Condition and
Results of Operations—Capital Resources and Liquidity—Contingencies” under the captions “Environmental” and
“Climate Change.” It includes information on expensed and capitalized environmental costs for 2017 and those expected
for 2018 and 2019.
Website Access to SEC Reports
Our Internet website address is http://www.phillips66.com. Information contained on our Internet website is not part of
this Annual Report on Form 10-K.
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any
amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934
are available on our website, free of charge, as soon as reasonably practicable after such reports are filed with, or
furnished to, the U.S. Securities and Exchange Commission (SEC). Alternatively, you may access these reports at the
SEC’s website at http://www.sec.gov.
Our revenues, operating results and future rate of growth are highly dependent on a number of factors, including fixed
and variable expenses (including the cost of crude oil, NGL, and other refining and petrochemical feedstocks) and the
margin we can derive from selling refined and Chemicals segment products. The prices of feedstocks and our products
fluctuate substantially. These prices depend on numerous factors beyond our control, including the global supply and
demand for feedstocks and our products, which are subject to, among other things:
• Changes in the global economy and the level of foreign and domestic production of crude oil, natural gas and NGL
and refined, petrochemical and plastics products.
• Availability of feedstocks and refined products and the infrastructure to transport them.
• Local factors, including market conditions, the level of operations of other facilities in our markets, and the volume
of products imported and exported.
• Threatened or actual terrorist incidents, acts of war and other global political conditions.
• Government regulations.
• Weather conditions, hurricanes or other natural disasters.
The price of crude oil influences prices for refined products. We do not produce crude oil and must purchase all of the
crude oil we process. Many crude oils available on the world market will not meet the quality restrictions for use in our
refineries. Others are not economical to use due to high transportation costs or for other reasons. The prices for crude oil
and refined products can fluctuate differently based on global, regional and local market conditions. In addition, the
timing of the relative movement of the prices (both among different classes of refined products and among various global
markets for similar refined products), as well as the overall change in refined product prices, can reduce refining margins
and could have a significant impact on our refining, wholesale marketing and retail operations, revenues, operating
income and cash flows. Also, crude oil supply contracts generally have market-responsive pricing provisions. We
normally purchase our refinery feedstocks weeks before manufacturing and selling the refined products. Changes in
prices that occur between when we purchase feedstocks and when we sell the refined products produced from these
feedstocks could have a significant effect on our financial results. We also purchase refined products produced by others
for sale to our customers. Price changes that occur between when we purchase and sell these refined products also could
have a material adverse effect on our business, financial condition and results of operations.
The price of feedstocks also influences prices for petrochemical and plastics products. Although our Chemicals segment
transports and fractionates feedstocks to meet a portion of their demand and has certain long-term feedstock supply
contracts with others, it is still subject to volatile feedstock prices. In addition, the petrochemicals industry is both
cyclical and volatile. Cyclicality occurs when periods of tight supply, resulting in increased prices and profit margins, are
followed by periods of capacity expansion, resulting in oversupply and declining prices and profit margins. Volatility
occurs as a result of changes in supply and demand for products, changes in energy prices, and changes in various other
economic conditions around the world.
Uncertainty and illiquidity in credit and capital markets can impair our ability to obtain credit and financing on
acceptable terms and can adversely affect the financial strength of our business partners.
Our ability to obtain credit and capital depends in large measure on the state of the credit and capital markets, which is
beyond our control. Our ability to access credit and capital markets may be restricted at a time when we would like, or
need, access to those markets, which could constrain our flexibility to react to changing economic and business
conditions. In addition, the cost and availability of debt and equity financing may be adversely impacted by unstable or
illiquid market conditions. Protracted uncertainty and illiquidity in these markets also could have an adverse impact on
our lenders, commodity hedging counterparties, or our customers, preventing them from meeting their obligations to us.
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2017 PHILLIPS 66 ANNUAL REPORT
From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially
and adversely affected if we are unable to obtain necessary funds from financing activities. From time to time, we may
need to supplement cash generated from operations with proceeds from financing activities. Uncertainty and illiquidity
in financial markets may materially impact the ability of the participating financial institutions to fund their commitments
to us under our liquidity facilities. Accordingly, we may not be able to obtain the full amount of the funds available
under our liquidity facilities to satisfy our cash requirements, and our failure to do so could have a material adverse effect
on our operations and financial position.
Deterioration in our credit profile could increase our costs of borrowing money and limit our access to the capital
markets and commercial credit, and could trigger co-venturer rights under joint-venture arrangements.
Our or Phillips 66 Partners’ credit ratings could be lowered or withdrawn entirely by a rating agency if, in its judgment,
the circumstances warrant. If a rating agency were to downgrade our rating below investment grade, our or Phillips 66
Partners’ borrowing costs would increase, and our funding sources could decrease. In addition, a failure by us to
maintain an investment grade rating could affect our business relationships with suppliers and operating partners. For
example, our agreement with Chevron regarding CPChem permits Chevron to buy our 50 percent interest in CPChem for
fair market value if we experience a change in control or if both Standard & Poor’s and Moody’s lower our credit ratings
below investment grade and the credit rating from either rating agency remains below investment grade for 365 days
thereafter, with fair market value determined by agreement or by nationally recognized investment banks. As a result of
these factors, a downgrade of credit ratings could have a materially adverse impact on our future operations and financial
position.
We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with
existing and future environmental laws and regulations. Likewise, future environmental laws and regulations may
impact or limit our current business plans and reduce demand for our products.
Our business is subject to numerous laws and regulations relating to the protection of the environment. These laws and
regulations continue to increase in both number and complexity and affect our operations with respect to, among other
things:
• The discharge of pollutants into the environment.
• Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury emissions, and greenhouse gas
emissions as they are, or may become, regulated).
• The quantity of renewable fuels that must be blended into motor fuels.
• The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous and
nonhazardous wastes.
• The dismantlement and abandonment of our facilities and restoration of our properties at the end of their useful
lives.
We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures
as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in
the prices of our products and services, our business, financial condition, results of operations and cash flows in future
periods could be materially adversely affected.
The U.S. Environmental Protection Agency (EPA) has implemented a Renewable Fuel Standard (RFS) pursuant to the
Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007. The RFS program sets annual quotas
for the quantity of renewable fuels (such as ethanol) that must be blended into motor fuels consumed in the United States.
To provide certain flexibility in compliance options available to the industry, a Renewable Identification Number (RIN)
is assigned to each gallon of renewable fuel produced in, or imported into, the United States. As a producer of
petroleum-based motor fuels, we are obligated to blend renewable fuels into the products we produce at a rate that is at
least commensurate to the EPA’s quota and, to the extent we do not, we must purchase RINs in the open market to satisfy
our obligation under the RFS program. To the extent the EPA mandates a blending quantity of renewable fuel that
exceeds the amount that is commercially feasible to blend into motor fuel (a situation commonly referred to as “the blend
wall”), our operations could be materially adversely impacted, up to and including a reduction in produced motor fuel.
The adoption of climate change legislation or regulation could result in increased operating costs and reduced
demand for the refined products we produce.
The U.S. government, including the EPA, as well as several state and international governments, have either considered
or adopted legislation or regulations in an effort to reduce greenhouse gas (GHG) emissions. These proposed or
promulgated laws apply or could apply in states and/or countries where we have interests or may have interests in the
future. In addition, various groups suggest that additional laws may be needed in an effort to address climate change, as
illustrated by the Paris Agreement negotiated at the 2015 United Nations Conference on Climate Change, referred to as
COP 21, which entered into force on November 4, 2016. We cannot predict the extent to which any such legislation or
regulation will be enacted and, if so, what its provisions would be. To the extent we incur additional costs required to
comply with the adoption of new laws and regulations that are not ultimately reflected in the prices of our products and
services, our business, financial condition, results of operations and cash flows in future periods could be materially
adversely affected. In addition, demand for the refined products we produce could be adversely affected.
Climate change may adversely affect our facilities and our ongoing operations.
The potential physical effects of climate change on our operations are highly uncertain and depend upon the unique
geographic and environmental factors present. Examples of such effects include rising sea levels at our coastal facilities,
changing storm patterns and intensities, and changing temperature levels. As many of our facilities are located near
coastal areas, rising sea levels may disrupt our ability to operate those facilities or transport crude oil and refined
petroleum products. Extended periods of such disruption could have an adverse effect on our results of operation. We
could also incur substantial costs to prevent or repair damage to these facilities.
Domestic and worldwide political and economic developments could affect our operations and materially reduce our
profitability and cash flows.
Actions of the U.S., state, local and international governments through tax and other legislation or regulation, executive
order, permit or other review of infrastructure or facility development, and commercial restrictions could delay projects,
increase costs, limit development, or otherwise reduce our operating profitability both in the United States and abroad.
Any such actions may affect many aspects of our operations, including requiring permits or other approvals that may
impose unforeseen or unduly burdensome conditions or potentially cause delays in our operations; further limiting or
prohibiting construction or other activities in environmentally sensitive or other areas; requiring increased capital costs to
construct, maintain or upgrade equipment or facilities; or restricting the locations where we may construct facilities or
requiring the relocation of facilities. In addition, the U.S. government can prevent or restrict us from doing business in
foreign countries. These restrictions and those of foreign governments could limit our ability to operate in, or gain access
to various countries, as well as limit our ability to obtain the optimum slate of crude oil and other refinery feedstocks.
Our foreign operations and those of our joint ventures are further subject to risks of loss of revenue, equipment and
property as a result of expropriation, acts of terrorism, war, civil unrest and other political risks; unilateral or forced
renegotiation, modification or nullification of existing contracts with governmental entities; and difficulties enforcing
rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over
international operations. Our foreign operations and those of our joint ventures are also subject to fluctuations in
currency exchange rates. Actions by both the United States and host governments may affect our operations significantly
in the future.
Renewable fuels, alternative energy mandates and energy conservation efforts could reduce demand for refined products.
Tax incentives and other subsidies can make renewable fuels and alternative energy more competitive with refined
products than they otherwise might be, which may reduce refined product margins and hinder the ability of refined
products to compete with renewable fuels.
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.
Our basis for approving a large-scale capital project is the expectation that it will deliver an acceptable level of return on
the capital invested. We base these forecasted project economics on our best estimate of future market conditions. Most
large-scale projects take several years to complete. During this multi-year period, market conditions can change from
those we forecast, and these changes could be significant. Accordingly, we may not be able to realize our expected
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returns from a large investment in a capital project, and this could negatively impact our results of operations, cash flows
and our return on capital employed.
Increased regulation of hydraulic fracturing could result in reductions or delays in U.S. production of crude oil and
natural gas, which could adversely impact our results of operations.
Our investments in joint ventures decrease our ability to manage risk.
We conduct some of our operations, including parts of our Midstream, Refining and M&S segments, and our entire
Chemicals segment, through joint ventures in which we share control with our joint-venture participants. Our joint-
venture participants may have economic, business or legal interests or goals that are inconsistent with ours or those of the
joint venture, or our joint-venture participants may be unable to meet their economic or other obligations, and we may be
required to fulfill those obligations alone. Failure by us, or an entity in which we have a joint-venture interest, to
adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the
financial condition or results of operations of our joint ventures and, in turn, our business and operations.
Activities in our Chemicals and Midstream segments involve numerous risks that may result in accidents that could
affect the ability of our equity affiliates to make distributions to us.
There are a variety of hazards and operating risks inherent in the manufacturing of petrochemicals and the gathering,
processing, transmission, storage, and distribution of natural gas and NGL, such as spills, leaks, explosions and
mechanical problems that could cause substantial financial losses. In addition, these risks could result in significant
injury, loss of human life, damage to property, environmental pollution and impairment of operations, any of which could
result in substantial losses. For assets located near populated areas, including residential areas, commercial business
centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater.
Should any of these risks materialize, it could have a material adverse effect on the business and financial condition of
our equity affiliates in these segments and negatively impact their ability to make future distributions to us.
Our operations present hazards and risks, which may not be fully covered by insurance, if insured. If a significant
accident or event occurs for which we are not adequately insured, our operations and financial results could be
adversely affected.
The scope and nature of our operations present a variety of operational hazards and risks, including explosions, fires,
toxic emissions, maritime hazards and natural catastrophes, that must be managed through continual oversight and
control. For example, the operation of refineries, power plants, fractionators, pipelines, terminals and vessels is
inherently subject to the risks of spills, discharges or other inadvertent releases of petroleum or hazardous substances. If
any of these events had previously occurred or occurs in the future in connection with any of our refineries, pipelines or
refined products terminals, or in connection with any facilities that receive our wastes or by-products for treatment or
disposal, other than events for which we are indemnified, we could be liable for all costs and penalties associated with
their remediation under federal, state, local and international environmental laws or common law, and could be liable for
property damage to third parties caused by contamination from releases and spills. These and other risks are present
throughout our operations. As protection against these hazards and risks, we maintain insurance against many, but not
all, potential losses or liabilities arising from such operating risks. As such, our insurance coverage may not be sufficient
to fully cover us against potential losses arising from such risks. Uninsured losses and liabilities arising from operating
risks 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.
We are subject to interruptions of supply and increased costs as a result of our reliance on third-party transportation
of crude oil, NGL and refined products.
We often utilize the services of third parties to transport crude oil, NGL and refined products to and from our facilities.
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 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 a pipeline or vessel to transport crude oil, NGL or refined products to or from one or more of
our refineries or other facilities could have a material adverse effect on our business, financial condition, results of
operations and cash flows.
An increasing percentage of crude oil supplied to our refineries and the crude oil and gas production of our Midstream
segment’s customers is being produced from unconventional oil shale reservoirs. These reservoirs require hydraulic
fracturing completion processes to release the hydrocarbons from the rock so they can flow through casing to the surface.
Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate
hydrocarbon production. The EPA, as well as several state agencies, have commenced studies and/or convened hearings
regarding the potential environmental impacts of hydraulic fracturing activities. At the same time, certain environmental
groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic
fracturing process, and legislation has been proposed to provide for such regulation. In addition, some communities have
adopted measures to ban hydraulic fracturing in their communities. We cannot predict whether any such legislation will
ever be enacted and, if so, what its provisions would be. Any additional levels of regulation and permits required with
the adoption of new laws and regulations at the federal or state level could result in our having to rely on higher priced
crude oil for our refineries. This could lead to delays, increased operating costs and process prohibitions that could reduce
the volumes of natural gas that move through DCP Midstream’s gathering systems and could reduce supplies and
increase costs of NGL feedstocks to CPChem ethylene facilities. This could materially adversely affect our results of
operations and the ability of DCP Midstream and CPChem to make cash distributions to us.
DCP Midstream’s success depends on its ability to obtain new sources of natural gas and NGL. Any decrease in the
volumes of natural gas DCP Midstream gathers could adversely affect its business and operating results.
DCP Midstream’s gathering and transportation pipeline systems are connected to or dependent on the level of production
from natural gas wells, which naturally declines over time. As a result, its cash flows associated with these wells will
also decline over time. In order to maintain or increase throughput levels on its gathering and transportation pipeline
systems and NGL pipelines and the asset utilization rates at its natural gas processing plants, DCP Midstream must
continually obtain new supplies. The primary factors affecting DCP Midstream’s ability to obtain new supplies of natural
gas and NGL, and to attract new customers to its assets, include the level of successful drilling activity near these assets,
prices of, and the demand for, natural gas and crude oil, producers’ desire and ability to obtain necessary permits in an
efficient manner, natural gas field characteristics and production performance, surface access and infrastructure issues,
and its ability to compete for volumes from successful new wells. If DCP Midstream is not able to obtain new supplies
of natural gas to replace the natural decline in volumes from existing wells or because of competition, throughput on its
pipelines and the utilization rates of its treating and processing facilities would decline. This could have a material
adverse effect on its business, results of operations, financial position and cash flows, and its ability to make cash
distributions to us.
Competitors that produce their own supply of feedstocks, have more extensive retail outlets, or have greater financial
resources may have a competitive advantage.
The refining and marketing industry is highly competitive with respect to both feedstock supply and refined product
markets. We compete with many companies for available supplies of crude oil and other feedstocks and for outlets for
our refined products. We do not produce any of our crude oil feedstocks. Some of our competitors, however, obtain a
portion of their feedstocks from their own production and some have more extensive retail outlets than we have.
Competitors that have their own production or extensive retail outlets (and greater brand-name recognition) are at times
able to offset losses from refining operations with profits from producing or retailing operations, and may be better
positioned to withstand periods of depressed refining margins or feedstock shortages.
Some of our competitors also have materially greater financial and other resources than we have. Such competitors have
a greater ability to bear the economic risks inherent in all phases of our business. In addition, we compete with other
industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and
individual customers.
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2017 PHILLIPS 66 ANNUAL REPORT We may incur losses as a result of our forward-contract activities and derivative transactions.
We currently use commodity derivative instruments, and we expect to use them in the future. If the instruments we
utilize to hedge our exposure to various types of risk are not effective, we may incur losses. Derivative transactions
involve the risk that counterparties may be unable to satisfy their obligations to us. The risk of counterparty default is
heightened in a poor economic environment.
One of our subsidiaries acts as the general partner of a publicly traded master limited partnership, Phillips 66
Partners, which may involve a greater exposure to legal liability than our historic business operations.
One of our subsidiaries acts as the general partner of Phillips 66 Partners, a publicly traded master limited partnership.
Our control of the general partner of Phillips 66 Partners may increase the possibility that we could be subject to claims
of breach of fiduciary duties, including claims of conflicts of interest, related to Phillips 66 Partners. Any liability
resulting from such claims could have a material adverse effect on our future business, financial condition, results of
operations and cash flows.
A significant interruption in one or more of our facilities could adversely affect our business.
Our operations could be subject to significant interruption if one or more of our facilities were to experience a major
accident, mechanical failure, or power outage, encounter work stoppages relating to organized labor issues, be damaged
by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down.
If any facility were to experience an interruption in operations, earnings from the facility could be materially adversely
affected (to the extent not recoverable through insurance, if insured) because of lost production and repair costs. A
significant interruption in one or more of our facilities could also lead to increased volatility in prices for feedstocks and
refined products, and could increase instability in the financial and insurance markets, making it more difficult for us to
access capital and to obtain insurance coverage that we consider adequate.
Our performance depends on the uninterrupted operation of our facilities, which are becoming increasingly
dependent on our information technology systems.
Our performance depends on the efficient and uninterrupted operation of the manufacturing equipment in our production
facilities. The inability to operate one or more of our facilities due to a natural disaster; power outage; labor dispute; or
failure of one or more of our information technology, telecommunications, or other systems could significantly impair
our ability to manufacture our products. Our manufacturing equipment is becoming increasingly dependent on our
information technology systems. A disruption in our information technology systems due to a catastrophic event or
security breach could interrupt or damage our operations.
Security breaches and other disruptions could compromise our information and expose us to liability, which would
cause our business and reputation to suffer.
In the ordinary course of our business, we collect sensitive data, including personally identifiable information of our
customers using credit cards at our branded retail outlets. Despite our security measures, our information technology and
infrastructure, or information technology and infrastructure of our third-party service providers (e.g., cloud-based service
providers), may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions.
Although we have experienced occasional, actual or attempted breaches of our cybersecurity, none of these breaches has
had a material effect on our business, operations or reputation (or compromised any customer data). Any such breaches
could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen.
Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws
that protect the privacy of customer information, disrupt the services we provide to customers, and damage our
reputation, any of which could adversely affect our business.
The level of returns on pension and postretirement plan assets and the actuarial assumptions used for valuation
purposes could affect our earnings and cash flows in future periods.
Assumptions used in determining projected benefit obligations and the expected return on plan assets for our pension
plan and other postretirement benefit plans are evaluated by us based on a variety of independent sources of market
information and in consultation with outside actuaries. If we determine that changes are warranted in the assumptions
used, such as the discount rate, expected long-term rate of return, or health care cost trend rate, our future pension and
postretirement benefit expenses and funding requirements could increase. In addition, several factors could cause actual
results to differ significantly from the actuarial assumptions that we use. Funding obligations are determined based on
the value of assets and liabilities on a specific date as required under relevant regulations. Future pension funding
requirements, and the timing of funding payments, could be affected by legislation enacted by governmental authorities.
In connection with the Separation, ConocoPhillips has indemnified us for certain liabilities and we have agreed to
indemnify ConocoPhillips for certain liabilities. If we are required to act on these indemnities to ConocoPhillips, we
may need to use cash to meet those obligations and our financial results could be negatively impacted. The
ConocoPhillips indemnity may not be sufficient to insure us against the full amount of liabilities for which it has been
allocated responsibility, and ConocoPhillips may not be able to satisfy its indemnification obligations in the future.
Pursuant to the Indemnification and Release Agreement and certain other agreements with ConocoPhillips entered into in
connection with the Separation, ConocoPhillips agreed to indemnify us for certain liabilities, and we agreed to indemnify
ConocoPhillips for certain liabilities. Indemnities that we may be required to provide ConocoPhillips are not subject to
any cap, may be significant and could negatively impact our business, particularly indemnities relating to our actions that
could impact the tax-free nature of the distribution of Phillips 66 stock. Third parties could also seek to hold us
responsible for any of the liabilities that ConocoPhillips has agreed to retain. Further, the indemnity from ConocoPhillips
may not be sufficient to protect us against the full amount of such liabilities, and ConocoPhillips may not be able to fully
satisfy its indemnification obligations. Moreover, even if we ultimately succeed in recovering from ConocoPhillips any
amounts for which we are held liable, we may be temporarily required to bear these losses ourselves. Each of these risks
could negatively affect our business, results of operations and financial condition.
We are subject to continuing contingent liabilities of ConocoPhillips following the Separation.
Notwithstanding the Separation, there are several significant areas where the liabilities of ConocoPhillips may become
our obligations. For example, under the Internal Revenue Code and the related rules and regulations, each corporation
that was a member of the ConocoPhillips consolidated U.S. federal income tax reporting group during any taxable period
or portion of any taxable period ending on or before the effective time of the Separation is jointly and severally liable for
the U.S. federal income tax liability of the entire ConocoPhillips consolidated tax reporting group for that taxable period.
In connection with the Separation, we entered into the Tax Sharing Agreement with ConocoPhillips that allocates the
responsibility for prior period taxes of the ConocoPhillips consolidated tax reporting group between us and
ConocoPhillips. ConocoPhillips may be unable to pay any prior period taxes for which it is responsible, and 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.
If the distribution in connection with the Separation, together with certain related transactions, does not qualify as a
transaction that is generally tax-free for U.S. federal income tax purposes, our stockholders and ConocoPhillips could
be subject to significant tax liability and, in certain circumstances, we could be required to indemnify ConocoPhillips
for material taxes pursuant to indemnification obligations under the Tax Sharing Agreement.
ConocoPhillips received a private letter ruling from the Internal Revenue Service (IRS) substantially to the effect that,
among other things, the distribution, together with certain related transactions, qualified as a transaction that is generally
tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. The private letter ruling
and the tax opinion that ConocoPhillips received relied on certain representations, assumptions and undertakings,
including those relating to the past and future conduct of our business, and neither the private letter ruling nor the opinion
would be valid if such representations, assumptions and undertakings were incorrect. Moreover, the private letter ruling
does not address all the issues that are relevant to determining whether the distribution qualified for tax-free treatment.
Notwithstanding the private letter ruling and the tax opinion, the IRS could determine the distribution should be treated
as a taxable transaction for U.S. federal income tax purposes if it determines any of the representations, assumptions or
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2017 PHILLIPS 66 ANNUAL REPORT In October 2016, after receiving a Notice of Intent to Sue from the Sierra Club, we entered into a voluntary settlement
with the Illinois Environmental Protection Agency for alleged violations of wastewater requirements at the Wood River
Refinery. The settlement involves certain capital projects and payment of $125,000. After the settlement was filed with
the Court for final approval, the Sierra Club sought and was granted approval to intervene in the case. The settlement
and a first modification have been entered by the Court, but the Sierra Club still seeks to reopen and challenge the
settlement.
In September 2014, the EPA issued an NOV alleging a violation of hazardous air pollution regulations at the Wood River
Refinery during 2014. We are working with the EPA to resolve this NOV.
In July 2014, Phillips 66 received an NOV from the EPA alleging various flaring-related violations between 2009 and
2013 at the Wood River Refinery. We are working with the EPA to resolve this NOV.
In May 2012, the Illinois Attorney General’s office filed and notified us of a complaint with respect to operations at the
Wood River Refinery alleging violations of the Illinois groundwater standards and a third-party’s hazardous waste permit.
The complaint seeks as relief remediation of area groundwater; compliance with the hazardous waste permit; enhanced
pipeline and tank integrity measures; additional spill reporting; and fines and penalties exceeding $100,000. We are
working with the Illinois Environmental Protection Agency and Attorney General’s office to resolve these allegations.
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
undertakings that were included in the request for the private letter ruling are false or have been violated or if it disagrees
with the conclusions in the opinion that are not covered by the IRS ruling.
If the IRS were to determine that the distribution failed to qualify for tax-free treatment, in general, ConocoPhillips
would be subject to tax as if it had sold the Phillips 66 common stock in a taxable sale for its fair market value, and
ConocoPhillips stockholders who received shares of Phillips 66 common stock in the distribution would be subject to tax
as if they had received a taxable distribution equal to the fair market value of such shares.
Under the Tax Sharing Agreement, we would generally be required to indemnify ConocoPhillips against any tax resulting
from the distribution to the extent that such tax resulted from (i) any of our representations or undertakings being
incorrect or violated, or (ii) other actions or failures to act by us. Our indemnification obligations to ConocoPhillips and
its subsidiaries, officers and directors are not limited by any maximum amount. If we are required to indemnify
ConocoPhillips or such other persons under the circumstances set forth in the Tax Sharing Agreement, we may be subject
to substantial liabilities.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 3. LEGAL PROCEEDINGS
The following is a description of reportable legal proceedings, including those involving governmental authorities under
federal, state and local laws regulating the discharge of materials into the environment. While it is not possible to
accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were decided
adversely to Phillips 66, we expect there would be no material effect on our consolidated financial position.
Nevertheless, such proceedings are reported pursuant to Securities and Exchange Commission (SEC) regulations.
Our U.S. refineries are implementing two separate consent decrees, regarding alleged violations of the Federal Clean Air
Act, with the U.S. Environmental Protection Agency (EPA), five states and one local air pollution agency. Some of the
requirements and limitations contained in the decrees provide for stipulated penalties for violations. Stipulated penalties
under the decrees are not automatic, but must be requested by one of the agency signatories. As part of periodic reports
under the decrees or other reports required by permits or regulations, we occasionally report matters that could be subject
to a request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth
in SEC rules is made pursuant to these decrees based on a given reported exceedance, we will separately report that
matter and the amount of the proposed penalty.
New Matters
There are no new matters to report.
Matters Previously Reported (unresolved or resolved since the quarterly report on Form 10-Q for the quarterly period
ended September 30, 2017)
The California Air Resources Board issued four separate Notices of Violation (NOV) to the company alleging violations
of fuel specification requirements at our Los Angeles Refinery and Torrance Tank Farm. This matter was resolved with a
payment of $190,000 in December 2017.
On June 27, 2017, Phillips 66 reached settlement with the San Francisco Regional Water Quality Control Board for
certain exceedances of copper and chlorine under the Rodeo Refinery’s National Pollutant Discharge Elimination System
permit. The settlement was finalized and payment of $109,000 to resolve the matter was made following a 30-day public
comment period that ended in November 2017.
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2017 PHILLIPS 66 ANNUAL REPORT EXECUTIVE OFFICERS OF THE REGISTRANT
PART II
Name
Greg C. Garland
Robert A. Herman
Paula A. Johnson
Kevin J. Mitchell
Chukwuemeka A. Oyolu
* On February 23, 2018.
Position Held
Chairman and Chief Executive Officer
Executive Vice President, Refining
Executive Vice President, Legal and Government Affairs, General Counsel
and Corporate Secretary
Executive Vice President, Finance and Chief Financial Officer
Vice President and Controller
Age*
60
58
54
51
48
There are no family relationships among any of the officers named above. The Board of Directors annually elects the
officers to serve until a successor is elected and qualified or as otherwise provided in our By-Laws. Set forth below is
information about the executive officers identified above.
Greg C. Garland is the Chairman and Chief Executive Officer of Phillips 66, a position he has held since June 2014.
Previously, Mr. Garland served as Phillips 66’s Chairman, President and Chief Executive Officer from April 2012 to June
2014. Mr. Garland previously served as ConocoPhillips’ Senior Vice President, Exploration and Production—Americas
from October 2010 to April 2012, and as President and Chief Executive Officer of CPChem from 2008 to 2010.
Robert A. Herman is Executive Vice President, Refining for Phillips 66, a position he has held since September 2017.
Previously, Mr. Herman served Phillips 66 as Executive Vice President, Midstream from June 2014 to September 2017,
Senior Vice President, HSE, Projects and Procurement from February 2014 to June 2014, and Senior Vice President,
Health, Safety, and Environment from April 2012 to February 2014.
Paula A. Johnson is Executive Vice President, Legal and Government Affairs, General Counsel and Corporate Secretary
of Phillips 66, a position she has held since October 2016. Previously, Ms. Johnson served as Executive Vice President,
Legal, General Counsel and Corporate Secretary of Phillips 66 from May 2013 to October 2016, and Senior Vice
President, Legal, General Counsel and Corporate Secretary of Phillips 66 from April 2012 to May 2013.
Kevin J. Mitchell is Executive Vice President, Finance and Chief Financial Officer of Phillips 66, a position he has held
since January 2016. Previously, Mr. Mitchell served as Phillips 66’s Vice President, Investor Relations from September
2014, when he joined the company, to January 2016. Prior to joining the company, he served as the General Auditor of
ConocoPhillips from May 2010 until September 2014.
Chukwuemeka A. Oyolu is Vice President and Controller of Phillips 66, a position he has held since December 2014.
Mr. Oyolu was Phillips 66’s General Manager, Finance for Refining, Marketing and Transportation from May 2012 to
February 2014 when he became General Manager, Planning and Optimization.
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Quarterly Common Stock Prices and Cash Dividends Per Share
Phillips 66’s common stock is traded on the New York Stock Exchange under the symbol “PSX.” The following table
reflects intraday high and low sales prices of, and dividends declared on, our common stock for each quarter presented:
2017
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2016
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Closing Stock Price at December 29, 2017
Closing Stock Price at January 31, 2018
Number of Stockholders of Record at January 31, 2018
Stock Price
High
Low
Dividends
$
$
88.26
83.11
92.19
102.43
90.87
89.31
81.31
88.87
76.28
75.14
80.73
89.26
71.74
76.40
73.67
77.66
0.63
0.70
0.70
0.70
0.56
0.63
0.63
0.63
$
$
101.15
102.40
38,605
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2017 PHILLIPS 66 ANNUAL REPORT
Performance Graph
Item 6. SELECTED FINANCIAL DATA
Sales and other operating revenues
Income from continuing operations
Income from continuing operations
attributable to Phillips 66
Per common share
Basic
Diluted
Net income
Net income attributable to Phillips 66
Per common share
Basic
Diluted
Total assets
Long-term debt
Cash dividends declared per common share
Millions of Dollars Except Per Share Amounts
2017
2016
2015
2014
2013
$
102,354
5,248
84,279
1,644
98,975
4,280
161,212
4,091
171,596
3,682
5,106
9.90
9.85
5,248
5,106
9.90
9.85
54,371
10,069
2.7300
1,555
4,227
4,056
3,665
2.94
2.92
1,644
1,555
2.94
2.92
51,653
9,588
2.4500
7.78
7.73
4,280
4,227
7.78
7.73
48,580
8,843
2.1800
7.15
7.10
4,797
4,762
8.40
8.33
48,692
7,793
1.8900
5.97
5.92
3,743
3,726
6.07
6.02
49,769
6,101
1.3275
In December 2013, we entered into an agreement to exchange the stock of Phillips Specialty Products Inc. (PSPI), a flow
improver business, which was included in our Marketing and Specialties segment, for shares of Phillips 66 common
stock owned by the other party. The PSPI share exchange was completed in February 2014. Accordingly, the selected
income from continuing operations data above for the years ended December 31, 2014 and 2013, exclude income from
PSPI’s discontinued operations of $706 million and $61 million, respectively.
To ensure full understanding, you should read the selected financial data presented above in conjunction with
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated
financial statements and accompanying notes included elsewhere in this Annual Report on Form 10-K.
In our 2016 annual report, the performance graph included a peer index (the “Previous Peer Group”) composed of
Celanese Corporation; Delek US Holdings, Inc.; Dow Chemical Company; Eastman Chemical Co.; Energy Transfer
Equity, LP; Enterprise Products Partners, LP; HollyFrontier Corporation; Huntsman Corporation; Marathon Petroleum
Corporation; Oneok, Inc.; PBF Energy Inc.; Targa Resources Corp.; Tesoro Corporation; Valero Energy Corporation;
Western Refining, Inc.; and Westlake Chemical Corp. To more appropriately weight our peers with our business
segments and utilize peers with more comparable market capitalizations, we have removed Energy Transfer from the peer
group and replaced Dow with LyondellBasell Industries N.V. Additionally, Tesoro acquired Western Refining
(subsequently renamed Andeavor). Accordingly, the New Peer Index is composed of Andeavor; Celanese Corporation;
Delek US Holdings, Inc.; Eastman Chemical Co.; Enterprise Products Partners, LP; HollyFrontier Corporation;
Huntsman Corporation; LyondellBasell Industries N.V.; Marathon Petroleum Corporation; Oneok, Inc.; PBF Energy Inc.;
Targa Resources Corp.; Valero Energy Corporation; and Westlake Chemical Corp.
Issuer Purchases of Equity Securities
Total Number of
Shares
Purchased*
Average Price
Paid per Share
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs**
Millions of Dollars
Approximate Dollar
Value of Shares
that May Yet Be
Purchased Under the
Plans or Programs
1,717,513
1,675,652
1,492,675
4,885,840
$
$
92.25
93.30
99.17
94.72
$
1,717,513
1,675,652
1,492,675
4,885,840
3,277
3,120
2,972
Period
October 1-31, 2017
November 1-30, 2017
December 1-31, 2017
Total
* Includes repurchase of shares of common stock from company employees in connection with the company’s broad-based employee incentive plans, when
applicable.
** As of December 31, 2017, our Board of Directors has authorized repurchases totaling up to $12 billion of our outstanding common stock, including the
authorization in October 2017 to repurchase $3 billion of additional shares. The authorizations from the Board of Directors do not have expiration dates.
The share repurchases are expected to be funded primarily through available cash. The authorized shares will be repurchased from time to time in the
open market at the company’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. We
are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to
time without prior notice. Shares of stock repurchased are held as treasury shares.
30
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2017 PHILLIPS 66 ANNUAL REPORT
quarter of 2018. Growth capital in Refining will be directed toward small, high-return, quick-payout projects
primarily to increase clean product yields, while in Marketing and Specialties (M&S) it will be directed
primarily towards increasing our retail sites in Europe.
• Returns. We plan to improve refining returns by increasing throughput of advantaged feedstocks, disciplined
capital allocation and portfolio optimization. A disciplined capital allocation process ensures we focus
investments in projects that generate competitive returns throughout the business cycle. In 2017, we improved
clean product yield in Refining, and in M&S, we continued to enhance our network and brand by re-imaging
sites in the United States, while growing our number of sites in Europe.
• Distributions. We believe shareholder value is enhanced through, among other things, consistent growth of
regular dividends, complemented by share repurchases. We increased our quarterly dividend rate by 11 percent
during 2017, and have increased it 250 percent since the company’s inception in 2012. Regular dividends
demonstrate the confidence our Board of Directors and management have in our capital structure and operations’
capability to generate free cash flow throughout the business cycle. In 2017, we repurchased $1.6 billion, or
approximately 18.7 million shares, of our common stock. Also, in October 2017, our Board of Directors
authorized up to $3 billion of additional share repurchases. At the discretion of our Board of Directors, we plan
to increase dividends annually and fund our share repurchase program while continuing to invest in the growth
of our business.
• High-Performing Organization. We strive to attract, develop and retain individuals with the knowledge and
skills to implement our business strategy and who support our values and culture. Throughout the company, we
focus on getting results in the right way and believe success is both what we do and how we do it. We encourage
collaboration throughout our company, while valuing differences, respecting diversity, and creating a great place
to work. We foster an environment of learning and development through structured programs focused on
enhancing functional and technical skills where employees are engaged in our business and committed to their
own, as well as the company’s, success.
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Management’s Discussion and Analysis is the company’s analysis of its financial performance, financial condition, and
significant trends that may affect future performance. It should be read in conjunction with the consolidated financial
statements and notes thereto included elsewhere in this Annual Report on Form 10-K. It contains forward-looking
statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations
and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of
1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,”
“potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,”
“guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company
does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the
federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with
the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE
HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.”
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss)
attributable to Phillips 66.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
Phillips 66 is an energy manufacturing and logistics company with midstream, chemicals, refining, and marketing and
specialties businesses. At December 31, 2017, we had total assets of $54.4 billion.
Executive Overview
We reported earnings of $5.1 billion and generated $3.6 billion in cash from operating activities in 2017. Our reported
earnings included a $2.7 billion provisional income tax benefit from the U.S. Tax Cuts and Jobs Act (the Tax Act) enacted
on December 22, 2017. Phillips 66 Partners LP (Phillips 66 Partners) raised net proceeds totaling $1.8 billion from
equity and debt offerings. We used available cash to fund capital expenditures and investments of $1.8 billion,
repurchase $1.6 billion of our common stock and pay dividends of $1.4 billion. We ended 2017 with $3.1 billion of cash
and cash equivalents and approximately $5.8 billion of total committed capacity available under both our and Phillips 66
Partners’ credit facilities.
We continue to focus on the following strategic priorities:
• Operating Excellence. Our commitment to operating excellence guides everything we do. We are committed to
protecting the health and safety of everyone who has a role in our operations and the communities in which we
operate. Continuous improvement in safety, environmental stewardship, reliability and cost efficiency is a
fundamental requirement for our company and employees. We employ rigorous training and audit programs to
drive ongoing improvement in both personal and process safety as we strive for zero incidents. We achieved a
record-low combined injury rate in 2017. Since we cannot control commodity prices, controlling operating
expenses and overhead costs, within the context of our commitment to safety and environmental stewardship, is
a high priority. Senior management actively monitors these costs. We are committed to protecting the
environment and strive to reduce our environmental footprint throughout our operations. Optimizing utilization
rates at our refineries through reliable and safe operations enables us to capture the value available in the market
in terms of prices and margins. During 2017, our worldwide refining crude oil capacity utilization rate was 95
percent.
• Growth. We have budgeted $2.3 billion in capital expenditures and investments in 2018, including $0.6 billion
for Phillips 66 Partners. Additionally, our share of expected capital spending by joint ventures DCP Midstream,
LLC (DCP Midstream), Chevron Phillips Chemical Company LLC (CPChem) and WRB Refining LP (WRB) in
2018 is $0.9 billion. In Midstream, we plan to invest in our Transportation and NGL businesses, focusing on
projects integrated with our existing assets and infrastructure. In Chemicals, CPChem’s capital expenditures are
expected to decrease due to completion of its U.S. Gulf Coast Petrochemicals Project. The two polyethylene
units started up in September 2017, while commissioning of the ethane cracker is expected to begin in the first
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2017 PHILLIPS 66 ANNUAL REPORT Business Environment
Commodity prices rose significantly during 2017, compared with 2016. The discount for the U.S. crude oil benchmark
West Texas Intermediate (WTI) versus the international benchmark Brent widened over much of 2017, initially related to
extended production cuts by the Organization of the Petroleum Exporting Countries (OPEC) and certain non-OPEC
countries, but further widened with Hurricane Harvey and logistical issues at the Cushing, Oklahoma, trading hub. Over
the course of 2017, commodity prices had both favorable and unfavorable impacts on our businesses that vary by
segment.
Net income in the Midstream segment, which includes our 50 percent equity investment in DCP Midstream, is closely
linked to natural gas liquids (NGL) prices, natural gas prices and crude oil prices. Average natural gas prices increased in
2017, compared with 2016, due to higher demand and low production in early 2017. In the fourth quarter of 2017,
natural gas prices gained momentum with colder temperatures and increased residential and commercial heating demand.
Total U.S. natural gas production also increased through the fourth quarter of 2017, largely from dry gas in the Marcellus
play and associated gas from the Permian Basin. NGL prices improved throughout 2017 due to international demand.
The Chemicals segment consists of our 50 percent equity investment in CPChem. The chemicals and plastics industry is
mainly a commodity-based industry where the margins for key products are based on supply and demand, as well as cost
factors. During 2017, the chemicals and plastics industry continued to benefit from feedstock cost advantages associated
with manufacturing ethylene in regions of the world with significant NGL production. The price of crude oil is rising
faster than NGL prices and thus the petrochemicals industry continues to experience lower ethylene cash costs in regions
of the world where ethylene manufacturing is based upon NGL rather than crude oil-derived feedstocks. In particular,
companies with North American ethane-based crackers have benefited and have captured a somewhat higher
polyethylene chain margin. The ethylene-to-polyethylene chain margins expanded in 2017 because of the crude oil price
recovery after the significant decline in oil prices that began in 2014.
Our Refining segment results are driven by several factors, including refining margins, cost control, refinery throughput,
feedstock costs, product yields and turnaround activity. Industry crack spread indicators, the difference between market
prices for refined products and crude oil, are used to estimate refining margins. During 2017, the U.S. 3:2:1 crack spread
(three barrels of crude oil producing two barrels of gasoline and one barrel of diesel) strengthened across all quarters,
compared with 2016, largely attributable to higher product demand and lower product inventories in the last half of 2017
due to Hurricane Harvey. Northwest European crack spreads on average increased in 2017, compared with 2016, also
due to higher demand.
Results for our M&S segment depend largely on marketing fuel margins, lubricant margins, and other specialty product
margins. While M&S margins are primarily driven by market factors, largely determined by the relationship between
supply and demand, marketing fuel margins, in particular, are influenced by the trend in spot prices for refined products.
Generally speaking, a downward trend of spot prices has a favorable impact on marketing fuel margins, while an upward
trend of spot prices has an unfavorable impact on marketing fuel margins. Spot prices moved upward in 2017, following
the increase in crude oil prices.
RESULTS OF OPERATIONS
Basis of Presentation
During the fourth quarter of 2017, the segment performance measure used by our chief executive officer to assess
performance and allocate resources was changed from “net income attributable to Phillips 66” to “net income.” This
change reflects the recognition that management does not differentiate between those earnings attributable to Phillips 66
and those attributable to noncontrolling interests when making operating and resource allocation decisions impacting
segment performance. Prior period segment information has been recast to conform to the current presentation.
Consolidated Results
A summary of net income (loss) by business segment with a reconciliation to net income attributable to Phillips 66
follows:
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Net income
Less: net income attributable to noncontrolling interests
Net income attributable to Phillips 66
Millions of Dollars
Year Ended December 31
2017
464
525
1,404
686
2,169
5,248
142
5,106
$
$
2016
280
583
374
891
(484)
1,644
89
1,555
2015
74
962
2,555
1,187
(498)
4,280
53
4,227
2017 vs. 2016
Our earnings increased $3,551 million, or 228 percent, in 2017, mainly reflecting:
• Recognition of a $2,735 million provisional income tax benefit from the enactment of the Tax Act in December
2017.
• Higher realized refining margins.
• Recognition of a $261 million after-tax gain from the consolidation of Merey Sweeny, L.P. (MSLP).
•
Improved equity earnings from affiliates in our Midstream segment.
These increases were partially offset by:
•
Increased costs due to Hurricane Harvey, primarily impacting CPChem in our Chemicals segment.
• Lower realized marketing margins.
• Higher interest and debt expense.
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2017 PHILLIPS 66 ANNUAL REPORT
Income tax expense (benefit) was a benefit in 2017, compared with expense in 2016, primarily due to the $2,735 million
provisional income tax benefit from the enactment of the Tax Act in December 2017. This benefit was partially offset by
higher income tax expense from increased income before income taxes. See Note 21—Income Taxes, in the Notes to
Consolidated Financial Statements, for more information regarding our income taxes.
Net income attributable to noncontrolling interest increased $53 million in 2017, reflecting the contribution of assets to
Phillips 66 Partners during 2017 and late 2016. See Note 27—Phillips 66 Partners LP, in the Notes to Consolidated
Financial Statements, for more information.
2016 vs. 2015
Sales and other operating revenues and purchased crude oil and products both decreased 15 percent in 2016. The
decreases were primarily due to lower average prices for petroleum products and crude oil, while average NGL prices
were slightly improved during 2016.
Equity in earnings of affiliates decreased 10 percent in 2016, primarily resulting from decreased earnings from CPChem
and WRB, partially offset by improved results from DCP Midstream.
• Equity in earnings of CPChem decreased 37 percent, primarily due to lower realized olefins and polyolefins
margins.
• Equity in earnings of WRB decreased $186 million, mainly resulting from lower market crack spreads, partially
offset by higher feedstock advantage.
• Equity in earnings of DCP Midstream improved $426 million in 2016, primarily driven by goodwill and other
asset impairments recorded by DCP Midstream in 2015.
Net gain on dispositions decreased $273 million in 2016. In 2015, we recognized a $242 million deferred gain related to
the sale of ICHP. See Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for
additional information.
See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our income
tax expense and effective tax rates.
2016 vs. 2015
Our earnings decreased $2,672 million, or 63 percent, in 2016, primarily resulting from:
• Lower realized refining margins.
• Lower olefins and polyolefins margins.
• Recognition in 2015 of $242 million of the deferred gain related to the sale in 2013 of the Immingham
Combined Heat and Power Plant (ICHP).
These decreases were partially offset by:
•
Improved results from DCP Midstream, primarily as a result of goodwill and other asset impairments recorded in
2015.
See the “Segment Results” section for additional information on our segment results.
Income Statement Analysis
2017 vs. 2016
Sales and other operating revenues and purchased crude oil and products increased 21 percent and 27 percent,
respectively, in 2017. The increases were primarily due to higher prices for petroleum products, crude oil and NGL.
Equity in earnings of affiliates increased 22 percent in 2017, primarily resulting from higher equity in earnings from DCP
Midstream and other affiliates in our Midstream segment, as well as WRB, partially offset by lower results from
CPChem.
• Equity in earnings from our Midstream segment increased $270 million due to improved results from DCP
Midstream, primarily driven by improved margins, as well as higher equity in earnings from our Transportation
affiliates, including our joint ventures that own the Bakken Pipeline, which started commercial operations in
June 2017.
• Equity in earnings of WRB increased $207 million, primarily due to higher market crack spreads, partially offset
by lower feedstock advantage.
• Equity in earnings of CPChem decreased $120 million, primarily due to hurricane-related costs and downtime.
Other income increased $447 million in 2017. We recognized a noncash, pre-tax gain of $423 million in February 2017
related to the consolidation of MSLP. See Note 5—Business Combinations, in the Notes to Consolidated Financial
Statements, for additional information.
Operating expenses increased 10 percent in 2017. This increase was mainly due to the consolidation of a transportation
joint venture in December 2016, as well as higher refining turnaround expenses and utility costs, pension settlement
expense, and costs associated with a full year of operations at the Freeport LPG Export Terminal. These increases were
partially offset by lower costs due to the sale of the Whitegate Refinery in 2016.
Depreciation and amortization increased 13 percent in 2017 due to the Freeport LPG Export Terminal beginning
operations in late 2016, as well as other assets placed in service in 2017.
Interest and debt expense increased 30 percent in 2017. This increase was primarily due to lower capitalized interest
from the completion of major projects, including the startup of the Freeport LPG Export Terminal in late 2016, as well as
higher average debt principal balances.
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66
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2017 PHILLIPS 66 ANNUAL REPORT Segment Results
Midstream
Net Income (Loss)
Transportation
NGL and Other
DCP Midstream
Total Midstream
Transportation Volumes
Pipelines*
Terminals
Operating Statistics
NGL fractionated**
NGL extracted***
$
$
376
43
45
464
311
2
(33)
280
Thousands of Barrels Daily
3,501
2,665
186
374
3,511
2,422
170
393
335
63
(324)
74
3,264
1,981
112
410
* Pipelines represent the sum of volumes transported through each separately tariffed pipeline segment, including our share of equity volumes from
Yellowstone Pipe Line Company and Lake Charles Pipe Line Company.
** Excludes DCP Midstream.
*** Represents 100 percent of DCP Midstream’s volumes.
Dollars Per Gallon
Weighted-Average NGL Price*
DCP Midstream
* Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by NGL component and location mix.
0.62
$
0.46
0.45
Net income from our NGL and Other business increased $41 million in 2017, compared with 2016. The increase reflects
a full year of operations at the Freeport LPG Export Terminal, the contribution of MSLP to Phillips 66 Partners in
October 2017, and higher equity earnings from DCP Sand Hills Pipeline, LLC (Sand Hills), partially offset by lower
realized margins.
Year Ended December 31
2017
2016
2015
Millions of Dollars
Net income from our investment in DCP Midstream improved $78 million in 2017, compared with 2016. The increase
was primarily due to improved margins driven by higher average NGL and natural gas prices, and improved results from
DCP Midstream’s hedging program.
See the “Business Environment and Executive Overview” section for information on market factors impacting 2017
results.
2016 vs. 2015
Net income from the Midstream segment increased $206 million in 2016, compared with 2015. The increase was
primarily due to improved results from DCP Midstream, partially offset by lower net income from our Transportation and
NGL and Other businesses.
Transportation net income decreased $24 million in 2016, compared with 2015. Lower net income primarily resulted
from higher operating costs and increased depreciation expense due to growth projects. These items were partially offset
by higher revenues from increased throughput volumes and higher tariffs.
Net income from our NGL and Other business decreased $61 million in 2016, compared with 2015. The decrease was
primarily driven by lower realized margins, as well as increased depreciation and operating expenses associated with the
Sweeny Fractionator and, late in the year, the Freeport LPG Export Terminal. These items were partially offset by higher
fractionated volumes, reflecting the operation of the Sweeny Fractionator for a full year in 2016, and the benefit of the
first liquefied petroleum gas cargos exported from the Freeport LPG Export Terminal in late 2016.
Improved results from our investment in DCP Midstream increased our net income by $291 million in 2016, compared
with 2015. In 2015, DCP Midstream recorded goodwill and other asset impairments, which reduced our net income by
$232 million. In addition, favorable contract restructuring efforts, improved asset performance, higher equity in earnings
from DCP Midstream’s equity affiliates, lower operating costs and higher NGL prices contributed to better results in
2016. These improvements were partially offset by lower natural gas and crude oil prices.
The Midstream segment provides crude oil and refined products transportation, terminaling and processing services, as
well as natural gas, NGL and liquefied petroleum gas (LPG) transportation, storage, processing and marketing services,
mainly in the United States. This segment includes our master limited partnership (MLP), Phillips 66 Partners, as well as
our 50 percent equity investment in DCP Midstream, which includes the operations of its MLP, DCP Midstream, LP
(DCP Partners).
2017 vs. 2016
Net income from the Midstream segment increased $184 million in 2017, compared with 2016, due to improved results
across all business lines.
Transportation net income increased $65 million in 2017, compared with 2016. The improvement was mainly driven by
increased equity in earnings from affiliates, including our joint ventures that own the Bakken Pipeline, which started
commercial operations in June 2017, as well as Rockies Express Pipeline LLC (REX) due to our share of a favorable
breach of contract settlement claim. These increases were partially offset by higher operating costs.
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39
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2017 PHILLIPS 66 ANNUAL REPORT
Chemicals
2016 vs. 2015
Year Ended December 31
2017
2016
2015
Millions of Dollars
Net Income
$
525
583
962
CPChem Externally Marketed Sales Volumes*
Olefins and Polyolefins
Specialties, Aromatics and Styrenics
Millions of Pounds
15,870
4,618
20,488
16,011
4,911
20,922
16,916
5,301
22,217
* Represents 100 percent of CPChem’s outside sales of produced petrochemical products, as well as commission sales from equity affiliates.
Olefins and Polyolefins Capacity Utilization (percent)*
87%
91
92
The Chemicals segment consists of our 50 percent interest in CPChem, which we account for under the equity method.
CPChem uses NGL and other feedstocks to produce petrochemicals. These products are then marketed and sold or used
as feedstocks to produce plastics and other chemicals. We structure our reporting of CPChem’s operations around two
primary business segments: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P
business segment produces and markets ethylene and other olefin products. Ethylene produced is primarily consumed
within CPChem for the production of polyethylene, normal alpha olefins and polyethylene pipe. The SA&S business
segment manufactures and markets aromatics and styrenics products, such as benzene, styrene, paraxylene and
cyclohexane, as well as polystyrene. SA&S also manufactures and/or markets a variety of specialty chemical products.
Unless otherwise noted, amounts referenced below reflect our net 50 percent interest in CPChem.
2017 vs. 2016
Net income from the Chemicals segment decreased $58 million in 2017, compared with 2016. The decrease was
primarily driven by higher costs and lower volumes due to Hurricane Harvey, as well as lower margins. These items
were partially offset by lower impairment charges, higher equity in earnings from an O&P affiliate due to lower
turnaround costs and a gain on the sale of CPChem’s K-Resin® styrene-butadiene copolymers business. CPChem
recognized impairment charges of $127 million and $177 million in 2017 and 2016, respectively, due to lower demand
and margin factors. As a result of these impairments, net income of the Chemicals segment was reduced by $39 million
and $89 million in 2017 and 2016, respectively.
As a result of Hurricane Harvey, CPChem’s Cedar Bayou facility in Baytown, Texas, experienced severe flooding, which
caused it to shut down operations in the third quarter of 2017. This facility restarted in phases during the fourth quarter
of 2017. CPChem’s U.S. Gulf Coast Petrochemicals Project, which consists of an ethane cracker at Cedar Bayou and
two polyethylene units at Old Ocean, Texas, was also impacted by the flooding. CPChem achieved mechanical
completion of its ethane cracker at the Cedar Bayou facility in December 2017, and is expected to complete
commissioning of the ethane cracker in the first quarter of 2018, with a transition to full production in the second quarter
of 2018.
See the “Business Environment and Executive Overview” section for information on market factors impacting CPChem’s
results.
Net income from the Chemicals segment decreased $379 million in 2016, compared with 2015. The decrease in net
income was primarily due to lower realized margins from the O&P business, driven by a decline in sales prices for
polyethylene and normal alpha olefins (NAO) and higher feedstock costs, as well as impacts from increased turnaround
activity. Lower equity earnings from CPChem’s equity affiliates and lower SA&S volumes further reduced net income in
2016.
In addition, CPChem recognized a $177 million impairment in 2016 due to lower demand and margin factors affecting an
equity affiliate, which resulted in an $89 million after-tax reduction in our equity earnings from CPChem. Our equity in
earnings from CPChem were reduced by $24 million in 2015 as a result of an impairment CPChem recognized on an
equity affiliate. These items were partially offset by higher NAO and polyethylene sales volumes and improved SA&S
margins.
Refining
Net Income (Loss)
Atlantic Basin/Europe
Gulf Coast
Central Corridor
West Coast
Worldwide
Net Income (Loss)
Atlantic Basin/Europe
Gulf Coast
Central Corridor
West Coast
Worldwide
Realized Refining Margins
Atlantic Basin/Europe
Gulf Coast
Central Corridor
West Coast
Worldwide
Year Ended December 31
2017
2016
2015
Millions of Dollars
$
$
$
$
370
512
477
45
1,404
1.86
1.79
5.18
0.34
1.97
8.25
7.07
12.44
10.49
9.13
204
52
234
(116)
374
Dollars Per Barrel
0.93
0.18
2.38
(0.92)
0.51
6.26
5.49
8.70
9.15
6.99
569
551
857
578
2,555
2.68
2.08
8.96
4.42
3.63
9.39
9.29
14.88
16.86
11.84
40
70
41
71
2017 PHILLIPS 66 ANNUAL REPORT
Operating Statistics
Refining operations*
Atlantic Basin/Europe
Crude oil capacity
Crude oil processed
Capacity utilization (percent)
Refinery production
Gulf Coast
Crude oil capacity
Crude oil processed
Capacity utilization (percent)
Refinery production
Central Corridor
Crude oil capacity
Crude oil processed
Capacity utilization (percent)
Refinery production
West Coast
Crude oil capacity
Crude oil processed
Capacity utilization (percent)
Refinery production
Worldwide
Crude oil capacity
Crude oil processed
Capacity utilization (percent)
Refinery production
* Includes our share of equity affiliates.
Thousands of Barrels Daily
Year Ended December 31
2017
2016
2015
520
494
95%
553
743
709
95%
789
493
467
95%
489
360
342
95%
368
566
568
100
607
743
704
95
783
493
485
98
506
360
318
88
345
588
539
92
587
738
654
89
733
492
465
95
486
360
330
92
359
2,116
2,012
95%
2,199
2,162
2,075
96
2,241
2,178
1,988
91
2,165
2016 vs. 2015
Net income for the Refining segment decreased $2,181 million in 2016, compared with 2015. Lower net income in 2016
reflected lower realized refining margins resulting from decreased market crack spreads, higher costs associated with
renewable fuels blending activities, lower clean product differentials and lower feedstock advantage. These items were
partially offset by higher volumes due to lower turnaround activities and less unplanned downtime.
Our worldwide refining crude oil capacity utilization rate was 96 percent in 2016, compared with 91 percent in 2015.
The increase was primarily attributable to lower turnaround activities and less unplanned downtime.
Non-GAAP Reconciliations
Our realized refining margins measure the difference between a) sales and other operating revenues derived from the sale
of petroleum products manufactured at our refineries and b) purchase costs of feedstocks, primarily crude oil, used to
produce the petroleum products. The margins are adjusted to include our proportional share of our joint-venture
refineries’ realized margins, as well as to exclude those items that are not representative of the underlying operating
performance of a period, which we call “special items.” The realized refining margins are converted to a per-barrel basis
by dividing them by total refinery processed inputs (primarily crude oil) measured on a barrel basis, including our share
of inputs processed by our joint-venture refineries. Our realized refining margin per barrel is intended to be comparable
with industry refining margins, which are known as “crack spreads.” As discussed in “Business Environment,” industry
crack spreads measure the difference between market prices for refined petroleum products and crude oil. Realized
refining margin per barrel calculated on a similar basis as industry crack spreads provides a useful measure of how well
we performed relative to benchmark industry margins.
Under generally accepted accounting principles in the United States (GAAP), the performance measure most directly
comparable to refining margin per barrel is the Refining segment’s “net income per barrel.” Refining margin per barrel
excludes items that are typically included in a manufacturer’s gross margin, such as depreciation and operating expenses,
and other items used to determine net income, such as general and administrative expenses and income taxes. It also
includes our proportional share of joint-venture refineries’ realized margins and excludes special items. Because refining
margin per barrel is calculated in this manner, and because refining margin per barrel may be defined differently by other
companies in our industry, it has limitations as an analytical tool. Following are reconciliations of net income to realized
refining margins:
The Refining segment refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and
aviation fuels) at 13 refineries in the United States and Europe.
2017 vs. 2016
Net income for the Refining segment increased $1,030 million in 2017, compared with 2016. The increase was primarily
due to higher realized refining margins and West Coast volumes, as well as an after-tax gain of $261 million recognized
on the consolidation of MSLP, partially offset by higher turnaround expenses, utilities costs and pension settlement
expense. The higher realized refining margins primarily resulted from improved market crack spreads and secondary
product margins, partially offset by lower feedstock advantage.
See the “Business Environment and Executive Overview” section for information on industry crack spreads and other
market factors impacting this year’s results. In addition, see Note 5—Business Combinations and Note 27—Phillips 66
Partners LP, in the Notes to Consolidated Financial Statements, for additional information on the consolidation of MSLP
in February 2017 and the subsequent contribution of our ownership interest in MSLP to Phillips 66 Partners in October
2017, respectively.
Our worldwide refining crude oil capacity utilization rate was 95 percent in 2017, compared with 96 percent in 2016.
The decrease was primarily attributable to higher turnaround activities and unplanned downtime, partially offset by
improved market conditions.
42
72
43
73
2017 PHILLIPS 66 ANNUAL REPORT Realized Refining Margins
Year Ended December 31, 2017
Net income
Plus:
Income tax expense
Taxes other than income taxes
Depreciation, amortization and impairments
Selling, general and administrative expenses
Operating expenses
Equity in (earnings) losses of affiliates
Other segment (income) expense, net
Proportional share of refining gross margins
contributed by equity affiliates
Special items:
Certain tax impacts
Realized refining margins
Total processed inputs (thousands of barrels)
Adjusted total processed inputs (thousands of barrels)*
Net income per barrel (dollars per barrel)**
Realized refining margins (dollars per barrel)***
Year Ended December 31, 2016
Net income (loss)
Plus:
Income tax expense (benefit)
Taxes other than income taxes
Depreciation, amortization and impairments
Selling, general and administrative expenses
Operating expenses
Equity in (earnings) losses of affiliates
Other segment (income) expense, net
Proportional share of refining gross margins
contributed by equity affiliates
Special items:
Pending claims and settlements
Certain tax impacts
Railcar lease residual value deficiencies and related
costs
Recognition of deferred logistics commitments
Realized refining margins
$
$
$
204
(17)
58
200
64
817
8
(11)
55
—
(32)
5
30
1,381
$
Millions of Dollars, Except as Indicated
Atlantic
Basin/
Europe
Gulf
Coast
Central
Corridor
West
Coast Worldwide
$
370
512
477
45
1,404
78
56
192
61
847
11
(10)
59
(23)
1,641
297
97
273
55
1,212
(4)
(421)
1
—
2,022
278
46
129
34
593
(329)
13
959
19
64
244
48
982
—
5
—
—
2,200
—
1,407
672
263
838
198
3,634
(322)
(413)
1,019
(23)
7,270
199,068
199,068
285,951
285,951
92,146
176,823
134,089
134,089
711,254
795,931
1.86
8.25
1.79
7.07
5.18
12.44
0.34
10.49
1.97
9.13
Realized Refining Margins
Year Ended December 31, 2015
Net income
Plus:
Income tax expense (benefit)
Taxes other than income taxes
Depreciation, amortization and impairments
Selling, general and administrative expenses
Operating expenses
Equity in (earnings) losses of affiliates
Other segment (income) expense, net
Proportional share of refining gross margins
contributed by equity affiliates
Realized refining margins
Millions of Dollars, Except as Indicated
Atlantic
Basin/
Europe
Gulf
Coast
Central
Corridor
West
Coast Worldwide
$
569
551
857
578
2,555
(15)
57
197
67
995
8
30
89
1,997
$
338
76
226
60
1,241
(25)
2
(9)
2,460
469
42
102
35
447
(308)
8
312
84
216
59
961
—
(5)
977
2,629
—
2,205
1,104
259
741
221
3,644
(325)
35
1,057
9,291
Total processed inputs (thousands of barrels)
Adjusted total processed inputs (thousands of barrels)*
212,627
212,627
264,874
264,874
95,682
176,641
130,799
130,799
703,982
784,941
2.08
Net income per barrel (dollars per barrel)**
Realized refining margins (dollars per barrel)***
9.29
* Adjusted total processed inputs include our proportional share of processed inputs of an equity affiliate.
** Net income divided by total processed inputs.
*** Realized refining margins per barrel, as presented, are calculated using the underlying realized refining margin amounts, in dollars, divided by adjusted
3.63
11.84
4.42
16.86
8.96
14.88
2.68
9.39
$
total processed inputs, in barrels. As such, recalculated per barrel amounts using the rounded margins and barrels presented may differ from the
presented per barrel amounts due to rounding.
52
234
(116)
374
17
73
234
51
1,234
(50)
3
(4)
(70)
—
16
—
1,556
133
42
106
31
465
(122)
(6)
705
—
—
11
—
1,599
(72)
80
230
49
979
—
(2)
—
—
—
8
—
1,156
61
253
770
195
3,495
(164)
(16)
756
(70)
(32)
40
30
5,692
Total processed inputs (thousands of barrels)
Adjusted total processed inputs (thousands of barrels)*
220,519
220,519
283,574
283,574
98,217
183,691
126,329
126,329
728,639
814,113
Net income (loss) per barrel (dollars per barrel)**
Realized refining margins (dollars per barrel)***
* Adjusted total processed inputs include our proportional share of processed inputs of an equity affiliate.
** Net income (loss) divided by total processed inputs.
*** Realized refining margins per barrel, as presented, are calculated using the underlying realized refining margin amounts, in dollars, divided by adjusted
(0.92)
9.15
0.93
6.26
0.18
5.49
2.38
8.70
0.51
6.99
$
total processed inputs, in barrels. As such, recalculated per barrel amounts using the rounded margins and barrels presented may differ from the
presented per barrel amounts due to rounding.
44
74
45
75
2017 PHILLIPS 66 ANNUAL REPORT Marketing and Specialties
Net Income
Marketing and Other
Specialties
Total Marketing and Specialties
Net Income
U.S.
International
Realized Marketing Fuel Margins
U.S.
International
U.S. Average Wholesale Prices*
Gasoline
Distillates
* On third-party branded petroleum products sales, excluding excise taxes.
Marketing Petroleum Products Sales
Gasoline
Distillates
Other
Year Ended December 31
2017
2016
2015
Millions of Dollars
$
$
$
$
$
551
135
686
0.56
1.81
1.48
4.21
1.87
1.85
747
144
891
Dollars Per Barrel
0.74
2.21
1.64
4.05
Dollars Per Gallon
1.62
1.48
Thousands of Barrels Daily
1,246
931
18
2,195
1,238
947
16
2,201
1,004
183
1,187
0.76
1.98
1.65
4.40
1.92
1.77
1,205
953
16
2,174
The M&S segment purchases for resale and markets refined petroleum products (such as gasoline, distillates and aviation
fuels), mainly in the United States and Europe. In addition, this segment includes the manufacturing and marketing of
specialty products (such as base oils and lubricants), as well as power generation operations.
2017 vs. 2016
Net income from the M&S segment decreased $205 million in 2017, compared with 2016. The decrease was primarily
due to lower realized marketing margins, as well as the absence of biofuel tax credits and a favorable income tax
adjustment recognized in 2016.
See the “Business Environment and Executive Overview” section for information on marketing fuel margins and other
market factors impacting 2016 results.
2016 vs. 2015
Net income from the M&S segment decreased $296 million in 2016, compared with 2015. The decrease was mainly
attributable to the $242 million deferred gain recognized in 2015 related to the 2013 ICHP sale. See Note 6—Assets
Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information.
Also contributing to the lower net income in 2016 were lower realized marketing margins driven by an upward trend of
spot prices during most of 2016, and lower margins and volumes in lubricants. These decreases were partially offset by
favorable tax adjustments and higher marketing volumes.
Non-GAAP Reconciliations
Our realized marketing fuel margins measure the difference between a) sales and other operating revenues derived from
the sale of fuels in our M&S segment and b) purchase costs of those fuels. These margins are converted to a per-barrel
basis by dividing them by sales volumes measured on a barrel basis. Marketing fuel margin per barrel demonstrates the
value uplift our marketing operations provide by optimizing the placement and ultimate sale of our refineries’ fuel
production.
Within the M&S segment, the GAAP performance measure most directly comparable to marketing fuel margin per barrel
is the marketing business’ “net income per barrel.” Marketing fuel margin per barrel excludes items that are typically
included in gross margin, such as depreciation and operating expenses, and other items used to determine net income,
such as general and administrative expenses and income taxes. Because marketing fuel margin per barrel excludes these
items, and because marketing fuel margin per barrel may be defined differently by other companies in our industry, it has
limitations as an analytical tool. Following are reconciliations of net income to realized marketing fuel margins:
Realized Marketing Fuel Margins
Net income
Plus:
Income tax expense
Taxes other than income taxes
Depreciation, amortization and impairment
Selling, general and administrative expenses
Equity in earnings of affiliates
Other operating revenues*
Other segment (income) expense, net
Marketing margins
Less: margin for non-fuel related sales
Realized marketing fuel margins
Millions of Dollars, Except as Indicated
U.S.
International
2017
2016
2015
2017
2016
2015
$
395
519
518
176
235
217
233
5,481
14
751
(5)
(5,815)
(15)
1,039
—
1,039
$
285
5,187
12
708
(4)
(5,558)
—
1,149
—
1,149
292
5,208
9
732
(4)
(5,614)
(15)
1,126
—
1,126
41
7,579
67
264
(83)
(7,594)
2
452
42
410
17
8,132
63
259
(75)
(8,157)
3
477
45
432
57
8,499
62
269
(78)
(8,507)
6
525
44
481
Total fuel sales volumes (thousands of barrels)
703,928
699,111
684,045
97,346
106,574
109,332
Net income per barrel (dollars per barrel)
Realized marketing fuel margins (dollars per
barrel)**
* Primarily excise taxes and other non-fuel revenues.
** Realized marketing fuel margins per barrel, as presented, are calculated using the underlying realized marketing fuel margin amounts, in dollars, divided
by sales volumes, in barrels. As such, recalculated per barrel amounts using the rounded margins and barrels presented may differ from the presented per
barrel amounts due to rounding.
4.05
2.21
1.48
1.64
4.21
0.74
1.65
0.76
1.98
4.40
0.56
1.81
$
46
76
47
77
2017 PHILLIPS 66 ANNUAL REPORT
Corporate and Other
Net Income (Loss)
Net interest expense
Corporate general and administrative expenses
Technology
U.S. tax reform
Other
Total Corporate and Other
2017 vs. 2016
Millions of Dollars
Year Ended December 31
2017
(266)
(175)
(62)
2,735
(63)
2,169
$
$
2016
(210)
(161)
(58)
—
(55)
(484)
2015
(186)
(157)
(60)
—
(95)
(498)
Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net
interest expense increased $56 million in 2017, compared with 2016, primarily due to lower capitalized interest as a
result of the Freeport LPG Export Terminal beginning operations in late 2016, and higher interest expense driven by
higher average debt principal balances, reflecting Phillips 66 Partners’ debt issuances in October 2017 and 2016.
The Tax Act was enacted on December 22, 2017. The material provisions of the Tax Act i) reduced the U.S. federal
corporate income tax rate from 35 percent to 21 percent beginning January 1, 2018, ii) imposed a one-time deemed
repatriation tax on foreign-sourced earnings that were previously tax deferred, and iii) created a new tax regime on
post-2017 foreign-sourced earnings. We have not yet completed our accounting for the income tax effects of the Tax Act
as of December 31, 2017, but have made reasonable estimates of those effects on our existing deferred income tax
balances and the one-time deemed repatriation tax. We recognized a provisional income tax benefit of $2,735 million,
which is included in the “Income tax expense (benefit)” line on our consolidated statement of income. We have included
these one-time impacts of the Tax Act in Corporate and Other. Of the provisional income tax benefit recognized, $2,870
million was associated with the revaluation of our existing deferred tax assets and liabilities, and $14 million reflected
higher manufacturing deductions, which was an indirect benefit of the Tax Act. These benefits were partially offset by
the one-time deemed repatriation tax estimate of $149 million. We expect the Tax Act to significantly lower our effective
tax rates in 2018 and future years for both our consolidated operations and each of our operating segments. See Note 21
—Income Taxes, in the Notes to Consolidated Financial Statements, for more information.
2016 vs. 2015
Net interest expense increased $24 million in 2016, compared with 2015, mainly due to lower capitalized interest.
The category “Other” includes certain income tax expenses, environmental costs associated with sites no longer in
operation, foreign currency transaction gains and losses and other costs not directly associated with an operating
segment. The decrease in other costs in 2016 was primarily attributable to favorable tax impacts and the write-off of
certain fixed assets during 2015, partially offset by higher environmental accruals.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Cash and cash equivalents
Net cash provided by operating activities
Short-term debt
Total debt
Total equity
Percent of total debt to capital*
Percent of floating-rate debt to total debt
* Capital includes total debt and total equity.
Millions of Dollars, Except as Indicated
2017
2016
2015
$
3,119
3,648
41
10,110
27,428
27%
11%
2,711
2,963
550
10,138
23,725
30
3
3,074
5,713
44
8,887
23,938
27
1
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources but rely primarily on
cash generated from operating activities. Additionally, Phillips 66 Partners raises funds for its growth activities through
debt and equity financings. During 2017, we generated $3.6 billion in cash from operations. Phillips 66 Partners
completed the private placement of perpetual convertible preferred units and common units and the public offering of
senior notes and common units for net proceeds totaling $1.8 billion. We used this available cash primarily for capital
expenditures and investments of $1.8 billion; repurchases of our common stock of $1.6 billion; and dividend payments
on our common stock of $1.4 billion. During 2017, cash and cash equivalents increased by $0.4 billion, to $3.1 billion.
In addition to cash flows from operating activities, we rely on our commercial paper and credit facility programs, asset
sales and our ability to issue securities using our shelf registration statement to support our short- and long-term liquidity
requirements. We believe current cash and cash equivalents and cash generated by operations, together with access to
external sources of funds as described below under “Significant Sources of Capital,” will be sufficient to meet our
funding requirements in the near and long term, including our capital spending, dividend payments, defined benefit plan
contributions, debt repayment and share repurchases.
Significant Sources of Capital
Operating Activities
During 2017, cash of $3,648 million was provided by operating activities, a 23 percent increase compared with 2016.
The increase was primarily attributable to increased operating results due to higher realized refining margins and
distributions from our equity affiliates. This increase was partially offset by working capital changes, reflecting the
negative impact of building inventory at higher commodity prices and timing of refining payables payments, as well as
lower marketing margins.
During 2016, cash of $2,963 million was provided by operating activities, a 48 percent decrease compared with 2015.
The decrease was primarily attributable to lower realized refining margins, as well as a reduction in distributions from
our equity affiliates. This decrease was partially offset by positive working capital of $501 million in 2016 compared to a
negative working capital impact of $221 million in 2015. The positive working capital impact in 2016 was primarily
driven by increased refining payables, due to an increase in feedstock costs at the end of 2016 as compared with 2015,
and the timing of tax payments and refunds, partially offset by an increase in receivables, resulting from higher
commodity prices.
Our short- and long-term operating cash flows are highly dependent upon refining and marketing margins, NGL prices
and chemicals margins. Prices and margins in our industry are typically volatile, and are driven by market conditions
over which we have little or no control. Absent other mitigating factors, as these prices and margins fluctuate, we would
expect a corresponding change in our operating cash flows.
48
78
49
79
2017 PHILLIPS 66 ANNUAL REPORT
The level and quality of output from our refineries also impacts our cash flows. Factors such as operating efficiency,
maintenance turnarounds, market conditions, feedstock availability and weather conditions can affect output. We
actively manage the operations of our refineries, and any variability in their operations typically has not been as
significant to cash flows as that caused by margins and prices. Our worldwide refining crude oil capacity utilization was
95 percent in 2017, compared with 96 percent in 2016.
Equity Affiliates
Our operating cash flows are also impacted by distribution decisions made by our equity affiliates, including
DCP Midstream, CPChem and WRB. Over the three years ended December 31, 2017, we received distributions of $107
million from DCP Midstream, $1,854 million from CPChem and $300 million from WRB. We cannot control the
amount or timing of future distributions from equity affiliates; therefore, future distributions by these and other equity
affiliates are not assured.
Effective January 1, 2017, DCP Midstream and DCP Partners closed a transaction in which DCP Midstream contributed
subsidiaries owning all of its operating assets, $424 million of cash and $3.15 billion of debt to DCP Partners, in
exchange for DCP Partners units which had an estimated fair value of $1.125 billion at the time of the transaction. We
and our co-venturer retained our 50/50 investment in DCP Midstream, and DCP Midstream retained its incentive
distribution rights (IDRs) in DCP Partners through its ownership of the general partner of DCP Partners. After the
transaction, DCP Midstream held a 36 percent limited partner interest and a 2 percent general partner interest in DCP
Partners. DCP Midstream, through its ownership of the general partner, has agreed, if required, to forgo receipt of IDRs
up to $100 million annually (100 percent basis) through 2019, to support a minimum distribution coverage ratio for DCP
Partners. In connection with the transaction, DCP Midstream terminated its revolving credit agreement, which had
previously served to limit distributions to its owners while amounts had been borrowed under the facility. As a result,
distributions to the owners of DCP Midstream resumed in 2017.
In 2015, CPChem made a special distribution to its owners, with our share totaling $696 million. CPChem funded the
distribution by issuing $1.4 billion of senior notes with maturities ranging from three to five years, with a combination of
fixed and floating interest rates. This cash inflow from CPChem was included in operating cash flows, as we had
cumulative undistributed equity earnings attributable to CPChem in excess of the amount distributed. We did not receive
any distributions from CPChem in the second half of 2017 due to the impacts of Hurricane Harvey on its Gulf Coast
operations and its U.S. Gulf Coast Petrochemicals Project. We expect distributions from CPChem to resume in 2018.
Foreign Cash Holdings
With the passage of the Tax Act in December 2017, we are subject to a one-time deemed repatriation tax on foreign-
sourced earnings. For a portion of those foreign earnings, we had previously deferred any associated U.S. income taxes.
As a result of the Tax Act, we now have the ability to utilize a greater percentage of our worldwide cash and cash
equivalents for domestic purposes without incurring additional material U.S. income taxes beyond those imposed by the
one-time deemed repatriation tax, thereby improving the flexibility of our worldwide cash management system. We
expect a portion of our foreign cash holdings will be reserved exclusively for foreign use in support of those operations
and local statutory and regulatory requirements; however, that amount is not expected to materially impact our liquidity.
Additionally, we do not expect the payment of the one-time deemed repatriation tax to materially impact our liquidity.
Phillips 66 Partners
In 2013, we formed Phillips 66 Partners, a publicly traded MLP, to own, operate, develop and acquire primarily fee-based
crude oil, refined petroleum products, and NGL pipelines and terminals, as well as other Midstream assets.
Ownership
At December 31, 2017, we owned a 55 percent limited partner interest and a 2 percent general partner interest in Phillips
66 Partners, while its public unitholders owned a 43 percent limited partner interest and 13.8 million perpetual
convertible preferred units. We consolidate Phillips 66 Partners as a variable interest entity for financial reporting
purposes. See Note 3—Variable Interest Entities, in the Notes to Consolidated Financial Statements, for additional
information on why we consolidate the partnership. As a result of this consolidation, the public common and preferred
unitholders’ interests in Phillips 66 Partners are reflected as noncontrolling interests in our consolidated balance sheet,
and totaled $2,314 million at December 31, 2017. Generally, drop down transactions to Phillips 66 Partners will
eliminate in consolidation, except for third-party debt or third-party equity offerings made by Phillips 66 Partners to
finance such transactions. As a result of Phillips 66 Partners’ third-party debt and equity offerings in 2017, primarily
related to the contribution of assets in October 2017, our consolidated cash increased by $1,848 million and consolidated
debt increased by $643 million.
Debt and Equity Financings
During the three years ended December 31, 2017, Phillips 66 Partners raised net proceeds of approximately $5.4 billion
from the following third-party debt and equity offerings:
•
•
•
•
•
•
•
•
•
In October 2017, Phillips 66 Partners received net proceeds of $643 million from the issuance of $500 million of
3.750% Senior Notes due 2028 and $150 million of 4.680% Senior Notes due 2045.
In October 2017, Phillips 66 Partners received net proceeds of $737 million from a private placement of
13,819,791 perpetual convertible preferred units, at a price of $54.27 per unit.
In October 2017, Phillips 66 Partners received net proceeds of $295 million from a private placement of
6,304,204 common units, at a price of $47.59 per unit.
In October 2016, Phillips 66 Partners received net proceeds of $1,111 million from the issuance of $500 million
of 3.550% Senior Notes due 2026 and $625 million of 4.900% Senior Notes due 2046.
In August 2016, Phillips 66 Partners received net proceeds of $299 million from a public offering of 6,000,000
common units, at a price of $50.22 per unit.
In June 2016, Phillips 66 Partners began issuing common units under a continuous offering program, which
allows for the offering of up to $250 million of common units. Through December 31, 2017, net proceeds of
$192 million had been received under this program.
In May 2016, Phillips 66 Partners received net proceeds of $656 million from a public offering of 12,650,000
common units, at a price of $52.40 per unit.
In February 2015, Phillips 66 Partners received net proceeds of $1,092 million from the issuance of $300 million
of 2.646% Senior Notes due 2020, $500 million of 3.605% Senior Notes due 2025, and $300 million of 4.680%
Senior Notes due 2045.
In February 2015, Phillips 66 Partners received net proceeds of $384 million from a public offering of 5,250,000
million common units, at a price of $75.50 per unit.
Phillips 66 Partners primarily used these net proceeds to fund the cash portion of acquisitions of assets from Phillips 66.
See Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on
Phillips 66 Partners and additional details on assets contributed to the partnership by us during 2017.
Phillips 66 Partners filed a new shelf registration statement for a second continuous offering program that became
effective with the Securities and Exchange Commission (SEC) on January 23, 2018, related to the continuous offering of
up to an aggregate of $250 million of common units, in amounts, at prices and on terms to be determined by the market
conditions and other factors at the time of the offerings.
Credit Facilities and Commercial Paper
Phillips 66 has a $5.0 billion revolving credit facility that extends until October 2021. This facility may be used for
direct bank borrowings, as support for issuances of letters of credit, or as support for our commercial paper program.
The facility is with a broad syndicate of financial institutions and contains covenants that we consider usual and
customary for an agreement of this type for comparable commercial borrowers, including a maximum consolidated net
debt-to-capitalization ratio of 60 percent. The agreement has customary events of default, such as nonpayment of
principal when due; nonpayment of interest, fees or other amounts; violation of covenants; cross-payment default and
cross-acceleration (in each case, to indebtedness in excess of a threshold amount); and a change of control. Borrowings
under the facility will incur interest at the London Interbank Offered Rate (LIBOR) plus a margin based on the credit
rating of our senior unsecured long-term debt as determined from time to time by Standard & Poor’s (S&P) Ratings
50
80
51
81
2017 PHILLIPS 66 ANNUAL REPORT Services and Moody’s Investors Service. The facility also provides for customary fees, including administrative agent
fees and commitment fees. At December 31, 2017, no amount had been drawn under this revolving credit agreement.
We have a $5.0 billion commercial paper program for short-term working capital needs that is supported by our revolving
credit facility. Commercial paper maturities are generally limited to 90 days. At December 31, 2017, we had no
borrowings under our commercial paper program.
Phillips 66 Partners has a $750 million revolving credit facility that extends until October 2021. The Phillips 66 Partners
facility is with a broad syndicate of financial institutions. At December 31, 2017, Phillips 66 Partners had no borrowings
outstanding under this facility.
Other Debt Issuances and Financings
In April 2017, Phillips 66 completed a private offering of $600 million aggregate principal amount of unsecured notes,
consisting of $300 million of Notes due 2019 and $300 million of Notes due 2020. Interest on the notes is a floating rate
equal to three-month LIBOR plus 0.65% per annum for the 2019 Notes and three-month LIBOR plus 0.75% per annum
for the 2020 Notes. Interest on both series of notes is payable quarterly in arrears on January 15, April 15, July 15 and
October 15, commencing in July 2017. The 2019 Notes mature on April 15, 2019, and the 2020 Notes mature on April
15, 2020.
Also in April 2017, Phillips 66 entered into term loan facilities with an aggregate borrowing amount of $900 million,
consisting of a $450 million 364-day facility and a $450 million three-year facility. Interest on the term loans is a
floating rate based on either the Eurodollar rate or the reference rate, plus a margin determined by our long-term credit
ratings.
Phillips 66 used the net proceeds from the issuance of the notes, together with the proceeds from the term loans, and cash
on-hand to repay its outstanding 2.950% Senior Notes upon maturity in May 2017.
In October 2017, as part of the contribution of assets to Phillips 66 Partners, discussed above, Phillips 66 Partners
assumed the $450 million term loan outstanding under the 364-day facility originally issued in April 2017, and
subsequently repaid the loan.
In addition, we have capital lease obligations related to equipment and transportation assets, and the use of an oil
terminal in the United Kingdom. These leases mature within the next sixteen years. The present value of our minimum
capital lease payments for these obligations as of December 31, 2017, was $192 million.
Availability of Debt and Equity Financing
The $6.0 billion of outstanding Senior Notes and $600 million of floating-rate notes issued by Phillips 66 are guaranteed
by Phillips 66 Company, a 100-percent-owned subsidiary. Our senior unsecured long-term debt has been rated
investment grade by S&P (BBB+) and Moody’s (A3). We do not have any ratings triggers on any of our corporate debt
that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our
credit rating. If our credit rating deteriorated to a level prohibiting us from accessing the commercial paper market, we
would expect to be able to access funds under our liquidity facilities mentioned above.
In addition, we have a universal shelf registration statement on file with the SEC under which we, as a well-known
seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
Off-Balance Sheet Arrangements
Under the operating lease agreement on our headquarters facility in Houston, Texas, we have a residual value guarantee
with a maximum future exposure of $554 million. The operating lease has a term of five years and provides us the
option, at the end of the lease term, to request to renew the lease, purchase the facility, or assist the lessor in marketing it
for resale.
We also have residual value guarantees associated with railcar and airplane leases with maximum future potential
payments of $305 million. For information on our need to perform under the railcar lease guarantee, see the “Capital
Requirements” section to follow.
In addition, we have guarantees outstanding related to certain joint-venture debt obligations, which have remaining terms
of up to eight years. The maximum potential amount of future payments to third parties under these guarantees is
approximately $308 million.
See Note 13—Guarantees, in the Notes to Consolidated Financial Statements, for additional information on our
guarantees.
Capital Requirements
Capital Expenditures and Investments
For information about our capital expenditures and investments, see “Capital Spending” below.
Debt Financing
Our debt balance at December 31, 2017, was $10.1 billion and our total debt-to-capital ratio was 27 percent. See Note 12
—Debt, in the Notes to Consolidated Financial Statements, for our annual debt maturities over the next five years.
Dividends
On February 7, 2018, our Board of Directors declared a quarterly cash dividend of $0.70 per common share, payable
March 1, 2018, to holders of record at the close of business on February 20, 2018.
Share Repurchases
Since July 2012, our Board of Directors has, at various times, authorized repurchases of our outstanding common stock
which aggregate to a total authorization of up to $12.0 billion. The share repurchases are expected to be funded primarily
through available cash. The shares will be repurchased from time to time in the open market at our discretion, subject to
market conditions and other factors, and in accordance with applicable regulatory requirements. We are not obligated to
acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or
from time to time without prior notice. Since the inception of our share repurchases in 2012, through December 31,
2017, we have repurchased a total of 124,142,530 shares at an aggregate cost of $9.0 billion. Shares of stock
repurchased are held as treasury shares.
On February 13, 2018, we entered into a Stock Purchase and Sale Agreement (Purchase Agreement) with Berkshire
Hathaway Inc. and National Indemnity Company, a wholly owned subsidiary of Berkshire Hathaway, to repurchase 35
million shares of Phillips 66 common stock for an aggregate purchase price of approximately $3.3 billion. Pursuant to
the Purchase Agreement, the purchase price per share of $93.725 was based on the volume-weighted-average price of our
common stock on the New York Stock Exchange on February 13, 2018. The transaction closed on February 14, 2018.
We funded the repurchase with cash on hand of approximately $1.9 billion and borrowings of approximately $1.4 billion
under our commercial paper program. This specific share repurchase transaction was separately authorized by our Board
of Directors and therefore does not impact previously announced authorizations which total up to $12.0 billion.
52
82
53
83
2017 PHILLIPS 66 ANNUAL REPORT Railcar and Airplane Leases Residual Value Guarantees
On May 1, 2015, the U.S. Department of Transportation issued a final rule focused on the safe transportation of
flammable liquids by rail. The final rule, which is being challenged, subjects new and existing railcars transporting crude
oil in high volumes to heightened design standards, including thicker tank walls and heat shields, improved pressure
relief valves and enhanced braking systems. We are currently evaluating the impact of the new regulations on our crude
oil railcar fleet, which is mostly held under operating leases. The regulations become effective subsequent to the
expiration dates of a portion of our leases. Some of our leases require a portion of the leased railcars to be retrofitted.
Certain leases are subject to residual value guarantees. Under the lease terms, we have the option to either purchase the
railcars or return them to the lessors. If railcars are returned to the lessors, we may be required to make the lessors whole
under the residual value guarantees, which are subject to a cap. The current market demand for crude oil railcars is low,
which has resulted in a decline in crude oil railcar prices. Based on third-party appraisals of the railcars’ fair value at the
end of their lease terms, we estimated a total residual value deficiency of $109 million that would be payable at the end
of the lease terms, with approximately one-half paid in late 2017 and the other half due in 2019. During 2017 and 2016,
we recognized $73 million of expense related to the residual value deficiency of our leased railcars. In October 2017,
upon maturity of one of our railcar leases, $53 million of the total residual value deficiency of $109 million was settled.
The residual value deficiency of $36 million remaining at December 31, 2017, will be recognized on a straight-line basis
through May 2019. Due to current market uncertainties, changes in the estimated fair values of railcars could occur,
which could increase or decrease our currently estimated residual value deficiency. As of December 31, 2017, our
maximum future exposure for residual value guarantees associated with our railcar and airplane leases was
approximately $305 million. See Note 13—Guarantees, in the Notes to Consolidated Financial Statements.
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2017:
Millions of Dollars
Payments Due by Period
Up to
1 Year
25
16
41
436
533
32,236
7
78
1
33,332
Years
2-3
1,375
27
1,402
839
726
9,554
30
117
(d)
12,668
Years
4-5
2,050
22
2,072
765
241
6,698
18
72
(d)
9,866
After
5 Years
6,576
127
6,703
5,331
326
29,195
213
191
(d)
41,959
Total
10,026
192
10,218
7,371
1,826
77,683
268
458
1
97,825
$
$
Debt obligations (a)
Capital lease obligations
Total debt
Interest on debt
Operating lease obligations
Purchase obligations (b)
Other long-term liabilities (c)
Asset retirement obligations
Accrued environmental costs
Unrecognized income tax benefits (d)
Total
(a) For additional information, see Note 12—Debt, in the Notes to Consolidated Financial Statements.
(b) Represents any agreement to purchase goods or services that is enforceable, legally binding and specifies all
significant terms. We expect these purchase obligations will be fulfilled by operating cash flows in the
applicable maturity period. The majority of the purchase obligations are market-based contracts, including
exchanges and futures, for the purchase of products such as crude oil and unfractionated NGL. The products are
mostly used to supply our refineries and fractionators, optimize the supply chain, and resell to customers.
Product purchase commitments with third parties totaled $35,480 million. In addition, $24,230 million are
product purchases from CPChem, mostly for natural gas and NGL over the remaining contractual term of 82
years, and product purchases of $1,652 million from DCP entities for NGL over the remaining contractual term
of three years.
Purchase obligations of $5,097 million are related to agreements to access and utilize the capacity of third-party
equipment and facilities, including pipelines and product terminals, to transport, process, treat, and store
products. The remainder is primarily our net share of purchase commitments for materials and services for
jointly owned facilities where we are the operator.
(c) Excludes pensions. From 2018 through 2022, we expect to contribute an average of $70 million per year to our
qualified and nonqualified pension and other postretirement benefit plans in the United States and an average of
$34 million per year to our non-U.S. plans, which are expected to be in excess of required minimums in many
cases. The U.S. five-year average consists of $60 million for 2018 and then approximately $75 million per year
for the remaining four years. Our minimum funding in 2018 is expected to be $60 million in the United States
and $35 million outside the United States.
(d) Excludes unrecognized income tax benefits of $33 million because the ultimate disposition and timing of any
payments to be made with regard to such amounts are not reasonably estimable or the amounts relate to potential
refunds. Also excludes interest and penalties of $8 million. Although unrecognized income tax benefits are not
a contractual obligation, they are presented in this table because they represent potential demands on our
liquidity.
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2017 PHILLIPS 66 ANNUAL REPORT
Capital Spending
Capital Expenditures and Investments
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Selected Equity Affiliates*
DCP Midstream
CPChem
WRB
* Our share of capital spending.
2018
Budget
1,218
—
827
140
116
2,301
405
398
143
946
$
$
$
$
Millions of Dollars
2017
771
—
853
108
100
1,832
268
776
126
1,170
2016
1,453
—
1,149
98
144
2,844
99
987
164
1,250
2015
4,457
—
1,069
122
116
5,764
438
1,319
175
1,932
Midstream
Capital spending in our Midstream segment during the three-year period ended December 31, 2017, included:
• Construction activities related to the Sweeny Fractionator and Freeport LPG Export Terminal projects.
• Bakken Pipeline project, developed by our 25-percent-owned joint ventures, Dakota Access, LLC and Energy
Transfer Crude Oil Company.
• Construction activities related to increasing storage capacity at our crude oil and petroleum products terminal
located near Beaumont, Texas.
• Acquisition by Phillips 66 Partners of certain southeast Louisiana NGL logistics assets comprising
approximately 500 miles of pipelines and a storage cavern connecting multiple fractionation facilities, refineries
and a petrochemical facility.
• Development of the Bayou Bridge Pipeline by Phillips 66 Partners’ 40-percent-owned joint venture.
• Construction activities by joint ventures of Phillips 66 Partners in the Bakken production area of North Dakota,
including the Palermo Rail Terminal, Sacagawea Crude Pipeline, the New Town injection point, Keene CDP
Terminal and Sacagawea Gas Pipeline.
• Expansion activities on the Phillips 66 Partners’ 33-percent-owned Sand Hills Pipeline including investment in
the transportation of NGL from the Permian Basin to the Texas Gulf Coast.
• Expansion activities on the Phillips 66 Partners’ 50-percent-owned STACK Pipeline joint venture.
•
Spending associated with return, reliability and maintenance projects in our Transportation and NGL and Other
businesses.
During the three-year period ended December 31, 2017, DCP Midstream’s capital expenditures and investments were
$1.6 billion on a 100 percent basis. In 2015, we contributed $1.5 billion of cash to DCP Midstream and our co-venturer
contributed its interests in certain operating assets of equal value, that are held as equity investments. Upon completion
of this transaction, our interest in DCP Midstream remained at 50 percent.
In 2015, REX repaid $450 million of its debt, reducing its long-term debt to approximately $2.6 billion. REX funded the
repayment through member cash contributions. Our 25 percent share was approximately $112 million, which we
contributed to REX in 2015.
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Chemicals
During the three-year period ended December 31, 2017, CPChem had a self-funded capital program, and thus required no
new capital infusions from us or our co-venturer. During this period, on a 100 percent basis, CPChem’s capital
expenditures and investments were $6.2 billion. In addition, CPChem’s advances to its equity affiliates, primarily used
for project construction and start-up activities, were $139 million and its repayments received from equity affiliates were
$140 million.
Refining
Capital spending for the Refining segment during the three-year period ended December 31, 2017, was $3.1 billion,
primarily for air emission reduction and clean fuels projects to meet new environmental standards, refinery upgrade
projects to increase accessibility of advantaged crudes and improve product yields, improvements to the operating
integrity of key processing units, and safety-related projects.
Key projects completed during the three-year period included:
•
•
•
•
Installation of a tail gas treating unit at the Humber Refinery to reduce emissions from the sulfur recovery units.
Installation of facilities to improve clean product yields at the Sweeny, Lake Charles and Ponca City refineries.
Installation of facilities to improve processing of advantaged crudes at the Billings and Ponca City refineries, as
well as the jointly owned Wood River Refinery.
Installation of facilities to comply with U.S. Environmental Protection Agency (EPA) Tier 3 gasoline regulations
at the Alliance, Lake Charles and Sweeny refineries, as well as the jointly owned Wood River Refinery.
•
Installation of a crude tank to increase accessibility of waterborne crude at the Los Angeles Refinery.
Major construction activities in progress include:
•
•
•
Installation of facilities to comply with EPA Tier 3 gasoline regulations at the Bayway and Ferndale refineries.
Installation of facilities to improve processing of advantaged crudes at the Lake Charles Refinery.
Installation of facilities to improve clean product yield at the Bayway Refinery, as well as the jointly owned
Wood River Refinery.
Generally, our equity affiliates in the Refining segment are intended to have self-funding capital programs. During this
three-year period, on a 100 percent basis, WRB’s capital expenditures and investments were $930 million. We expect
WRB’s 2018 capital program to be self-funding.
Marketing and Specialties
Capital spending for the M&S segment during the three-year period ended December 31, 2017, was primarily for the
acquisition of and investments in projects targeted at developing our new international sites. In addition, capital is used
for reliability and maintenance projects at our Lubricants facilities.
Corporate and Other
Capital spending for Corporate and Other during the three-year period ended December 31, 2017, was primarily for
projects related to information technology and facilities.
2018 Budget
Our 2018 capital budget is $2.3 billion including Phillips 66 Partners’ capital budget of $0.6 billion. This excludes our
portion of planned capital spending by joint ventures DCP Midstream, CPChem and WRB totaling $0.9 billion, all of
which is expected to be self-funded.
The Midstream capital budget of $1.2 billion is focused on projects integrated with our existing assets and infrastructure,
including continued expansion of the Beaumont Terminal, additional Gulf Coast fractionation capacity and investment in
pipelines and other terminals. The Midstream capital budget also includes Phillips 66 Partners’ growth projects,
including expansions of the Sand Hills and Bayou Bridge pipelines, and construction of an isomerization unit at our Lake
Charles Refinery. Refining’s capital budget of $0.8 billion is primarily directed toward reliability, safety and
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environmental projects, as well as small, high-return, quick payout projects, primarily to improve clean product yields.
In M&S, we plan to invest approximately $0.1 billion, primarily directed towards increasing retail sites in Europe. In
Corporate and Other, we plan to fund approximately $0.1 billion in projects primarily related to information technology
and facilities.
Contingencies
A number of lawsuits involving a variety of claims that arose in the ordinary course of business have been filed against
us or are subject to indemnifications provided by us. We also may be required to remove or mitigate the effects on the
environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at
various active and inactive sites. We regularly assess the need for financial recognition or disclosure of these
contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability
when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and
no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do
not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for
probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative
probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to known contingent liability
exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated
financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to
accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent
liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation
costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent
of such remedial actions that may be required, and the determination of our liability in proportion to that of other
potentially responsible parties. Estimated future costs related to tax and legal matters are subject to change as events
evolve and as additional information becomes available during the administrative and litigation processes.
Legal and Tax Matters
Our legal and tax matters are handled by our legal and tax organizations. These organizations apply their knowledge,
experience and professional judgment to the specific characteristics of our cases and uncertain tax positions. We employ
a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the
early evaluation and quantification of potential exposures in individual cases and enables the tracking of those cases that
have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation
management tools and available information about current developments in all our cases, our legal organization regularly
assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new
accruals, is required. In the case of income-tax-related contingencies, we monitor tax legislation and court decisions, the
status of tax audits and the statute of limitations within which a taxing authority can assert a liability. See Note 21—
Income Taxes, in the Notes to Consolidated Financial Statements, for additional information about income-tax-related
contingencies.
Environmental
Like other companies in our industry, we are subject to numerous international, federal, state and local environmental
laws and regulations. Among the most significant of these international and federal environmental laws and regulations
are the:
• U.S. Federal Clean Air Act, which governs air emissions.
• U.S. Federal Clean Water Act, which governs discharges into water bodies.
• European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH),
which governs the manufacture, placing on the market or use of chemicals.
• U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which
imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous
substance releases have occurred or are threatening to occur.
• U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage and disposal
of solid waste.
• U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report
toxic chemical inventories to local emergency planning committees and response departments.
• U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and
pipelines as well as owners and operators of vessels are liable for removal costs and damages that result from a
discharge of oil into navigable waters of the United States.
• European Union Trading Directive resulting in the European Union Emissions Trading Scheme (EU ETS), which
uses a market-based mechanism to incentivize the reduction of greenhouse gas emissions.
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish
water quality limits. They also, in most cases, require permits in association with new or modified operations. These
permits can require an applicant to collect substantial information in connection with the application process, which can
be expensive and time consuming. In addition, there can be delays associated with notice and comment periods and the
agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control
of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar environmental laws and
regulations governing these same types of activities. While similar, in some cases these regulations may impose
additional, or more stringent, requirements that can add to the cost and difficulty of developing infrastructure and
marketing and transporting products across state and international borders. For example, in California the South Coast
Air Quality Management District (SCAQMD) approved amendments to the Regional Clean Air Incentives Market
(RECLAIM) that became effective in 2016, which require a phased reduction of nitrogen oxide emissions through 2022
and potentially affect refineries in the Los Angeles metropolitan area. In 2017, SCAQMD required additional nitrogen
dioxide emissions reductions through 2025 and began evaluating if and how to replace the RECLAIM program with a
traditional command and controls regulatory regime.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily
determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations,
continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns
about global climate change, are expected to continue to have an increasing impact on our operations in the United States
and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and
remediation obligations in the United States.
An example of this in the fuels area is the Energy Independence and Security Act of 2007 (EISA). It requires fuel
producers and importers to provide additional renewable fuels for transportation motor fuels and stipulates a mix of
various types to be included through 2022. We have met the increasingly stringent requirements to date while
establishing implementation, operating and capital strategies, along with advanced technology development, to address
projected future requirements. It is uncertain how various future requirements contained in EISA, and the regulations
promulgated thereunder, may be implemented and what their full impact may be on our operations. For the 2018
compliance year, the EPA has set volumes of advanced and total renewable fuel at higher levels than mandated in most
previous years (although the 2018 compliance year volumes are roughly equivalent to those required for the 2017
compliance year); it is uncertain if these increased obligations will be achievable by fuel producers and shippers without
drawing on the Renewable Identification Number (RIN) bank. For compliance years after 2018, we do not know
whether the EPA will utilize its authority to reduce statutory volumes. Additionally, we may experience a decrease in
demand for refined petroleum products due to the regulatory program as currently promulgated. This program continues
to be the subject of possible Congressional review and re-promulgation in revised form, and the EPA’s regulations
pertaining to the 2014 through 2017 compliance years are subject to legal challenge, further creating uncertainty
regarding renewable fuel volume requirements and obligations. Additionally, the market for RINs has been the subject of
fraudulent third-party activity, and it is reasonably possible that some RINs that we have purchased may be determined to
be invalid. Should that occur, we could incur costs to replace those fraudulent RINs. Although the cost for replacing any
fraudulently marketed RINs is not reasonably estimable at this time, we would not expect to incur the full financial
impact of fraudulent RINs replacement costs in any single interim or annual period, and would not expect such costs to
have a material impact on our results of operations or financial condition.
We also are subject to certain laws and regulations relating to environmental remediation obligations associated with
current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents.
Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks
located at numerous previously and currently owned and/or operated petroleum-marketing outlets throughout the United
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States. Federal and state laws require contamination caused by such underground storage tank releases be assessed and
remediated to meet applicable standards. In addition to other cleanup standards, many states have adopted cleanup
criteria for methyl tertiary-butyl ether for both soil and groundwater.
At RCRA-permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be
required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as
“Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by
us. We anticipate increased expenditures for RCRA remediation activities may be required, but such annual expenditures
for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the
past few years. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.
We occasionally receive requests for information or notices of potential liability from the EPA and state environmental
agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion,
we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests,
notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but
allegedly contain wastes attributable to our past operations. As of December 31, 2016, we reported that we had been
notified of potential liability under CERCLA and comparable state laws at 31 sites within the United States. During
2017, there were three new sites for which we received notification of potential liability, and three sites were deemed
resolved and closed, leaving 31 unresolved sites with potential liability at December 31, 2017.
For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the
percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low.
Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for
state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to
meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share
of liability has not increased materially. Many of the sites for which we are potentially responsible are still under
investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally
assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may
have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or
equivalent state agency approval of a remediation plan. There are relatively few sites where we are a major participant,
and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs
at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial
condition.
Expensed environmental costs were $690 million in 2017 and are expected to be approximately $670 million and $640
million in 2018 and 2019, respectively. Capitalized environmental costs were $159 million in 2017 and are expected to
be approximately $185 million and $135 million, in 2018 and 2019, respectively. This amount does not include capital
expenditures made for another purpose that have an indirect benefit on environmental compliance.
Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties
and are not discounted (except those assumed in a business combination, which we record on a discounted basis).
Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain
investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where our
generated waste was disposed. We also have accrued for a number of sites we identified that may require environmental
remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable,
we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs
under both CERCLA and RCRA. Remediation activities vary substantially in duration and cost from site to site,
depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and
enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop
reasonable estimates of future site remediation costs.
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs
and liabilities are inherent concerns in certain of our operations and products, and there can be no assurance that material
costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect on our results
of operations or financial position as a result of compliance with current environmental laws and regulations.
Climate Change
There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse
gas (GHG) emissions reduction, including various regulations proposed or issued by the EPA. These proposed or
promulgated laws apply or could apply in states and/or countries where we have interests or may have interests in the
future. Laws regulating GHG emissions continue to evolve, and while it is not possible to accurately estimate either a
timetable for implementation or our future compliance costs relating to implementation, such laws potentially could have
a material impact on our results of operations and financial condition as a result of increasing costs of compliance,
lengthening project implementation and agency review items, or reducing demand for certain hydrocarbon products.
Examples of legislation or precursors for possible regulation that do or could affect our operations include:
• EU ETS, which is part of the European Union’s policy to combat climate change and is a key tool for reducing
industrial greenhouse gas emissions. EU ETS impacts factories, power stations and other installations across all
EU member states.
• California’s Global Warming Solutions Act, which requires the California Air Resources Board to develop
regulations and market mechanisms that will target reduction of California’s GHG emissions by 25 percent by
2020 (as well as SB32, which requires further reduction of California's GHG emissions to 40 percent below the
1990 emission level by 2030, and the recently-enacted AB398, which extends the California GHG emission cap-
and-trade program through 2030). Other GHG emissions programs in the western U.S. states have been enacted or
are under consideration or development, including amendments to California's Low Carbon Fuel Standard,
Oregon's Low Carbon Fuel Standard, and Washington's carbon reduction programs.
• The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S. Ct. 1438 (2007), confirming that
the EPA has the authority to regulate carbon dioxide as an “air pollutant” under the Federal Clean Air Act.
• The EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine
Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s
and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that triggers
regulation of GHGs under the Clean Air Act. These collectively may lead to more climate-based claims for
damages, and may result in longer agency review time for development projects to determine the extent of
potential climate change.
• EPA's 2015 Final Rule regulating GHG emissions from existing fossil fuel-fired electrical generating units under
the Federal Clean Air Act, commonly referred to as the Clean Power Plan.
• Carbon taxes in certain jurisdictions.
• GHG emission cap and trade programs in certain jurisdictions.
In the EU, the first phase of the EU ETS completed at the end of 2007 and Phase II was undertaken from 2008 through to
2012. The current phase (Phase III) runs from 2013 through to 2020, with the main changes being reduced allocation of
free allowances and increased auctioning of new allowances. Phillips 66 has assets that are subject to the EU ETS, and
the company is actively engaged in minimizing any financial impact from the EU ETS.
From November 30 to December 12, 2015, more than 190 countries, including the United States, participated in the
United Nations Climate Change Conference in Paris, France. The conference culminated in what is known as the “Paris
Agreement,” which, upon certain conditions being met, entered into force on November 4, 2016. The Paris Agreement
establishes a commitment by signatory parties to pursue domestic GHG emission reductions. In 2017, the President of
the United States announced his intention to withdraw the United States from the Paris Agreement.
In the United States, some additional form of regulation is likely to be forthcoming in the future at the state or federal
levels with respect to GHG emissions. Such regulation could take any of several forms that may result in the creation of
additional costs in the form of taxes, the restriction of output, investments of capital to maintain compliance with laws
and regulations, or required acquisition or trading of emission allowances. We are working to continuously improve
operational and energy efficiency through resource and energy conservation throughout our operations.
Compliance with changes in laws and regulations that create a GHG emission trading program, GHG reduction
requirements or carbon taxes could significantly increase our costs, reduce demand for fossil energy derived products,
impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also
increase demand for less carbon intensive energy sources.
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An example of one such program is California’s cap and trade program, which was promulgated pursuant to the State’s
Global Warming Solutions Act. The program had been limited to certain stationary sources, which include our refineries
in California, but beginning in January 2015 expanded to include emissions from transportation fuels distributed in
California. Inclusion of transportation fuels in California’s cap and trade program as currently promulgated has increased
our cap and trade program compliance costs. The ultimate impact on our financial performance, either positive or
negative, from this and similar programs, will depend on a number of factors, including, but not limited to:
• Whether and to what extent legislation or regulation is enacted.
• The nature of the legislation or regulation (such as a cap and trade system or a tax on emissions).
• The GHG reductions required.
• The price and availability of offsets.
• The demand for, and amount and allocation of allowances.
• Technological and scientific developments leading to new products or services.
• Any potential significant physical effects of climate change (such as increased severe weather events, changes in
sea levels and changes in temperature).
• Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products
and services.
We consider and take into account anticipated future GHG emissions in designing and developing major facilities and
projects, and implement energy efficiency initiatives to reduce GHG emissions. Data on our GHG emissions, legal
requirements regulating such emissions, and the possible physical effects of climate change on our coastal assets are
incorporated into our planning, investment, and risk management decision-making.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires
management to select appropriate accounting policies and to make estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues and expenses. See Note 1—Summary of Significant Accounting Policies, in the
Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these
accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that
materially different amounts would have been reported under different conditions, or if different assumptions had been
used. The following discussion of critical accounting estimates, along with the discussion of contingencies in this report,
address all important accounting areas where the nature of accounting estimates or assumptions could be material due to
the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such
matters to change.
Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a
possible significant deterioration in future cash flows is expected. If the sum of the undiscounted pre-tax cash flows of
an asset group is less than the carrying value, including applicable liabilities, the carrying value is written down to
estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the
lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of
assets (for example, at a refinery complex level). Because there usually is a lack of quoted market prices for long-lived
assets, the fair value of impaired assets is typically determined using one or more of the following methods: the present
value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used
by principal market participants; a market multiple of earnings for similar assets; or historical market transactions of
similar assets, adjusted using principal market participant assumptions when necessary. The expected future cash flows
used for impairment reviews and related fair value calculations are based on judgmental assessments of future volumes,
commodity prices, operating costs, margins, discount rates and capital project decisions, considering all available
information at the date of review.
Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment when there
are indicators of a loss in value, such as a lack of sustained earnings capacity or a current fair value less than the
investment’s carrying amount. When it is determined that an indicated impairment is other than temporary, a charge is
recognized for the difference between the investment’s carrying value and its estimated fair value.
When determining whether a decline in value is other than temporary, management considers factors such as the length
of time and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention
to retain our investment for a period that allows for recovery. When quoted market prices are not available, the fair value
is usually based on the present value of expected future cash flows using discount rates and other assumptions believed to
be consistent with those used by principal market participants and a market analysis of comparable assets, if appropriate.
Differing assumptions could affect the timing and the amount of an impairment of an investment in any period.
Asset Retirement Obligations
Under various contracts, permits and regulations, we have legal obligations to remove tangible equipment and restore the
land at the end of operations at certain operational sites. Our largest asset removal obligations involve asbestos
abatement at refineries. Estimating the timing and amount of payments for future asset removal costs is difficult. Most
of these removal obligations are many years, or decades, in the future, and the contracts and regulations often have vague
descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal
technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into
valuation of the obligation, including discount and inflation rates, are also subject to change.
Environmental Costs
In addition to asset retirement obligations discussed above, we have certain obligations to complete environmental-
related projects. These projects are primarily related to cleanup at domestic refineries, underground storage sites and
non-operated sites. Future environmental remediation costs are difficult to estimate because they are subject to change
due to such factors as the uncertain magnitude of cleanup costs, timing and extent of such remedial actions that may be
required, and the determination of our liability in proportion to that of other responsible parties.
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2017 PHILLIPS 66 ANNUAL REPORT
Intangible Assets and Goodwill
At December 31, 2017, we had $756 million of intangible assets that we have determined to have indefinite useful lives,
and therefore are not amortized. This judgmental assessment of an indefinite useful life must be continuously evaluated
in the future. If, due to changes in facts and circumstances, management determines these intangible assets have finite
useful lives, amortization will commence at that time on a prospective basis. As long as these intangible assets are
judged to have indefinite lives, they will be subject to annual impairment tests that require management’s judgment of the
estimated fair value of these intangible assets.
At December 31, 2017, we had $3.3 billion of goodwill recorded in conjunction with past business combinations.
Goodwill is not amortized. Instead, goodwill is subject to at least annual reviews for impairment at a reporting unit level.
The reporting units used to evaluate and measure goodwill for impairment are determined primarily from the manner in
which the business is managed. A reporting unit is an operating segment or a component that is one level below an
operating segment.
Because quoted market prices for our reporting units are not available, management applies judgment in determining the
estimated fair values of the reporting units for purposes of performing the goodwill impairment test. Management uses
all available information to make this fair value determination, including observed market earnings multiples of
comparable companies, our common stock price and associated total company market capitalization. Sales or
dispositions of significant assets within a reporting unit are allocated a portion of that reporting unit’s goodwill, based on
relative fair values, which impacts the amount of gain or loss on the sale or disposition.
We completed our annual impairment test as of October 1, 2017, and concluded that the fair value of each of our
reporting units continued to exceed their respective recorded net book values by a significant percentage. A decline in the
estimated fair value of one or more of our reporting units in the future could result in an impairment. For example, a
prolonged or significant decline in our stock price or a significant decline in actual or forecasted earnings could provide
evidence of a significant decline in fair value and a need to record a material impairment of goodwill for one or more of
our reporting units. After we have completed our annual test, we continue to monitor for impairment indicators, which
can lead to further goodwill impairment testing.
Tax Assets and Liabilities
Our operations are subject to various taxes, including federal, state and foreign income taxes, property taxes, and
transactional taxes such as excise, sales/use and payroll taxes. We record tax liabilities based on our assessment of
existing tax laws and regulations. The recording of tax liabilities requires significant judgment and estimates. We
recognize the financial statement effects of an income tax position when it is more likely than not that the position will be
sustained upon examination by a taxing authority. A contingent liability related to a transactional tax claim is recorded if
the loss is both probable and estimable. Actual incurred tax liabilities can vary from our estimates for a variety of
reasons, including different interpretations of tax laws and regulations and different assessments of the amount of tax due.
In determining our income tax expense (benefit), we assess the likelihood our deferred tax assets will be recovered
through future taxable income. Valuation allowances reduce deferred tax assets to an amount that will, more likely than
not, be realized. Judgment is required in estimating the amount of valuation allowance, if any, that should be recorded
against our deferred tax assets. Based on our historical taxable income, our expectations for the future, and available tax-
planning strategies, we expect the net deferred tax assets will more likely than not be realized as offsets to reversing
deferred tax liabilities and as reductions to future taxable income. If our actual results of operations differ from such
estimates or our estimates of future taxable income change, the valuation allowance may need to be revised.
New tax laws and regulations, as well as changes to existing tax laws and regulations, are continuously being proposed or
promulgated. The implementation of future legislative and regulatory tax initiatives could result in increased income tax
liabilities that cannot be predicted at this time. The material provisions of the Tax Act i) reduced the U.S. federal
corporate income tax rate from 35 percent to 21 percent beginning January 1, 2018, ii) imposed a one-time deemed
repatriation tax on foreign-sourced earnings that were previously tax deferred, and iii) created a new tax regime on
post-2017 foreign-sourced earnings. We have not yet completed our accounting for the income tax effects of the Tax Act
as of December 31, 2017, but have made reasonable estimates of those effects on our existing deferred income tax
balances and the one-time deemed repatriation tax. As more guidelines and interpretations of the Tax Act become
available over the next year, the estimates previously made may change, which could increase or decrease our revalued
deferred income tax balances and the one-time deemed repatriation tax, with an offset to earnings.
Projected Benefit Obligations
Determination of the projected benefit obligations for our defined benefit pension and postretirement plans impacts the
obligations on the balance sheet and the amount of benefit expense in the income statement. The actuarial determination
of projected benefit obligations and company contribution requirements involves judgment about uncertain future events,
including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return
on plan assets, future interest rates, future health care cost-trend rates, and rates of utilization of health care services by
retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the
determination of these projected benefit obligations and company contribution requirements. Due to differing objectives
and requirements between financial accounting rules and the pension plan funding regulations promulgated by
governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects.
Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded
by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect
periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate
and return on plan assets assumptions. A one percentage-point decrease in the discount rate assumption would increase
annual benefit expense by an estimated $65 million, while a one percentage-point decrease in the return on plan assets
assumption would increase annual benefit expense by an estimated $35 million. In determining the discount rate, we use
yields on high-quality fixed income investments with payments matched to the estimated distributions of benefits from
our plans.
In 2017 and 2016, our expected weighted-average long-term rate of return was approximately 6 percent for our
worldwide pension plan assets. The actual weighted-average rate of return was 15 percent and 10 percent in 2017 and
2016, respectively. For the past ten years, our weighted-average actual rate of return was 7 percent for worldwide
pension plan assets.
NEW ACCOUNTING STANDARDS
In February 2017, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No.
2017-05, “Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20).” This
ASU clarifies the scope and accounting for the sale or transfer of nonfinancial assets and in substance nonfinancial assets
to noncustomers, including partial sales. This ASU will eliminate the use of carryover basis for most nonmonetary
exchanges, including contributions of assets to equity method joint ventures. These amendments could result in the
entity recognizing a gain or loss on the sale or transfer of nonfinancial assets. Public entities should apply the guidance
in ASU No. 2017-05 to annual periods beginning after December 15, 2017, including interim periods within those
periods. There was no impact on our financial statements from adopting this ASU on January 1, 2018.
In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a
Business,” which clarifies the definition of a business with the objective of adding guidance to assist in evaluating
whether transactions should be accounted for as acquisitions of assets or businesses. The amendment provides a screen
for determining when a transaction involves an acquisition of a business. If substantially all of the fair value of the gross
assets acquired is concentrated in a single identifiable asset, or a group of similar identifiable assets, then the transaction
is not considered an acquisition of a business. If the screen is not met, then the amendment requires that to be considered
a business, the operation must include at a minimum an input and a substantive process that together significantly
contribute to the ability to create an output. The guidance may reduce the number of transactions accounted for as
business acquisitions. Public business entities should apply the guidance in ASU No. 2017-01 to annual periods
beginning after December 15, 2017, including interim periods within those periods, with early adoption permitted. The
amendments should be applied prospectively and no disclosures are required at the effective date. There was no impact
on our financial statements from adopting this ASU on January 1, 2018.
In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of
Credit Losses on Financial Instruments.” The new standard amends the impairment model to utilize an expected loss
methodology in place of the currently used incurred loss methodology, which may result in earlier recognition of losses.
Public business entities should apply the guidance in ASU No. 2016-13 for annual periods beginning after December 15,
2019, including interim periods within those annual periods. Early adoption will be permitted for annual periods
beginning after December 15, 2018. We are currently evaluating the provisions of ASU No. 2016-13 and assessing the
impact on our financial statements.
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2017 PHILLIPS 66 ANNUAL REPORT In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” The new standard establishes a right-of-use
(ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with
terms longer than 12 months. Leases will continue to be classified as either finance or operating, with classification
affecting the pattern of expense recognition in the income statement. Similarly, lessors will be required to classify leases
as sales-type, finance or operating, with classification affecting the pattern of income recognition. Classification for both
lessees and lessors will be based on an assessment of whether risks and rewards as well as substantive control have been
transferred through a lease contract. Public business entities should apply the guidance in ASU No. 2016-02 for annual
periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is
permitted. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional
practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or entered into
after the earliest comparative period presented in the financial statements. We are currently evaluating the provisions of
ASU No. 2016-02 and assessing its impact on our financial statements. As part of our assessment to-date, we have
formed an implementation team, commenced identification of our lease population and selected a lease software package.
We expect the adoption of ASU 2016-02 will materially gross up our consolidated balance sheet with the recognition of
the ROU assets and operating lease liabilities. The impact to our consolidated statements of income and cash flows is not
expected to be material. The new standard will also require additional disclosures for financing and operating leases.
In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments—Overall (Subtopic 825-10): Recognition
and Measurement of Financial Assets and Financial Liabilities,” to meet its objective of providing more decision-useful
information about financial instruments. The majority of this ASU’s provisions amend only the presentation or
disclosures of financial instruments; however, one provision will also affect net income. Equity investments carried
under the cost method or lower of cost or fair value method of accounting, in accordance with current GAAP, will have to
be carried at fair value upon adoption of ASU No. 2016-01, with changes in fair value recorded in net income. For equity
investments that do not have readily determinable fair values, a company may elect to carry such investments at cost less
impairments, if any, adjusted up or down for price changes in similar financial instruments issued by the investee, when
and if observed. Public business entities should apply the guidance in ASU No. 2016-01 for annual periods beginning
after December 15, 2017, and interim periods within those annual periods, with early adoption prohibited. We are
currently evaluating the provisions of ASU No. 2016-01. Our initial review indicates that ASU No. 2016-01 will have a
limited impact on our financial statements.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This ASU
and other related updates are intended to improve comparability of revenue recognition practices across entities,
industries, jurisdictions and capital markets and expand disclosure requirements. In August 2015, the FASB issued ASU
No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The amendment in
this ASU defers the effective date of ASU No. 2014-09 for all entities for one year. Public business entities should apply
the guidance in ASU No. 2014-09 to annual reporting periods beginning after December 15, 2017, including interim
reporting periods within that reporting period. Our assessment work primarily included the formation of an
implementation work team, training on the new ASU’s revenue recognition model, contract review and documentation
and the monitoring of industry interpretative issues. We adopted the standard on January 1, 2018, using the modified
retrospective application. Our evaluation of the new ASU is near completion, which includes understanding the impact
of adoption on earnings from equity method investments. Based upon our analysis to-date, the primary impact of
adoption of the new standard is the netting of sales-based taxes collected from our customers against revenue. Sales-
based taxes include excise taxes on sales of petroleum products as noted on our consolidated statement of income. We
have not identified any other material impact on our financial statements other than disclosures.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Financial Instrument Market Risk
We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our cash
flows or earnings to changes in commodity prices, foreign currency exchange rates or interest rates. We may use
financial- and commodity-based derivative contracts to manage the risks produced by changes in the prices of crude oil
and related products, natural gas, NGL, and electric power; fluctuations in interest rates and foreign currency exchange
rates; or to capture market opportunities.
Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board of
Directors, that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient market
liquidity for comparable valuations. The Authority Limitations document also establishes Value at Risk (VaR) limits, and
compliance with these limits is monitored daily. Our Chief Financial Officer monitors risks resulting from foreign
currency exchange rates and interest rates. Our Executive Vice President, Marketing and Commercial monitors
commodity price risk. The Commercial organization manages our commercial marketing, optimizes our commodity
flows and positions, and monitors related risks of our businesses.
Commodity Price Risk
We sell into or receive supply from the worldwide crude oil, refined products, natural gas, NGL, and electric power
markets, exposing our revenues, purchases, cost of operating activities, and cash flows to fluctuations in the prices for
these commodities. Generally, our policy is to remain exposed to the market prices of commodities. Consistent with this
policy, our Commercial organization uses derivative contracts to effectively convert our exposure from fixed-price sales
contracts, often requested by refined product customers, back to fluctuating market prices. Conversely, our Commercial
organization also uses futures, forwards, swaps and options in various markets to accomplish the following objectives to
optimize the value of our supply chain, and this may reduce our exposure to fluctuations in market prices:
•
In addition to cash settlement prior to contract expiration, exchange-traded futures contracts may be settled by
physical delivery of the commodity. This provides another source of supply to balance physical systems or to meet
our refinery requirements and marketing demand.
• Manage the risk to our cash flows from price exposures on specific crude oil, refined product, natural gas, NGL,
and electric power transactions.
• Enable us to use the market knowledge gained from these activities to capture market opportunities such as moving
physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and
blending commodities to capture quality upgrades. Derivatives may be utilized to optimize these activities.
We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of
adverse changes in market conditions on the derivative financial instruments and derivative commodity instruments held
or issued, including commodity purchase and sales contracts recorded on the balance sheet at December 31, 2017, as
derivative instruments. Using the Monte Carlo simulation, a 95 percent confidence level and a one-day holding period,
the VaR for those instruments issued or held for trading purposes at December 31, 2017 and 2016, was immaterial to our
cash flows and net income. The VaR for instruments held for purposes other than trading at December 31, 2017 and 2016,
was also immaterial to our cash flows and net income.
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2017 PHILLIPS 66 ANNUAL REPORT Interest Rate Risk
Our use of fixed- or variable-rate debt directly exposes us to interest rate risk. Fixed-rate debt, such as our senior notes,
exposes us to changes in the fair value of our debt due to changes in market interest rates. Fixed-rate debt also exposes
us to the risk that we may need to refinance maturing debt with new debt at higher rates, or that we may be obligated to
pay rates higher than the current market. Variable-rate debt, such as our floating-rate notes or borrowings under our
revolving credit facility, exposes us to short-term changes in market rates that impact our interest expense. The following
tables provide information about our debt instruments that are sensitive to changes in U.S. interest rates. These tables
present principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average
variable rates are based on effective rates at the reporting date. The carrying amount of our floating-rate debt
approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on observable market
prices.
Expected Maturity Date
Year-End 2017
2018
2019
2020
2021
2022
Remaining years
Total
Fair value
Expected Maturity Date
Year-End 2016
2017
2018
2019
2020
2021
Remaining years
Total
Fair value
Millions of Dollars, Except as Indicated
Fixed Rate
Maturity
Average
Interest
Rate
Floating Rate
Maturity
Average
Interest
Rate
—
—
300
—
2,000
6,576
8,876
9,746
—% $
—
2.65
—
4.30
4.78
$
$
1.94%
2.01
2.31
1.94
—
—
25
300
775
50
—
—
1,150
1,150
Millions of Dollars, Except as Indicated
Fixed Rate
Maturity
Average
Interest
Rate
Floating Rate
Maturity
Average
Interest
Rate
516
518
18
816
—
7,926
9,794
10,260
3.08%
2.39
7.00
2.76
—
4.72
$
$
$
1.80%
0.80
—
0.80
1.86
—
15
12
—
12
221
—
260
260
$
$
$
$
$
$
For additional information about our use of derivative instruments, see Note 15—Derivatives and Financial Instruments,
in the Notes to Consolidated Financial Statements.
CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words
“anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,”
“seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,”
“effort,” “target” and similar expressions.
We based the forward-looking statements on our current expectations, estimates and projections about us and the
industries in which we operate in general. We caution you these statements are not guarantees of future performance as
they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties
we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events
that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have
expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including
the following:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Fluctuations in NGL, crude oil, petroleum products and natural gas prices and refining, marketing and
petrochemical margins.
Failure of new products and services to achieve market acceptance.
Unexpected changes in costs or technical requirements for constructing, modifying or operating our facilities or
transporting our products.
Unexpected technological or commercial difficulties in manufacturing, refining or transporting our products,
including chemicals products.
Lack of, or disruptions in, adequate and reliable transportation for our NGL, crude oil, natural gas and refined
products.
The level and success of drilling and quality of production volumes around DCP Midstream’s assets and its
ability to connect supplies to its gathering and processing systems, residue gas and NGL infrastructure.
Inability to timely obtain or maintain permits, including those necessary for capital projects; comply with
government regulations; or make capital expenditures required to maintain compliance.
Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of,
announced and future capital projects.
Potential disruption or interruption of our operations due to accidents, weather events, civil unrest, political
events, terrorism or cyber attacks.
International monetary conditions and exchange controls.
Substantial investment or reduced demand for products as a result of existing or future environmental rules and
regulations.
Liability resulting from litigation or for remedial actions, including removal and reclamation obligations under
environmental regulations.
General domestic and international economic and political developments including: armed hostilities;
expropriation of assets; changes in governmental policies relating to NGL, crude oil, natural gas or refined
product pricing, regulation or taxation; and other political, economic or diplomatic developments.
Changes in tax, environmental and other laws and regulations (including alternative energy mandates) applicable
to our business.
Limited access to capital or significantly higher cost of capital related to changes to our credit profile or
illiquidity or uncertainty in the domestic or international financial markets.
The operation, financing and distribution decisions of our joint ventures.
Domestic and foreign supplies of crude oil and other feedstocks.
Domestic and foreign supplies of petrochemicals and refined products, such as gasoline, diesel, aviation fuel and
home heating oil.
Governmental policies relating to exports of crude oil and natural gas.
Overcapacity or undercapacity in the midstream, chemicals and refining industries.
Fluctuations in consumer demand for refined products.
The factors generally described in Item 1A.—Risk Factors in this report.
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2017 PHILLIPS 66 ANNUAL REPORT Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Management
PHILLIPS 66
INDEX TO FINANCIAL STATEMENTS
Report of Management
Reports of Independent Registered Public Accounting Firm
Consolidated Financial Statements of Phillips 66:
Consolidated Statement of Income for the years ended December 31, 2017, 2016 and 2015
Consolidated Statement of Comprehensive Income for the years ended December 31, 2017, 2016 and 2015
Consolidated Balance Sheet at December 31, 2017 and 2016
Consolidated Statement of Cash Flows for the years ended December 31, 2017, 2016 and 2015
Consolidated Statement of Changes in Equity for the years ended December 31, 2017, 2016 and 2015
Notes to Consolidated Financial Statements
Supplementary Information
Selected Quarterly Financial Data (Unaudited)
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Management prepared, and is responsible for, the consolidated financial statements and the other information appearing
in this annual report. The consolidated financial statements present fairly the company’s financial position, results of
operations and cash flows in conformity with generally accepted accounting principles in the United States. In preparing
its consolidated financial statements, the company includes amounts that are based on estimates and judgments
management believes are reasonable under the circumstances. The company’s financial statements have been audited by
Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of
the Board of Directors. Management has made available to Ernst & Young LLP all of the company’s financial records
and related data, as well as the minutes of stockholders’ and directors’ meetings.
Assessment of Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Phillips
66’s internal control system was designed to provide reasonable assurance to the company’s management and directors
regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to financial statement preparation and
presentation.
Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31,
2017. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission in Internal Control—Integrated Framework (2013). Based on this assessment, management
concluded the company’s internal control over financial reporting was effective as of December 31, 2017.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of
December 31, 2017, and their report is included herein.
/s/ Greg C. Garland
/s/ Kevin J. Mitchell
Greg C. Garland
Chairman and
Chief Executive Officer
Date: February 23, 2018
Kevin J. Mitchell
Executive Vice President, Finance and
Chief Financial Officer
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2017 PHILLIPS 66 ANNUAL REPORT
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Phillips 66
Opinion on the Financial Statements
To the Board of Directors and Stockholders of Phillips 66
Opinion on Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Phillips 66 (the Company) as of December 31, 2017
and 2016, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows, for
each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the
financial statements). In our opinion, the financial statements present fairly, in all material respects, the consolidated
financial position of the Company as of December 31, 2017 and 2016, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally
accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria
established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (2013 framework) and our report dated February 23, 2018 expressed an unqualified opinion
thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an
opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the
PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities
laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement,
whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of
the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.
Our audits also included evaluating the accounting principles used and significant estimates made by management, as
well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable
basis for our opinion.
/s/ Ernst & Young LLP
Houston, Texas
February 23, 2018
We have served as the Company’s auditor since 2011.
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We have audited Phillips 66’s internal control over financial reporting as of December 31, 2017, based on criteria
established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Phillips 66 (the Company) maintained, in
all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO
criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2017 and 2016, the related
consolidated statements of income, comprehensive income, changes in equity, and cash flows, for each of the three years
in the period ended December 31, 2017, and the related notes and our report dated February 23, 2018 expressed an
unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting included under the heading “Assessment of
Internal Control Over Financial Reporting” in the accompanying “Report of Management.” Our responsibility is to
express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public
accounting firm registered with the PCAOB and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange
Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that
our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over financial reporting includes those policies
and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) 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 (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
Houston, Texas
February 23, 2018
/s/ Ernst & Young LLP
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2017 PHILLIPS 66 ANNUAL REPORT Consolidated Statement of Income
Phillips 66
Consolidated Statement of Comprehensive Income
Phillips 66
Years Ended December 31
Revenues and Other Income
Sales and other operating revenues*
Equity in earnings of affiliates
Net gain on dispositions
Other income
Total Revenues and Other Income
Costs and Expenses
Purchased crude oil and products
Operating expenses
Selling, general and administrative expenses
Depreciation and amortization
Impairments
Taxes other than income taxes*
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction (gains) losses
Total Costs and Expenses
Income before income taxes
Income tax expense (benefit)
Net Income
Less: net income attributable to noncontrolling interests
Net Income Attributable to Phillips 66
Net Income Attributable to Phillips 66 Per Share of
Common Stock (dollars)
Basic
Diluted
Dividends Paid Per Share of Common Stock (dollars)
Weighted-Average Common Shares Outstanding (thousands)
Basic
Diluted
* Includes excise taxes on sales of petroleum products:
See Notes to Consolidated Financial Statements.
Millions of Dollars
2017
2016
2015
102,354
1,732
15
521
104,622
79,409
4,699
1,695
1,318
24
13,462
22
438
—
101,067
3,555
(1,693)
5,248
142
5,106
9.90
9.85
2.73
84,279
1,414
10
74
85,777
62,468
4,275
1,638
1,168
5
13,688
21
338
(15)
83,586
2,191
547
1,644
89
1,555
2.94
2.92
2.45
98,975
1,573
283
118
100,949
73,399
4,294
1,670
1,078
7
14,077
21
310
49
94,905
6,044
1,764
4,280
53
4,227
7.78
7.73
2.18
515,090
518,508
13,054
527,531
530,066
13,381
542,355
546,977
13,780
$
$
$
$
$
Millions of Dollars
Years Ended December 31
Net Income
Other comprehensive income (loss)
Defined benefit plans
2017
$
5,248
Actuarial loss arising during the period
Amortization to net income of net actuarial loss and
settlements
Curtailment gain
Plans sponsored by equity affiliates
Income taxes on defined benefit plans
Defined benefit plans, net of tax
Foreign currency translation adjustments
Income taxes on foreign currency translation adjustments
Foreign currency translation adjustments, net of tax
Cash flow hedges
Income taxes on hedging activities
Hedging activities, net of tax
Other Comprehensive Income (Loss), Net of Tax
Comprehensive Income
Less: comprehensive income attributable to noncontrolling interests
Comprehensive Income Attributable to Phillips 66
$
See Notes to Consolidated Financial Statements.
(1)
176
—
10
(70)
115
268
(9)
259
6
(2)
4
378
5,626
142
5,484
2016
1,644
(178)
94
31
(11)
13
(51)
(301)
5
(296)
8
(3)
5
(342)
1,302
89
1,213
2015
4,280
(138)
174
—
11
(13)
34
(163)
7
(156)
—
—
—
(122)
4,158
53
4,105
74
104
75
105
2017 PHILLIPS 66 ANNUAL REPORT Consolidated Balance Sheet
Phillips 66
Consolidated Statement of Cash Flows
Phillips 66
At December 31
Assets
Cash and cash equivalents
Accounts and notes receivable (net of allowances of $29 million in 2017
and $34 million in 2016)
Accounts and notes receivable—related parties
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments and long-term receivables
Net properties, plants and equipment
Goodwill
Intangibles
Other assets
Total Assets
Liabilities
Accounts payable
Accounts payable—related parties
Short-term debt
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Long-term debt
Asset retirement obligations and accrued environmental costs
Deferred income taxes
Employee benefit obligations
Other liabilities and deferred credits
Total Liabilities
Equity
Common stock (2,500,000,000 shares authorized at $0.01 par value)
Issued (2017—643,835,464 shares; 2016—641,593,854 shares)
Par value
Capital in excess of par
Treasury stock (at cost: 2017—141,565,145 shares; 2016—122,827,264 shares)
Retained earnings
Accumulated other comprehensive loss
Total Stockholders’ Equity
Noncontrolling interests
Total Equity
Total Liabilities and Equity
See Notes to Consolidated Financial Statements.
Millions of Dollars
2017
2016
$
3,119
6,424
1,082
3,395
370
14,390
13,941
21,460
3,270
876
434
54,371
7,242
785
41
1,002
582
455
10,107
10,069
641
5,008
884
234
26,943
6
19,768
(10,378)
16,306
(617)
25,085
2,343
27,428
54,371
$
$
$
2,711
5,485
912
3,150
422
12,680
13,534
20,855
3,270
888
426
51,653
6,395
666
550
805
527
520
9,463
9,588
655
6,743
1,216
263
27,928
6
19,559
(8,788)
12,608
(995)
22,390
1,335
23,725
51,653
Millions of Dollars
Years Ended December 31
Cash Flows From Operating Activities
Net income
Adjustments to reconcile net income to net cash provided by operating
activities
2017
$
5,248
Depreciation and amortization
Impairments
Accretion on discounted liabilities
Deferred income taxes
Undistributed equity earnings
Net gain on dispositions
Gain on consolidation of business
Other
Working capital adjustments
Decrease (increase) in accounts and notes receivable
Decrease (increase) in inventories
Decrease (increase) in prepaid expenses and other current assets
Increase (decrease) in accounts payable
Increase (decrease) in taxes and other accruals
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
Proceeds from asset dispositions*
Advances/loans—related parties
Collection of advances/loans—related parties
Restricted cash received from consolidation of business
Other
Net Cash Used in Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of common stock
Repurchase of common stock
Dividends paid on common stock
Distributions to noncontrolling interests
Net proceeds from issuance of Phillips 66 Partners LP common and
preferred units
Other
Net Cash Used in Financing Activities
Effect of Exchange Rate Changes on Cash, Cash Equivalents and
Restricted Cash
Net Change in Cash, Cash Equivalents and Restricted Cash
Cash, cash equivalents and restricted cash at beginning of year
Cash, Cash Equivalents and Restricted Cash at End of Year
* Includes return of investments in equity affiliates.
See Notes to Consolidated Financial Statements.
$
1,318
24
22
(1,886)
(516)
(15)
(423)
(186)
(1,182)
(176)
104
1,153
163
3,648
(1,832)
86
(10)
326
318
(34)
(1,146)
3,508
(3,678)
35
(1,590)
(1,395)
(120)
1,205
(76)
(2,111)
17
408
2,711
3,119
2016
1,644
1,168
5
21
612
(815)
(10)
—
(163)
(1,258)
216
(147)
1,579
111
2,963
(2,844)
156
(432)
108
—
(146)
(3,158)
2,090
(833)
34
(1,042)
(1,282)
(75)
972
(42)
(178)
10
(363)
3,074
2,711
2015
4,280
1,078
7
21
529
185
(283)
—
117
2,129
(144)
324
(2,300)
(230)
5,713
(5,764)
70
(50)
50
—
(44)
(5,738)
1,169
(926)
31
(1,512)
(1,172)
(46)
384
(45)
(2,117)
9
(2,133)
5,207
3,074
76
106
77
107
2017 PHILLIPS 66 ANNUAL REPORT December 31, 2014
Repurchase of common stock
Shares issued—share-based compensation
December 31, 2015
Repurchase of common stock
Shares issued—share-based compensation
December 31, 2016
Repurchase of common stock
Shares issued—share-based compensation
December 31, 2017
See Notes to Consolidated Financial Statements.
Shares in Thousands
Common Stock Issued
637,032
—
2,304
639,336
—
2,258
641,594
—
2,241
643,835
Treasury Stock
90,650
19,276
—
109,926
12,901
—
122,827
18,738
—
141,565
Consolidated Statement of Changes in Equity
Phillips 66
Millions of Dollars
Attributable to Phillips 66
Common Stock
Par
Value
Capital
in Excess
of Par
Treasury
Stock
Retained
Earnings
Accum. Other
Comprehensive
Loss
Noncontrolling
Interests
$
December 31, 2014
Net income
Other comprehensive loss
Cash dividends paid on common
stock
Repurchase of common stock
Benefit plan activity
Issuance of Phillips 66 Partners LP
common units
Distributions to noncontrolling
interests
December 31, 2015
Net income
Other comprehensive loss
Cash dividends paid on common
stock
Repurchase of common stock
Benefit plan activity
Issuance of Phillips 66 Partners LP
common units
Distributions to noncontrolling
interests
December 31, 2016
Net income
Other comprehensive income
Cash dividends paid on common
stock
Repurchase of common stock
Benefit plan activity
Issuance of Phillips 66 Partners LP
common and preferred units
Distributions to noncontrolling
interests
December 31, 2017
$
6
—
—
—
—
—
—
—
6
—
—
—
—
—
—
—
6
—
—
—
—
—
—
—
6
19,040
—
—
(6,234)
—
—
9,309
4,227
—
—
— (1,512)
—
105
— (1,172)
—
(16)
—
—
—
—
19,145
—
—
—
(7,746)
—
—
—
12,348
1,555
—
—
— (1,042)
—
106
— (1,282)
—
(13)
308
—
—
—
19,559
—
—
—
(8,788)
—
—
—
12,608
5,106
—
—
— (1,590)
—
72
— (1,395)
—
(13)
137
—
—
—
19,768
—
(10,378)
—
16,306
(531)
—
(122)
—
—
—
—
—
(653)
—
(342)
—
—
—
—
—
(995)
—
378
—
—
—
—
—
(617)
447
53
—
—
—
—
384
(46)
838
89
—
—
—
—
483
(75)
1,335
142
—
—
—
—
986
(120)
2,343
Total
22,037
4,280
(122)
(1,172)
(1,512)
89
384
(46)
23,938
1,644
(342)
(1,282)
(1,042)
93
791
(75)
23,725
5,248
378
(1,395)
(1,590)
59
1,123
(120)
27,428
78
108
79
109
2017 PHILLIPS 66 ANNUAL REPORT
Notes to Consolidated Financial Statements
Phillips 66
Fair Value Measurements—We categorize assets and liabilities measured at fair value into one of three
Note 1—Summary of Significant Accounting Policies
Consolidation Principles and Investments—Our consolidated financial statements include the accounts of
majority-owned, controlled subsidiaries and variable interest entities where we are the primary beneficiary. The
equity method is used to account for investments in affiliates in which we have the ability to exert significant
influence over the affiliates’ operating and financial policies. When we do not have the ability to exert
significant influence, the investment is classified either as available-for-sale if fair value is readily determinable,
or as the cost method if fair value is not readily determinable. Undivided interests in pipelines, natural gas plants
and terminals are consolidated on a proportionate basis. Other securities and investments are generally carried at
cost.
Recasted Financial Information—Certain prior period financial information has been recasted to reflect the
current year’s presentation.
Foreign Currency Translation—Adjustments resulting from the process of translating foreign functional
currency financial statements into U.S. dollars are included in accumulated other comprehensive income (loss) in
stockholders’ equity. Foreign currency transaction gains and losses result from remeasuring monetary assets and
liabilities denominated in a foreign currency into the functional currency of our subsidiary holding the asset or
liability. We include these transaction gains and losses in current earnings. Most of our foreign operations use
their local currency as the functional currency.
Use of Estimates—The preparation of financial statements in conformity with generally accepted accounting
principles in the United States requires management to make estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities.
Actual results could differ from these estimates.
Revenue Recognition—Revenues associated with sales of crude oil, natural gas liquids (NGL), petroleum and
chemical products, and other items are recognized when title passes to the customer, which is when the risk of
ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed
delivery schedule that is reasonable and customary in the industry.
Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of
inventory with the same counterparty are entered into in contemplation of one another, are combined and
reported in the “Purchased crude oil and products” line on our consolidated statement of income (i.e., these
transactions are recorded net).
Cash Equivalents—Cash equivalents are highly liquid, short-term investments that are readily convertible to
known amounts of cash and will mature within 90 days or less from the date of acquisition. We carry these
investments at cost plus accrued interest.
Shipping and Handling Costs—We record shipping and handling costs in the “Purchased crude oil and
products” line on our consolidated statement of income. Freight costs billed to customers are recorded in “Sales
and other operating revenues.”
Inventories—We have several valuation methods for our various types of inventories and consistently use the
following methods for each type of inventory. Crude oil and petroleum products inventories are valued at the
lower of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Any necessary lower-of-
cost-or-market write-downs at year end are recorded as permanent adjustments to the LIFO cost basis. LIFO is
used to better match current inventory costs with current revenues and to meet tax-conformity requirements.
Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing
condition and location. Materials and supplies inventories are valued using the weighted-average-cost method.
different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are
quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted
prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, through
market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability that are used to
measure fair value to the extent that relevant observable inputs are not available, and that reflect the assumptions
we believe market participants would use when pricing an asset or liability for which there is little, if any, market
activity at the measurement date.
Derivative Instruments—Derivative instruments are recorded on the balance sheet at fair value. We have
elected to net derivative assets and liabilities with the same counterparty on the balance sheet if the right of offset
exists and certain other criteria are met. We also net collateral payables or receivables against derivative assets
and derivative liabilities, respectively.
Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair
value depends on the purpose for issuing or holding the derivative. All realized and unrealized gains and losses
from derivative instruments for which we do not apply hedge accounting are immediately recognized in our
consolidated statement of income. Unrealized gains or losses from derivative instruments that qualify for and
are designated as a cash flow hedge are recognized in other comprehensive income (loss) and appear on the
balance sheet in accumulated other comprehensive income (loss) until the hedged transaction is recognized in
earnings; however, to the extent the change in the fair value of a derivative instrument exceeds the change in the
anticipated cash flows of the hedged transaction, the excess gain or loss is recognized immediately in earnings.
Capitalized Interest—A portion of interest from external borrowings is capitalized on major projects with an
expected construction period of one year or longer. Capitalized interest is added to the cost of the related asset,
and is amortized over the useful life of the related asset.
Loans and Long-Term Receivables—We enter into agreements with other parties to pursue business
opportunities, which may require us to provide loans or advances to certain affiliated and non-affiliated
companies. Loans are recorded when cash is transferred or seller financing is provided to the affiliated or non-
affiliated company pursuant to a loan agreement. The loan balance will increase as interest is earned on the
outstanding loan balance and will decrease as interest and principal payments are received. Interest is earned at
the loan agreement’s stated interest rate. Loans and long-term receivables are assessed for impairment when
events indicate the loan balance may not be fully recovered.
Intangible Assets Other Than Goodwill—Intangible assets with finite useful lives are amortized using the
straight-line method over their useful lives. Intangible assets with indefinite useful lives are not amortized but
are tested at least annually for impairment. Each reporting period, we evaluate the remaining useful lives of
intangible assets not being amortized to determine whether events and circumstances continue to support
indefinite useful lives. Indefinite-lived intangible assets are considered impaired if their fair value is lower than
their net book value. The fair value of intangible assets is determined based on quoted market prices in active
markets, if available. If quoted market prices are not available, the fair value of intangible assets is determined
based upon the present values of expected future cash flows using discount rates and other assumptions believed
to be consistent with those used by principal market participants, or upon estimated replacement cost, if expected
future cash flows from the intangible asset are not determinable.
Goodwill—Goodwill represents the excess of the purchase price over the estimated fair value of the net assets
acquired in a business combination. It is not amortized, but is tested for impairment annually and when events
or changes in circumstance indicate that the fair value of a reporting unit with goodwill is below its 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 book value of the reporting unit. If the fair
value of the reporting unit is less than the book value, an impairment is recognized for the amount by which the
book value exceeds the reporting unit’s fair value. A goodwill loss cannot exceed the total amount of goodwill
allocated to that reporting unit. For purposes of testing goodwill for impairment, we have three reporting units
with goodwill balances: Transportation, Refining, and Marketing and Specialties.
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110
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2017 PHILLIPS 66 ANNUAL REPORT
Depreciation and Amortization—Depreciation and amortization of properties, plants and equipment are
determined by either the individual-unit-straight-line method or the group-straight-line method (for those
individual units that are highly integrated with other units).
Impairment of Properties, Plants and Equipment—Properties, plants and equipment (PP&E) used in
operations are assessed for impairment whenever changes in facts and circumstances indicate a possible
significant deterioration in the future cash flows expected to be generated by an asset group. If indicators of
potential impairment exist, an undiscounted cash flow test is performed. If the sum of the undiscounted pre-tax
cash flows is less than the carrying value of the asset group, including applicable liabilities, the carrying value of
the PP&E included in the asset group is written down to estimated fair value through additional amortization or
depreciation provisions and reported in the “Impairments” line on our consolidated statement of income in the
period in which the determination of the impairment is made. Individual assets are grouped for impairment
purposes at the lowest level for which identifiable cash flows are largely independent of the cash flows of other
groups of assets (for example, at a refinery complex level). Because there is usually a lack of quoted market
prices for long-lived assets, the fair value of impaired assets is typically determined using one or more of the
following methods: the present values of expected future cash flows using discount rates and other assumptions
believed to be consistent with those used by principal market participants; a market multiple of earnings for
similar assets; or historical market transactions of similar assets, adjusted using principal market participant
assumptions when necessary. Long-lived assets held for sale are accounted for at the lower of amortized cost or
fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present
value of expected future cash flows as previously described.
The expected future cash flows used for impairment reviews and related fair value calculations are based on
estimated future volumes, prices, costs, margins and capital project decisions, considering all available evidence
at the date of review.
Impairment of Investments in Nonconsolidated Entities—Investments in nonconsolidated entities are
assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred.
When indicators exist, the fair value is estimated and compared to the investment carrying value. If any
impairment is judgmentally determined to be other than temporary, the carrying value of the investment is
written down to fair value. The fair value of the impaired investment is based on quoted market prices, if
available, or upon the present value of expected future cash flows using discount rates and other assumptions
believed to be consistent with those used by principal market participants and a market analysis of comparable
assets, if appropriate.
Maintenance and Repairs—Costs of maintenance and repairs, which are not significant improvements, are
expensed when incurred. Major refinery maintenance turnarounds are expensed as incurred.
Property Dispositions—When complete units of depreciable property are sold, the asset cost and related
accumulated depreciation are eliminated, with any gain or loss reflected in the “Net gain on dispositions” line on
our consolidated statement of income. When less than complete units of depreciable property are disposed of or
retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.
Asset Retirement Obligations and Environmental Costs—The fair value of legal obligations to retire and
remove long-lived assets are recorded in the period in which the obligation arises. When the liability is initially
recorded, we capitalize this cost by increasing the carrying amount of the related PP&E. Over time, the liability
is increased for the change in its present value, and the capitalized cost in PP&E is depreciated over the useful
life of the related asset. If our estimate of the liability changes after initial recognition, we record an adjustment
to the liability and PP&E.
Environmental expenditures are expensed or capitalized, depending upon their future economic benefit.
Expenditures relating to an existing condition caused by past operations, and those having no future economic
benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless
acquired in a business combination) when environmental assessments or cleanups are probable and the costs can
be reasonably estimated. Recoveries of environmental remediation costs from other parties, such as state
reimbursement funds, are recorded as assets when their receipt is probable and estimable.
Guarantees—The fair value of a guarantee is determined and recorded as a liability at the time the guarantee is
given. The initial liability is subsequently reduced as we are released from exposure under the guarantee. We
amortize the guarantee liability over the relevant time period, if one exists, based on the facts and circumstances
surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability
when we have information indicating the liability has essentially been relieved or amortize it over an appropriate
time period as the fair value of our guarantee exposure declines over time. We amortize the guarantee liability to
the related income statement line item based on the nature of the guarantee. When it becomes probable we will
have to perform on a guarantee, we accrue a separate liability for the excess amount above the guarantee’s book
value, if it is reasonably estimable, based on the facts and circumstances at that time. We reverse the fair value
liability only when there is no further exposure under the guarantee.
Share-Based Compensation—We recognize share-based compensation expense over the shorter of: (1) the
service period (i.e., the stated period of time required to earn the award); or (2) the period beginning at the start
of the service period and ending when an employee first becomes eligible for retirement, but not less than six
months as this is the minimum period of time required for an award not to be subject to forfeiture. Our equity-
classified programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service
required to earn an award) for awards held by employees at the time they become eligible for retirement (at age
55 with 5 years of service). We have elected to recognize expense on a straight-line basis over the service period
for the entire award, irrespective of whether the award was granted with ratable or cliff vesting, and elected to
recognize forfeiture reversals of awards when they occur.
Income Taxes—Income taxes are accounted for under the asset and liability method. Deferred tax assets and
liabilities are recognized for the future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets
and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which
those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Interest
related to unrecognized income tax benefits is reflected in interest expense, and penalties in operating expenses.
Taxes Collected from Customers and Remitted to Governmental Authorities—Excise taxes are reported
gross within sales and other operating revenues and taxes other than income taxes, while other sales and value-
added taxes are recorded net in taxes other than income taxes.
Treasury Stock—We record treasury stock purchases at cost, which includes incremental direct transaction
costs. Amounts are recorded as reductions in stockholders’ equity in the consolidated balance sheet.
Note 2—Changes in Accounting Principles
Effective January 1, 2017, we early adopted Financial Accounting Standards Board (FASB) Accounting Standards
Update (ASU) No. 2017-04, “Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill
Impairment,” which eliminated the second step from the goodwill impairment test. Under the revised test, an entity
should perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount.
An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting
unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting
unit. This ASU was applied prospectively to goodwill impairment tests performed on or after January 1, 2017.
Effective January 1, 2017, we early adopted ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash.”
The update clarified the classification and presentation of changes in restricted cash. The ASU requires that a statement
of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described
as restricted cash and restricted cash equivalents. Adoption of this ASU on a retrospective basis did not have a material
impact on our financial statements. See Note 23—Cash Flow Information for more information.
Effective January 1, 2017, we early adopted ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of
Certain Cash Receipts and Cash Payments.” The update clarified how certain cash receipts and cash payments should be
presented and classified in the statement of cash flows. In addition, the ASU clarified that when cash receipts and cash
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2017 PHILLIPS 66 ANNUAL REPORT
payments have aspects of more than one class of cash flows and cannot be separated, classification will depend on the
predominant source or use. Adoption of this ASU on a retrospective basis did not have a material impact on our financial
statements.
Non-Consolidated VIEs
We hold variable interests in VIEs that have not been consolidated because we are not considered the primary
beneficiary. Information on our significant non-consolidated VIEs follows.
Effective January 1, 2017, we adopted ASU No. 2016-09, “Compensation—Stock Compensation (Topic 718):
Improvements to Employee Share-Based Payment Accounting,” which simplified several aspects of the accounting for
share-based payment award transactions, including accounting for income taxes and classification of excess tax benefits
on the statement of cash flows, forfeitures and minimum statutory tax withholding requirements. Adoption of this ASU
on a prospective basis did not materially impact our financial position, results of operations, or cash flows. We account
for forfeitures of awards when they occur and excess tax benefits, which were previously reported in cash flows from
financing activities, are now reported in cash flows from operating activities.
In June 2014, the FASB issued ASU No. 2014-10, “Development Stage Entities (Topic 915): Elimination of Certain
Financial Reporting Requirements, Including an Amendment to Variable Interest Entities (VIE) Guidance in Topic 810,
Consolidation.” This update removed the definition of a development stage entity from the Master Glossary of the
Accounting Standard Codification (ASC) and the related financial reporting requirements specific to development stage
entities. This update was intended to reduce cost and complexity of financial reporting for entities that have not
commenced planned principal operations. For financial reporting requirements other than the VIE guidance in ASC
Topic 810, ASU No. 2014-10 was effective for annual and quarterly reporting periods of public entities beginning after
December 15, 2014. For the financial reporting requirements related to VIEs in ASC Topic 810, ASU No. 2014-10 was
effective for annual and quarterly reporting periods for public entities beginning after December 15, 2015. We adopted
the provisions of this ASU related to the financial reporting requirements other than the VIE guidance effective January
1, 2015. We adopted the remaining provisions effective January 1, 2016.
Note 3—Variable Interest Entities
Consolidated VIEs
In 2013, we formed Phillips 66 Partners LP (Phillips 66 Partners), a master limited partnership, to own, operate, develop
and acquire primarily fee-based crude oil, refined petroleum products and NGL pipelines and terminals, as well as other
midstream assets. We consolidate Phillips 66 Partners as we determined that Phillips 66 Partners is a VIE and we are the
primary beneficiary. As general partner of Phillips 66 Partners, we have the ability to control its financial interests, as
well as the ability to direct the activities of Phillips 66 Partners that most significantly impact its economic performance.
See Note 27—Phillips 66 Partners LP, for additional information.
The most significant assets of Phillips 66 Partners that are available to settle only its obligations, along with its most
significant liabilities for which its creditors do not have recourse to Phillips 66’s general credit at December 31 were:
Cash and cash equivalents
Equity investments*
Net properties, plants and equipment
Long-term debt
* Included in “Investments and long-term receivables” on the Phillips 66 consolidated balance sheet.
Millions of Dollars
2017
2016
$
185
1,932
2,918
2,920
2
1,142
2,675
2,396
Merey Sweeny, L.P. (MSLP) is a limited partnership that owns a delayed coker and related facilities at the Sweeny
Refinery. Under the agreements that governed the relationships between the former co-venturers in MSLP, certain
defaults by Petróleos de Venezuela S.A. (PDVSA) with respect to supply of crude oil to the Sweeny Refinery triggered
the right to acquire PDVSA’s 50 percent ownership interest in MSLP. The call right was exercised in August 2009. The
exercise of the call right was challenged, and the dispute was arbitrated in our favor and subsequently litigated. Through
February 7, 2017, we determined MSLP was a VIE and used the equity method of accounting because the exercise of the
call right remained subject to legal challenge. MSLP was a VIE because, in securing lender consents in connection with
our separation from ConocoPhillips in 2012 (the Separation), we provided a 100 percent debt guarantee to the lender of
MSLP’s 8.85% senior notes. PDVSA did not participate in the debt guarantee. In our VIE assessment, this
disproportionate debt guarantee, plus other liquidity support provided jointly by us and PDVSA independently of equity
ownership, resulted in MSLP not being exposed to all potential losses. We determined we were not the primary
beneficiary while the call exercise was subject to legal challenge, because under the partnership agreement, the co-
venturers jointly directed the activities of MSLP that most significantly impacted economic performance. As discussed
more fully in Note 5—Business Combinations, the exercise of the call right ceased to be subject to legal challenge in
February 2017. At that point, we no longer considered MSLP a VIE and the entity became a consolidated subsidiary.
We own a 25 percent interest in both Dakota Access, LLC (Dakota Access) and Energy Transfer Crude Oil Company,
LLC (ETCO), which collectively own the Bakken Pipeline. These entities did not have sufficient equity at risk to fully
fund the construction of all assets required for principal operations, and thus represented VIEs until operations began.
We determined we were not the primary beneficiary because we and our co-venturer at the time jointly directed the
activities of Dakota Access and ETCO that most significantly impact economic performance. In June 2017, these entities
started commercial operations and were no longer considered VIEs. We use the equity method of accounting for these
investments.
Note 4—Inventories
Inventories at December 31 consisted of the following:
Crude oil and petroleum products
Materials and supplies
Millions of Dollars
2017
3,106
289
3,395
$
$
2016
2,883
267
3,150
Inventories valued on the LIFO basis totaled $2,980 million and $2,772 million at December 31, 2017 and 2016,
respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately
$4.3 billion and $3.3 billion at December 31, 2017 and 2016, respectively.
Excluding the disposition of the Whitegate Refinery, which occurred in September 2016, certain planned reductions in
inventory caused liquidations of LIFO inventory values during each of the three years ended December 31, 2017. These
liquidations increased net income by approximately $13 million in 2017 and decreased net income by approximately $68
million and $37 million in 2016 and 2015, respectively.
In conjunction with the Whitegate Refinery disposition, the refinery’s LIFO inventory values were liquidated causing a
decrease in net income of $62 million during 2016. This LIFO liquidation impact was included in the net gain
recognized on the disposition.
84
114
85
115
2017 PHILLIPS 66 ANNUAL REPORT
Note 5—Business Combinations
MSLP owns a delayed coker and related facilities at the Sweeny Refinery. Prior to August 28, 2009, MSLP was owned
50/50 by ConocoPhillips and PDVSA. Under the agreements that governed the relationships between the partners,
certain defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery triggered the right, exercised in
August 2009, to acquire its 50 percent ownership interest in MSLP for a purchase price determined by a contractual
formula. As the distributions PDVSA received from MSLP exceeded the amounts it contributed to MSLP, the contractual
formula required no cash consideration for the acquisition. The exercise was challenged, and the dispute was arbitrated
in our favor and subsequently litigated. While the dispute was being arbitrated and litigated, we continued to use the
equity method of accounting for our 50 percent interest in MSLP. When the exercise of the call right ceased to be subject
to legal challenge on February 7, 2017, we deemed that we had acquired PDVSA’s 50 percent share of MSLP and began
accounting for MSLP as a consolidated subsidiary.
Based on a third-party appraisal of the fair value of MSLP’s net assets, utilizing discounted cash flows and replacement
costs, the acquisition of PDVSA’s 50 percent interest resulted in our recording a pre-tax gain of $423 million in the first
quarter of 2017. This gain was included in the “Other income” line on our consolidated statement of income. The fair
value of our original equity interest in MSLP immediately prior to the deemed acquisition was $145 million. As a result
of the transaction, we recorded $318 million of restricted cash, $250 million of PP&E and $238 million of debt, as well
as a net $93 million for the elimination of our equity investment in MSLP and net intercompany payables. Our
acquisition accounting was finalized during the first quarter of 2017.
The results of MSLP were included in our Refining segment until October 2017, when we contributed our 100 percent
interest in MSLP to Phillips 66 Partners, which is included in our Midstream segment. See Note 27—Phillips 66 Partners
LP for further discussion regarding the contribution.
In November 2016, Phillips 66 Partners acquired NGL logistics assets located in southeast Louisiana, consisting of
approximately 500 miles of pipelines and storage caverns connecting multiple fractionation facilities, refineries and a
petrochemical facility. The acquisition provided an opportunity for fee-based growth in the Louisiana market within our
Midstream segment. The acquisition was included in the “Capital expenditures and investments” line on our
consolidated statement of cash flows. At the acquisition date, we recorded $183 million of PP&E and $3 million of
goodwill. Our acquisition accounting was finalized during the first quarter of 2017, with no change to the provisional
amounts recorded in 2016.
Note 6—Assets Held for Sale or Sold
In September 2016, we completed the sale of the Whitegate Refinery and related marketing assets, which were included
primarily in our Refining segment. The net carrying value of the assets at the time of their disposition was $135 million,
which consisted of $127 million of inventory, other working capital, and PP&E; and $8 million of allocated goodwill.
An immaterial gain was recognized in 2016 on the disposition.
In February 2015, we completed the sale of the Bantry Bay terminal, which was included in our Refining segment. At
the time of the disposition, the terminal had a net carrying value of $68 million, which primarily related to net PP&E. An
immaterial gain was recognized in 2015 on this disposition.
In July 2013, we completed the sale of the Immingham Combined Heat and Power Plant (ICHP), which was included in
our Marketing and Specialties segment. A gain on this disposal was deferred at the time of the sale due to an indemnity
provided to the buyer. We recognized the deferred gain in earnings as our exposure under the indemnity declined,
beginning in the third quarter of 2014 and ending in the second quarter of 2015 when the indemnity expired. We
recognized $242 million of the deferred gain during the year ended December 31, 2015.
Note 7—Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables at December 31 were:
Equity investments
Loans and long-term receivables
Other investments
Millions of Dollars
2017
13,733
94
114
13,941
$
$
2016
13,102
334
98
13,534
Equity Investments
Affiliated companies in which we had a significant equity investment at December 31, 2017, included:
• WRB Refining LP (WRB)—50 percent owned business venture with Cenovus Energy Inc. (Cenovus)—owns the
Wood River and Borger refineries.
• DCP Midstream, LLC (DCP Midstream)—50 percent owned joint venture with Spectra Energy Corp, a wholly
owned subsidiary of Enbridge Inc.—owns and operates gas plants, gathering systems, storage facilities and
fractionation plants, including through its investment in DCP Midstream, LP (DCP Partners).
• Chevron Phillips Chemical Company LLC (CPChem)—50 percent owned joint venture with Chevron U.S.A. Inc.,
an indirect wholly owned subsidiary of Chevron Corporation—manufactures and markets petrochemicals and
plastics.
• Rockies Express Pipeline LLC (REX)—25 percent owned joint venture with Tallgrass Energy Partners L.P.—
owns and operates a natural gas pipeline system from Colorado to Ohio.
• DCP Sand Hills Pipeline, LLC (Sand Hills)—Phillips 66 Partners’ 33 percent owned joint venture with DCP
Partners—owns and operates NGL pipeline systems from the Permian and Eagle Ford basins to Mont Belvieu,
Texas.
• DCP Southern Hills Pipeline, LLC (Southern Hills)—Phillips 66 Partners’ 33 percent owned joint venture with
DCP Partners—owns and operates NGL pipeline systems from the Midcontinent region to Mont Belvieu, Texas.
• Dakota Access and ETCO—Phillips 66 Partners’ two 25 percent owned joint ventures with Energy Transfer
Partners L.P. (ETP) and MarEn Bakken Company LLC. Dakota Access owns a pipeline system that delivers
crude oil from the Bakken/Three Forks production area in North Dakota to Patoka, Illinois, and ETCO owns a
connecting crude oil pipeline system from Patoka, Illinois, to Nederland, Texas. Collectively, these two pipeline
systems form the Bakken Pipeline, which is operated by ETP.
Summarized 100 percent financial information for all equity method investments in affiliated companies, combined, was:
Revenues
Income before income taxes
Net income
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Noncontrolling interests
Millions of Dollars
2017
2016
2015
$
35,523
3,956
3,764
7,325
49,950
5,248
13,743
2,549
30,605
3,206
2,960
7,097
50,163
5,173
13,709
2,260
33,126
3,180
3,158
6,024
46,047
4,130
11,493
2,404
86
116
87
117
2017 PHILLIPS 66 ANNUAL REPORT
At December 31, 2017, retained earnings included approximately $2,320 million related to the undistributed earnings of
affiliated companies. Dividends received from affiliates were $1,270 million, $616 million, and $1,769 million in 2017,
2016 and 2015, respectively.
WRB
WRB’s operating assets consist of the Wood River and Borger refineries, located in Roxana, Illinois, and Borger, Texas,
respectively, for which we are the operator and managing partner. As a result of our contribution of these two assets to
WRB, a basis difference was created because the fair value of the contributed assets recorded by WRB exceeded their
historical book value. The difference is primarily amortized and recognized as a benefit evenly over a period of 26 years,
which was the estimated remaining useful life of the refineries’ PP&E at the closing date. At December 31, 2017, the
book value of our investment in WRB was $2,269 million, and the basis difference was $2,787 million. Equity earnings
in 2017, 2016 and 2015 were increased by $186 million, $185 million and $218 million, respectively, due to amortization
of the basis difference.
In the first quarter of 2017, we received payment of the $75 million outstanding principal balance of a partner loan we
made to WRB in 2016. This cash inflow was included in the “Collection of advances/loans—related parties” line on our
consolidated statement of cash flows.
DCP Midstream
DCP Midstream owns and operates gas plants, gathering systems, storage facilities and fractionation plants, primarily
through its investment in DCP Partners. DCP Midstream markets a portion of its NGL to us and CPChem under supply
agreements, the primary production commitment of which began a ratable wind-down period in December 2014 and
expires in January 2019. This purchase commitment is on an “if-produced, will-purchase” basis. NGL is purchased
under this agreement at various published market index prices, less transportation and fractionation fees. At
December 31, 2017, the book value of our investment in DCP Midstream was $2,227 million, and the basis difference
was $54 million.
In 2015, we contributed $1.5 billion in cash to DCP Midstream as a capital contribution. Our co-venturer contributed its
interests in Sand Hills and Southern Hills as a capital contribution equal in value to ours. Our capital contribution was
included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.
CPChem
CPChem manufactures and markets petrochemicals and plastics. We have multiple supply and purchase agreements in
place with CPChem, ranging in initial terms from one to 99 years, with extension options. These agreements cover sales
and purchases of refined products, solvents, and petrochemical and NGL feedstocks, as well as fuel oils and gases. All
products are purchased and sold under specified pricing formulas based on various published pricing indices. At
December 31, 2017, the book value of our equity method investment in CPChem was $6,222 million.
REX
REX owns a natural gas pipeline that runs from Meeker, Colorado, to Clarington, Ohio. At December 31, 2017, the book
value of our equity method investment in REX was $445 million, and the basis difference was $376 million. The basis
difference was created by historical impairment charges we recorded to our investment.
In 2015, we contributed $112 million to REX to cover our 25 percent share of a $450 million debt repayment. Our
capital contribution was included in the “Capital expenditures and investments” line on our consolidated statement of
cash flows.
Sand Hills
The Sand Hills pipeline is a fee-based pipeline that transports NGL from the Permian Basin and Eagle Ford Shale to
facilities along the Texas Gulf Coast and the Mont Belvieu market hub. At December 31, 2017, the book value of
Phillips 66 Partners’ equity investment in Sand Hills was $515 million.
Southern Hills
The Southern Hills pipeline is a fee-based pipeline that transports NGL from the Midcontinent to facilities along the
Texas Gulf Coast and the Mont Belvieu market hub. At December 31, 2017, the book value of Phillips 66 Partners’
investment in Southern Hills was $209 million, and the basis difference was $94 million.
Dakota Access and ETCO
The Dakota Access and ETCO joint ventures were created to construct pipeline systems that collectively form the
Bakken Pipeline. The Bakken Pipeline went into commercial service in June 2017, and delivers crude oil produced in the
Bakken/Three Forks production area of North Dakota to market centers in the Midwest and the Gulf Coast. In October
2017, these investments were contributed to Phillips 66 Partners as discussed further in Note 27—Phillips 66 Partners LP.
At December 31, 2017, the aggregate book value of Phillips 66 Partners’ investments in Dakota Access and ETCO was
$621 million, and the basis difference was $53 million.
In May 2016, we and our co-venturer at the time, executed agreements under which we and our co-venturer would loan
Dakota Access and ETCO up to a maximum of $2,256 million and $227 million, respectively, with the amounts loaned
by us and our co-venturer being proportionate to our ownership interests (Sponsor Loans). In August 2016, Dakota
Access and ETCO secured a $2.5 billion facility (Facility) with a syndicate of financial institutions on a limited recourse
basis with certain guarantees, and the outstanding Sponsor Loans were repaid. Allowable draws under the Facility were
initially reduced and finally suspended in September 2016 pending resolution of permitting delays. As a result, Dakota
Access and ETCO resumed making draws under the Sponsor Loans. The maximum amounts that could be loaned under
the Sponsor Loans were reduced in September 2016, to $1,411 million for Dakota Access and $76 million for ETCO. At
December 31, 2016, Dakota Access and ETCO had $976 million and $22 million, respectively, outstanding under the
Sponsor Loans. Our 25 percent share of those loans was $244 million and $6 million, respectively. In February 2017,
the Sponsor Loans were repaid in their entirety when draws resumed under the Facility. These cash inflows were
included in the “Collection of advances/loans—related parties” line on our consolidated statement of cash flows.
Note 8—Properties, Plants and Equipment
Our investment in PP&E is recorded at cost. Investments in refining and processing facilities are generally depreciated
on a straight-line basis over a 25-year life, pipeline assets over a 45-year life and terminal assets over a 33-year life. The
company’s investment in PP&E, with the associated accumulated depreciation and amortization (Accum. D&A), at
December 31 was:
Millions of Dollars
Gross
PP&E
8,849
—
22,144
1,658
1,091
33,742
$
$
2017
Accum.
D&A
1,853
—
8,987
909
533
12,282
Net
PP&E
6,996
—
13,157
749
558
21,460
Gross
PP&E
8,179
—
21,152
1,451
1,207
31,989
2016
Accum.
D&A
1,579
—
8,197
776
582
11,134
Net
PP&E
6,600
—
12,955
675
625
20,855
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
88
118
89
119
2017 PHILLIPS 66 ANNUAL REPORT
Note 9—Goodwill and Intangibles
Note 10—Asset Retirement Obligations and Accrued Environmental Costs
Goodwill
The carrying amount of goodwill by segment at December 31 was:
Asset retirement obligations and accrued environmental costs at December 31 were:
Millions of Dollars
Midstream
Refining
Marketing and
Specialties
$
$
623
3
—
626
—
626
1,813
—
(8)
1,805
—
1,805
839
—
—
839
—
839
Total
3,275
3
(8)
3,270
—
3,270
Balance at January 1, 2016
Goodwill assigned to acquisitions
Goodwill allocated to dispositions
Balance at December 31, 2016
Adjustments
Balance at December 31, 2017
Intangible Assets
The gross carrying value of indefinite-lived intangible assets at December 31 consisted of the following:
Trade names and trademarks
Refinery air and operating permits
Other
Millions of Dollars
2017
2016
$
$
503
252
1
756
503
260
1
764
At December 31, 2017, the net book value of our amortized intangible assets was $120 million, which included
accumulated amortization of $173 million. At December 31, 2016, the net book value of our amortized intangible assets
was $124 million, which included accumulated amortization of $152 million. Amortization expense was $21 million,
$18 million and $13 million in 2017, 2016 and 2015, respectively, and is expected to be less than $20 million per year in
future years.
Millions of Dollars
2017
2016
Asset retirement obligations
Accrued environmental costs
Total asset retirement obligations and accrued environmental costs
Asset retirement obligations and accrued environmental costs due within one
year*
Long-term asset retirement obligations and accrued environmental costs
* Classified as a current liability on the consolidated balance sheet, under the caption “Other accruals.”
$
$
268
458
726
(85)
641
244
496
740
(85)
655
Asset Retirement Obligations
We have asset retirement obligations that we are required to perform under law or contract once an asset is permanently
taken out of service. Most of these obligations are not expected to be paid until many years in the future and are
expected to be funded from general company resources at the time of removal. Our largest individual obligations involve
asbestos abatement at refineries.
During 2017 and 2016, our overall asset retirement obligation changed as follows:
Balance at January 1
Accretion of discount
Changes in estimates of existing obligations
Spending on existing obligations
Property dispositions
Foreign currency translation
Balance at December 31
Millions of Dollars
2017
2016
$
$
244
10
17
(14)
—
11
268
251
9
10
(15)
(5)
(6)
244
Accrued Environmental Costs
The $38 million decrease in total accrued environmental costs in 2017 was due to payments and settlements during the
year, which exceeded new accruals, accrual adjustments and accretion.
Of our total accrued environmental costs at December 31, 2017, $222 million was primarily related to cleanup at
domestic refineries and underground storage tanks at U.S. service stations; $187 million was associated with nonoperator
sites; and $49 million was related to sites at which we have been named a potentially responsible party under federal or
state laws. A large portion of our expected environmental expenditures have been discounted as these obligations were
acquired in various business combinations. Expected expenditures for acquired environmental obligations were
discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired
environmental liabilities of $268 million at December 31, 2017. The expected future undiscounted payments related to
the portion of the accrued environmental costs that have been discounted are: $18 million in 2018, $46 million in 2019,
$30 million in 2020, $16 million in 2021, $16 million in 2022, and $216 million for all future years after 2022.
90
120
91
121
2017 PHILLIPS 66 ANNUAL REPORT
Note 11—Earnings Per Share
The numerator of basic earnings per share (EPS) is net income attributable to Phillips 66, reduced by noncancelable
dividends paid on unvested share-based employee awards during the vesting period (participating securities). The
denominator of basic EPS is the sum of the daily weighted-average number of common shares outstanding during the
periods presented and fully vested stock and unit awards that have not yet been issued as common stock. The numerator
of diluted EPS is also based on net income attributable to Phillips 66, which is reduced only by dividend equivalents paid
on participating securities for which the dividends are more dilutive than the participation of the awards in the earnings of
the periods presented. To the extent unvested stock, unit or option awards and vested unexercised stock options are
dilutive, they are included with the weighted-average common shares outstanding in the denominator. Treasury stock is
excluded from the denominator in both basic and diluted EPS.
Amounts Attributed to Phillips 66 Common
Stockholders (millions):
Net income attributable to Phillips 66
Income allocated to participating securities
Net income available to common stockholders
2017
2016
2015
Basic Diluted
Basic Diluted
Basic Diluted
$ 5,106
(6)
$ 5,100
5,106
—
5,106
1,555
(6)
1,549
1,555
(5)
1,550
4,227
(6)
4,221
4,227
—
4,227
Weighted-average common shares outstanding
(thousands):
Effect of share-based compensation
Weighted-average common shares outstanding—EPS
511,268 515,090
3,418
515,090 518,508
3,822
523,250 527,531
2,535
527,531 530,066
4,281
537,602 542,355
4,622
542,355 546,977
4,753
Earnings Per Share of Common Stock (dollars)
$
9.90
9.85
2.94
2.92
7.78
7.73
Note 12—Debt
Long-term debt at December 31 was:
$
2.950% Senior Notes due 2017
4.300% Senior Notes due 2022
4.650% Senior Notes due 2034
5.875% Senior Notes due 2042
4.875% Senior Notes due 2044
Phillips 66 Partners 2.646% Senior Notes due 2020
Phillips 66 Partners 3.605% Senior Notes due 2025
Phillips 66 Partners 3.550% Senior Notes due 2026
Phillips 66 Partners 3.750% Senior Notes due 2028
Phillips 66 Partners 4.680% Senior Notes due 2045
Phillips 66 Partners 4.900% Senior Notes due 2046
Floating-rate notes due 2019 at 2.009% at year-end 2017
Floating-rate notes due 2020 at 2.109% at year-end 2017
Term loan due 2020 at 2.469% at year-end 2017
Note payable to MSLP due 2020 at 7.00%*
Industrial Development Bonds due 2018 through 2021 at 0.80%-2.09% at year-
end 2017 and 0.57%-0.81% at year-end 2016*
Phillips 66 Partners revolving credit facility due 2021 at 1.98% at year-end
2016
Other
Debt at face value
Capitalized leases
Net unamortized discounts and debt issuance costs
Total debt
Short-term debt
Long-term debt
* In February 2017, MSLP became a consolidated subsidiary, see Note 5—Business Combinations.
$
Millions of Dollars
2017
—
2,000
1,000
1,500
1,500
300
500
500
500
450
625
300
300
450
—
100
—
1
10,026
192
(108)
10,110
(41)
10,069
2016
1,500
2,000
1,000
1,500
1,500
300
500
500
—
300
625
—
—
—
68
50
210
1
10,054
188
(104)
10,138
(550)
9,588
Maturities of borrowings outstanding at December 31, 2017, inclusive of net unamortized discounts and debt issuance
costs, for each of the years from 2018 through 2022 are $41 million, $314 million, $1,084 million, $62 million and
$2,003 million, respectively.
Debt Issuances
In October 2017, Phillips 66 Partners closed on a public offering of $650 million aggregate principal amount of senior
notes, consisting of $500 million of 3.750% Senior Notes due 2028 and $150 million of 4.680% Senior Notes due 2045.
Interest on the 3.750% Senior Notes due 2028 is payable semiannually in arrears on March 1 and September 1 of each
year, commencing on March 1, 2018. Interest on the 4.680% Senior Notes due 2045 is payable semiannually in arrears
on February 15 and August 15 of each year.
92
122
93
123
2017 PHILLIPS 66 ANNUAL REPORT
In April 2017, Phillips 66 completed a private offering of $600 million aggregate principal amount of unsecured notes,
consisting of $300 million of Notes due 2019 and $300 million of Notes due 2020. Interest on these notes is a floating
rate equal to three-month London Interbank Offered Rate (LIBOR) plus 0.65% per annum for the 2019 Notes and three-
month LIBOR plus 0.75% per annum for the 2020 Notes. Interest on both series of notes is payable quarterly in arrears
on January 15, April 15, July 15 and October 15, commencing in July 2017. The 2019 Notes mature on April 15, 2019,
and the 2020 Notes mature on April 15, 2020. The notes are guaranteed by Phillips 66 Company, a 100-percent-owned
subsidiary.
Also in April 2017, Phillips 66 entered into term loan facilities with an aggregate borrowing amount of $900 million,
consisting of a $450 million 364-day facility and a $450 million three-year facility. Interest on the term loans is a
floating rate based on either the Eurodollar rate or the reference rate, plus a margin determined by our long-term credit
ratings.
In February 2017, as part of the consolidation of MSLP, Phillips 66 assumed $135 million of 8.85% Senior Notes due in
2019 and $100 million of tax-exempt bonds due between 2018 and 2021. See Note 5—Business Combinations for
additional information regarding the consolidation of MSLP.
Debt Repayments
In October 2017, as part of a contribution of assets to Phillips 66 Partners, Phillips 66 Partners assumed the $450 million
term loan outstanding under the 364-day facility originally issued in April 2017, and subsequently repaid the loan. See
Note 27—Phillips 66 Partners LP for additional information.
In May 2017, we repaid $1,500 million of 2.950% Senior Notes upon maturity with the funding from the April 2017 debt
issuances discussed above. In addition, we repaid $135 million of MSLP 8.85% Senior Notes due in 2019 originally
recorded in February 2017 as part of the consolidation of MSLP. See Note 5—Business Combinations for additional
information regarding MSLP.
During 2017, Phillips 66 Partners repaid all outstanding borrowings under its $750 million revolving credit facility.
Credit Facilities and Commercial Paper
Phillips 66 has a $5.0 billion revolving credit facility that extends until October 2021. This facility may be used for
direct bank borrowings, as support for issuances of letters of credit, or as support for our commercial paper program. The
facility is with a broad syndicate of financial institutions and contains covenants that we consider usual and customary
for an agreement of this type for comparable commercial borrowers, including a maximum consolidated net debt-to-
capitalization ratio of 60 percent. The agreement has customary events of default, such as nonpayment of principal when
due; nonpayment of interest, fees or other amounts; violation of covenants; cross-payment default and cross-acceleration
(in each case, to indebtedness in excess of a threshold amount); and a change of control. Borrowings under the facility
will incur interest at the LIBOR plus a margin based on the credit rating of our senior unsecured long-term debt as
determined from time to time by Standard & Poor’s Ratings Services and Moody’s Investors Service. The facility also
provides for customary fees, including administrative agent fees and commitment fees. At December 31, 2017, no
amount had been drawn under this revolving credit agreement.
We have a $5.0 billion commercial paper program for short-term working capital needs that is supported by our revolving
credit facility. Commercial paper maturities are generally limited to 90 days. At December 31, 2017, we had no
borrowings under our commercial paper program.
Phillips 66 Partners has a $750 million revolving credit facility that extends until October 2021. The Phillips 66 Partners
facility is with a broad syndicate of financial institutions. At December 31, 2017, Phillips 66 Partners had no borrowings
outstanding under this facility.
Note 13—Guarantees
At December 31, 2017, we were liable for certain contingent obligations under various contractual arrangements as
described below. We recognize a liability for the fair value of our obligation as a guarantor for newly issued or modified
guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability either because
the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In
addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect
future performance to be either immaterial or have only a remote chance of occurrence.
Guarantees of Joint-Venture Debt
In December 2016, as part of the restructuring within DCP Midstream, we issued a guarantee, effective January 1, 2017,
to support the debt DCP Midstream issued in the first quarter of 2017. At December 31, 2017, the maximum potential
amount of future payments to third parties under the guarantee is estimated to be $175 million. Payment would be
required if DCP Midstream defaults on this debt obligation, which matures in 2019.
At December 31, 2017, we had other guarantees outstanding for our portion of certain joint-venture debt obligations,
which have remaining terms of up to 8 years. The maximum potential amount of future payments to third parties under
these guarantees is approximately $133 million. Payment would be required if a joint venture defaults on its debt
obligations.
Other Guarantees
Under the operating lease agreement on our headquarters facility in Houston, Texas, we have a residual value guarantee
with a maximum future exposure of $554 million. The operating lease has a term of five years and provides us the
option, at the end of the lease term, to request to renew the lease, purchase the facility or assist the lessor in marketing it
for resale.
We also have residual value guarantees associated with railcar and airplane leases with maximum future exposures
totaling $305 million. Based on third-party appraisals of the railcars’ fair value at the end of their lease terms, we
estimated a total residual value deficiency of $109 million and recognized $28 million as expense in 2016. During 2017,
we recognized an additional $45 million of expense related to the residual value deficiency. In October 2017, upon
maturity of one of our railcar leases, $53 million of the total residual value deficiency of $109 million was settled. The
remaining residual value deficiency of $36 million remaining at December 31, 2017, will be recognized on a straight-line
basis through May 2019.
Indemnifications
Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures
and assets that gave rise to indemnification. Agreements associated with these sales include indemnifications for taxes,
litigation, environmental liabilities, permits and licenses, and employee claims, as well as real estate indemnity against
tenant defaults. The provisions of these indemnifications vary greatly. The majority of these indemnifications are related
to environmental issues, which generally have indefinite terms and potentially unlimited exposure. The carrying amount
recorded for indemnifications at December 31, 2017, was $193 million.
We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and
circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse
the liability when we have information to support that the liability was essentially relieved or amortize the liability over
an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible
future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a
reasonable estimate of the maximum potential amount of future payments. Included in the recorded carrying amount
were $104 million of environmental accruals for known contamination at December 31, 2017. For additional
information about environmental liabilities, see Note 10—Asset Retirement Obligations and Accrued Environmental
Costs and Note 14—Contingencies and Commitments.
94
124
95
125
2017 PHILLIPS 66 ANNUAL REPORT
Indemnification and Release Agreement
In 2012, in connection with the Separation, we entered into the Indemnification and Release Agreement with
ConocoPhillips. This agreement governs the treatment between ConocoPhillips and us of matters relating to
indemnification, insurance, litigation responsibility and management, and litigation document sharing and cooperation
arising in connection with the Separation. Generally, the agreement provides for cross-indemnities principally designed
to place financial responsibility for the obligations and liabilities of our business with us and financial responsibility for
the obligations and liabilities of ConocoPhillips’ business with ConocoPhillips. The agreement also establishes
procedures for handling claims subject to indemnification and related matters.
Note 14—Contingencies and Commitments
A number of lawsuits involving a variety of claims that arose in the ordinary course of business have been filed against us
or are subject to indemnifications provided by us. We also may be required to remove or mitigate the effects on the
environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at
various active and inactive sites. We regularly assess the need for financial recognition or disclosure of these
contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability
when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and
no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do
not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for
probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative
probability-weighted loss accrual in cases where sustaining a tax position is less than certain. See Note 21—Income
Taxes, for additional information about income-tax-related contingencies.
Based on currently available information, we believe it is remote that future costs related to known contingent liability
exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated
financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to
accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent
liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation
costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent
of such remedial actions that may be required, and the determination of our liability in proportion to that of other
potentially responsible parties. Estimated future costs related to tax and legal matters are subject to change as events
evolve and as additional information becomes available during the administrative and litigation processes.
Environmental
We are subject to international, federal, state and local environmental laws and regulations. When we prepare our
consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates,
using all information available at the time. We measure estimates and base contingent liabilities on currently available
facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business
considerations. When measuring contingent environmental liabilities, we also consider our prior experience in
remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental
Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental
liabilities, and we accrue them in the period they are both probable and reasonably estimable.
Although liability for environmental remediation costs is generally joint and several for federal sites and frequently so for
state sites, we are usually only one of many companies alleged to have liability at a particular site. Due to such joint and
several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a
potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound
companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state
agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion
responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a
settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their
proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly.
As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these
environmental obligations are mitigated by indemnifications made by others for our benefit, although some of the
indemnifications are subject to dollar and time limits.
We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable
state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an
undiscounted basis (except those pertaining to sites acquired in a business combination, which we record on a discounted
basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and
these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries. In the
future, we may be involved in additional environmental assessments, cleanups and proceedings. See Note 10—Asset
Retirement Obligations and Accrued Environmental Costs, for a summary of our accrued environmental liabilities.
Legal Proceedings
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our
cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process
facilitates the early evaluation and quantification of potential exposures in individual cases and enables the tracking of
those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using
these litigation management tools and available information about current developments in all our cases, our legal
organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or
establishment of new accruals, is required.
Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not
associated with financing arrangements. Under these agreements, we may be required to provide any such company with
additional funds through advances and penalties for fees related to throughput capacity not utilized.
At December 31, 2017, we had performance obligations secured by letters of credit and bank guarantees of $773
million related to various purchase and other commitments incident to the ordinary conduct of business.
Long-Term Throughput Agreements and Take-or-Pay Agreements
We have certain throughput agreements and take-or-pay agreements in support of third-party financing arrangements.
The agreements typically provide for crude oil transportation to be used in the ordinary course of our business. The
aggregate amounts of estimated payments under these various agreements are $327 million annually for each of the years
from 2018 through 2022 and $2,644 million in the aggregate for years 2023 and thereafter. Total payments under the
agreements were $323 million in 2017, $325 million in 2016 and $328 million in 2015.
Note 15—Derivatives and Financial Instruments
Derivative Instruments
We use financial and commodity-based derivative contracts to manage exposures to fluctuations in commodity prices,
interest rates and foreign currency exchange rates, or to capture market opportunities. Because we do not apply hedge
accounting for commodity derivative contracts, all realized and unrealized gains and losses from commodity derivative
contracts are recognized in our consolidated statement of income. Gains and losses from derivative contracts held for
trading not directly related to our physical business are reported net in the “Other income” line on our consolidated
statement of income. Cash flows from all our derivative activity for the periods presented appear in the operating section
on our consolidated statement of cash flows.
Purchase and sales contracts with firm minimum notional volumes for commodities that are readily convertible to cash
are recorded on our consolidated balance sheet as derivatives unless the contracts are eligible for, and we elect, the
normal purchases and normal sales exception, whereby the contracts are recorded on an accrual basis. We generally
apply the normal purchases and normal sales exception to eligible crude oil, refined products, NGL, natural gas and
power commodity contracts to purchase or sell quantities we expect to use or sell in the normal course of business. All
other derivative instruments are recorded at fair value on our consolidated balance sheet. For further information on the
fair value of derivatives, see Note 16—Fair Value Measurements.
96
126
97
127
2017 PHILLIPS 66 ANNUAL REPORT Commodity Derivative Contracts—We sell into or receive supply from the worldwide crude oil, refined products,
NGL, natural gas, and electric power markets, exposing our revenues, purchases, cost of operating activities and cash
flows to fluctuations in the prices for these commodities. Generally, our policy is to remain exposed to the market prices
of commodities; however, we use futures, forwards, swaps and options in various markets to balance physical systems,
meet customer needs, manage price exposures on specific transactions, and do a limited, immaterial amount of trading
not directly related to our physical business, all of which may reduce our exposure to fluctuations in market prices. We
also use the market knowledge gained from these activities to capture market opportunities such as moving physical
commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending
commodities to capture quality upgrades.
The following table indicates the consolidated balance sheet line items that include the fair values of commodity
derivative assets and liabilities. The balances in the following table are presented on a gross basis, before the effects of
counterparty and collateral netting. However, we have elected to present our commodity derivative assets and liabilities
with the same counterparty on a net basis on our consolidated balance sheet when the right of setoff exists.
December 31, 2017
December 31, 2016
Millions of Dollars
Commodity
Derivatives
Assets Liabilities
Effect of
Collateral
Netting
Net
Carrying
Value
Presented
on the
Balance
Sheet
Commodity
Derivatives
Assets Liabilities
Effect of
Collateral
Netting
Net
Carrying
Value
Presented
on the
Balance
Sheet
Assets
Prepaid expenses and other current assets
$
Other assets
Liabilities
Other accruals
Other liabilities and deferred credits
Total
$
43
7
699
—
749
(19)
(3)
(746)
(1)
(769)
—
—
21
—
21
24
4
(26)
(1)
1
267
5
474
—
746
(154)
(1)
(612)
(1)
(768)
—
—
73
—
73
113
4
(65)
(1)
51
At December 31, 2017 and 2016, there was no material cash collateral received or paid that was not offset on our
consolidated balance sheet.
The realized and unrealized gains (losses) incurred from commodity derivatives, and the line items where they appear on
our consolidated statement of income, were:
Sales and other operating revenues
Other income
Purchased crude oil and products
Net gain (loss) from commodity derivative activity
Millions of Dollars
2017
(247)
27
(18)
(238)
$
$
2016
2015
(451)
29
(62)
(484)
162
58
121
341
The following table summarizes our material net exposures resulting from outstanding commodity derivative contracts.
These financial and physical derivative contracts are primarily used to manage price exposure on our underlying
operations. The underlying exposures may be from non-derivative positions such as inventory volumes. Financial
derivative contracts may also offset physical derivative contracts, such as forward sales contracts. The percentage of our
derivative contract volumes expiring within the next 12 months was at least 98 percent at December 31, 2017 and 2016.
Commodity
Crude oil, refined products and NGL (millions of barrels)
Open Position
Long / (Short)
2017
2016
(11)
(18)
Interest Rate Derivative Contracts—In 2016, we entered into interest rate swaps to hedge the variability of anticipated
lease payments on our new headquarters. These monthly lease payments will vary based on monthly changes in the one-
month LIBOR and changes, if any, in our credit rating over the five-year term of the lease. The pay-fixed, receive-
floating interest rate swaps have an aggregate notional value of $650 million and end on April 25, 2021. They qualify for
and are designated as cash-flow hedges.
The aggregate net fair value of these swaps, which is included in the “Prepaid expenses and other current assets,” “Other
assets” and “Other accruals” lines of our consolidated balance sheet, totaled $14 million and $8 million at December 31,
2017 and 2016, respectively.
We report the effective portion of the mark-to-market gain or loss on our interest rate swaps designated as cash-flow
hedges as a component of other comprehensive income (loss), and reclassify such gains and losses into earnings in the
same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness are
recognized in general and administrative expenses. We did not have any material hedge ineffectiveness gain or loss for
the years ended December 31, 2017 and 2016. Net realized losses from settlements of the swaps were immaterial for the
years ended December 31, 2017 and 2016.
We currently estimate that pre-tax gains of $2 million will be reclassified from accumulated other comprehensive income
(loss) into general and administrative expenses during the next twelve months as the hedged transactions settle; however,
the actual amounts that will be reclassified will vary based on changes in interest rates throughout 2018.
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of over-the-counter (OTC)
derivative contracts and trade receivables.
The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the
transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of
cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps
and option contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse
and subject to mandatory margin requirements until settled. However, we are exposed to the credit risk of those
exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin
requirements.
Our trade receivables result primarily from the sale of products from, or related to, our refinery operations and reflect a
broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority
of these receivables have payment terms of 30 days or less. We continually monitor this exposure and the
creditworthiness of the counterparties and recognize bad debt expense based on historical write-off experience or specific
counterparty collectability. Generally, we do not require collateral to limit the exposure to loss; however, we will
sometimes use letters of credit, prepayments or master netting arrangements to mitigate credit risk with counterparties
that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset
against amounts due to us.
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure
exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold
amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit
ratings, while both the variable and fixed threshold amounts typically revert to zero if our credit ratings fall below
investment grade. Cash is the primary collateral in all contracts; however, many contracts also permit us to post letters of
credit as collateral.
98
128
99
129
2017 PHILLIPS 66 ANNUAL REPORT
The aggregate fair values of all derivative instruments with such credit-risk-related contingent features that were in a
liability position were not material at December 31, 2017 and 2016.
We used the following methods and assumptions to estimate the fair value of financial instruments:
Note 16—Fair Value Measurements
Recurring Fair Value Measurements
We carry certain assets and liabilities at fair value, which we measure at the reporting date using an exit price (i.e., the
price that would be received to sell an asset or paid to transfer a liability), and disclose the quality of these fair values
based on the valuation inputs used in these measurements under the following hierarchy:
• Level 1: Fair value measured with unadjusted quoted prices from an active market for identical assets or
liabilities.
• Level 2: Fair value measured either with: (1) adjusted quoted prices from an active market for similar assets or
liabilities; or (2) other valuation inputs that are directly or indirectly observable.
• Level 3: Fair value measured with unobservable inputs that are significant to the measurement.
We classify the fair value of an asset or liability based on the significance of its observable or unobservable inputs to the
measurement. However, the fair value of an asset or liability initially reported as Level 3 will be subsequently reported
as Level 2 if the unobservable inputs become inconsequential to its measurement or corroborating market data becomes
available. Conversely, an asset or liability initially reported as Level 2 will be subsequently reported as Level 3 if
corroborating market data becomes unavailable. For the year ended December 31, 2017, derivative assets with an
aggregate value of $131 million and derivative liabilities with an aggregate value of $134 million were transferred to
Level 1 from Level 2, as measured from the beginning of the reporting period. The measurements were reclassified
within the fair value hierarchy due to the availability of unadjusted quoted prices from an active market.
• Cash and cash equivalents—The carrying amount reported on our consolidated balance sheet approximates fair
value.
• Accounts and notes receivable—The carrying amount reported on our consolidated balance sheet approximates
fair value.
• Derivative instruments—We fair value our exchange-traded contracts based on quoted market prices obtained
from the New York Mercantile Exchange, the Intercontinental Exchange or other exchanges, and classify them
as Level 1 in the fair value hierarchy. When exchange-cleared contracts lack sufficient liquidity or are valued
using either adjusted exchange-provided prices or non-exchange quotes, we classify those contracts as Level 2.
OTC financial swaps and physical commodity forward purchase and sales contracts are generally valued using
forward quotes provided by brokers and price index developers, such as Platts and Oil Price Information Service.
We corroborate these quotes with market data and classify the resulting fair values as Level 2. When forward
market prices are not available, we estimate fair value using the forward price of a similar commodity, adjusted
for the difference in quality or location. In certain less liquid markets or for longer-term contracts, forward
prices are not as readily available. In these circumstances, OTC swaps and physical commodity purchase and
sales contracts are valued using internally developed methodologies that consider historical relationships among
various commodities that result in management’s best estimate of fair value. We classify these contracts as Level
3. Financial OTC and physical commodity options are valued using industry-standard models that consider
various assumptions, including quoted forward prices for commodities, time value, volatility factors and
contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to
which these inputs are observable in the forward markets determines whether the options are classified as Level
2 or 3. We use a mid-market pricing convention (the mid-point between bid and ask prices). When appropriate,
valuations are adjusted to reflect credit considerations, generally based on available market evidence.
We determine the fair value of our interest rate swaps based on observed market valuations for interest rate
swaps that have notionals, terms and pay and reset frequencies similar to ours.
• Rabbi trust assets—These deferred compensation investments are measured at fair value using unadjusted
quoted prices available from national securities exchanges and are therefore categorized as Level 1 in the fair
value hierarchy.
• Debt—The carrying amount of our floating-rate debt approximates fair value. The fair value of our fixed-rate
debt is estimated based on observable market prices.
The following tables display the fair value hierarchy for our material financial assets and liabilities either accounted for
or disclosed at fair value on a recurring basis. These values are determined by treating each contract as the fundamental
unit of account; therefore, derivative assets and liabilities with the same counterparty are shown on a gross basis in the
hierarchy sections of these tables, before the effects of counterparty and collateral netting. These tables also show that
our Level 3 activity was not material.
We have master netting agreements for all of our exchange-cleared derivative instruments, the majority of our OTC
derivative instruments, and certain physical commodity forward contracts (primarily pipeline crude oil deliveries). The
following tables show the impact of these contracts in the column “Effect of Counterparty Netting.”
The carrying values and fair values by hierarchy of our material financial instruments and commodity forward contracts,
either carried or disclosed at fair value, including any effects of netting derivative assets with liabilities and netting
collateral due to right of setoff or master netting agreements, were:
100
130
101
131
2017 PHILLIPS 66 ANNUAL REPORT Millions of Dollars
December 31, 2017
Fair Value Hierarchy
Level 1
Level 2
Level 3
Total Fair
Value of
Gross Assets
& Liabilities
Effect of
Counterparty
Netting
Effect of
Collateral
Netting
Difference in
Carrying
Value and
Fair Value
Net Carrying
Value
Presented on
the Balance
Sheet
Commodity Derivative Assets
Exchange-cleared instruments
Physical forward contracts
Interest rate derivatives
Rabbi trust assets
Commodity Derivative Liabilities
Exchange-cleared instruments
Physical forward contracts
Floating-rate debt
Fixed-rate debt, excluding capital
leases
$
$
$
$
333
—
—
112
445
369
—
—
—
369
395
20
14
—
429
373
23
1,150
9,746
11,292
—
1
—
—
1
—
4
—
—
4
728
21
14
112
875
742
27
1,150
9,746
11,665
(721)
—
—
N/A
(721)
(721)
—
N/A
N/A
(721)
—
—
—
N/A
—
(21)
—
N/A
N/A
(21)
—
—
—
—
—
—
—
—
(978)
(978)
7
21
14
112
154
—
27
1,150
8,768
9,945
Millions of Dollars
December 31, 2016
Fair Value Hierarchy
Level 1
Level 2
Level 3
Total Fair
Value of
Gross Assets
& Liabilities
Effect of
Counterparty
Netting
Effect of
Collateral
Netting
Difference in
Carrying
Value and
Fair Value
Net Carrying
Value
Presented on
the Balance
Sheet
Commodity Derivative Assets
Exchange-cleared instruments
$
273
OTC instruments
Physical forward contracts
Interest rate derivatives
Rabbi trust assets
Commodity Derivative Liabilities
Exchange-cleared instruments
OTC instruments
Physical forward contracts
Floating-rate debt
Fixed-rate debt, excluding capital
leases
—
—
—
97
370
249
—
—
—
—
249
$
$
$
371
6
94
8
—
479
452
1
61
260
10,260
11,034
—
—
2
—
—
2
—
—
5
—
—
5
644
6
96
8
97
851
701
1
66
260
10,260
11,288
(628)
(1)
—
—
N/A
(629)
(628)
(1)
—
N/A
N/A
(629)
—
—
—
—
N/A
—
(73)
—
—
N/A
N/A
(73)
—
—
—
—
—
—
—
—
—
—
16
5
96
8
97
222
—
—
66
260
(570)
(570)
9,690
10,016
The rabbi trust assets are recorded in the “Investments and long-term receivables” line and floating-rate and fixed-rate
debt are recorded in the “Short-term debt” and “Long-term debt” lines on our consolidated balance sheet. For
information regarding the location of our commodity derivative assets and liabilities on our consolidated balance sheet,
see the first table in Note 15—Derivatives and Financial Instruments.
Nonrecurring Fair Value Measurements
See Note 5—Business Combinations for information on the remeasurement of our investment in MSLP to fair value.
During the years ended December 31, 2017, and 2016, there were no other material nonrecurring fair value
remeasurements of assets subsequent to their initial recognition.
Note 17—Equity
Preferred Stock
We have 500 million shares of preferred stock authorized, with a par value of $0.01 per share, none of which have been
issued.
Treasury Stock
Since July 2012, our Board of Directors has, at various times, authorized repurchases of our outstanding common stock
which aggregate to a total authorization of up to $12.0 billion. The shares will be repurchased from time to time in the
open market at the company’s discretion, subject to market conditions and other factors, and in accordance with
applicable regulatory requirements. We are not obligated to acquire any particular amount of common stock and may
commence, suspend or discontinue purchases at any time or from time to time without prior notice. Since the inception
of our share repurchases in 2012, through December 31, 2017, we have repurchased a total of 124,142,530 shares at an
aggregate cost of $9.0 billion. Shares of stock repurchased are held as treasury shares.
In 2014, we completed the exchange of our flow improver business for shares of Phillips 66 common stock owned by the
other party to the transaction. We received 17,422,615 shares of our common stock with a fair value at the time of the
exchange of $1.35 billion.
Common Stock Dividends
On February 7, 2018, our Board of Directors declared a quarterly cash dividend of $0.70 per common share, payable
March 1, 2018, to holders of record at the close of business on February 20, 2018.
Noncontrolling Interests
Our noncontrolling interests primarily represent issuances of common and preferred units to the public by Phillips 66
Partners. See Note 27—Phillips 66 Partners LP, for information on Phillips 66 Partners.
Note 18—Leases
We lease ocean transport vessels, tugboats, barges, pipelines, railcars, service station sites, computers, office buildings,
corporate aircraft, land and other facilities and equipment. Certain leases include escalation clauses for adjusting rental
payments to reflect changes in price indices, as well as renewal options and/or options to purchase the leased property.
There are no significant restrictions imposed on us by the leasing agreements with regard to dividends, asset dispositions
or borrowing ability. Our capital lease obligations relate primarily to the lease of an oil terminal in the United Kingdom.
The lease obligation is subject to foreign currency translation adjustments each reporting period. The total net PP&E
recorded for capital leases was $210 million and $208 million at December 31, 2017 and 2016, respectively.
102
132
103
133
2017 PHILLIPS 66 ANNUAL REPORT
Future minimum lease payments at December 31, 2017, for operating and capital lease obligations were:
Note 19—Pension and Postretirement Plans
2018
2019
2020
2021
2022
Remaining years
Total
Less: income from subleases
Net minimum lease payments
Less: amount representing interest
Capital lease obligations
Millions of Dollars
Capital Lease
Obligations
Operating
Lease
Obligations*
$
$
$
22
22
18
18
15
148
243
—
243
51
192
533
420
306
141
100
326
1,826
71
1,755
* Includes the remaining residual value deficiency on our railcar leases. See Note 13—Guarantees, for additional information.
Operating lease rental expense for the years ended December 31 was:
Minimum rentals*
Contingent rentals
Less: sublease rental income
Millions of Dollars
2017
2016
2015
$
$
680
6
73
613
669
6
95
580
641
6
136
511
* Includes expenses related to the residual value deficiency on our railcar leases. See Note 13—Guarantees, for additional information.
The following table provides a reconciliation of the projected benefit obligations and plan assets for our pension plans
and accumulated benefit obligations for our other postretirement benefit plans:
Change in Benefit Obligation
Benefit obligation at January 1
Service cost
Interest cost
Plan participant contributions
Actuarial loss (gain)
Benefits paid
Curtailment gain
Acquisition of a business
Foreign currency exchange rate change
Benefit obligation at December 31
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1
Actual return on plan assets
Company contributions
Plan participant contributions
Benefits paid
Foreign currency exchange rate change
Fair value of plan assets at December 31
Funded Status at December 31
$
$
$
$
$
Millions of Dollars
Pension Benefits
2017
2016
Other Benefits
2017
2016
U.S.
Int’l.
U.S.
Int’l.
2,881
132
108
—
267
(345)
—
—
—
3,043
2,274
399
423
—
(345)
—
2,751
1,055
32
27
2
(5)
(20)
—
—
118
1,209
796
71
35
2
(20)
88
972
2,791
127
116
—
62
(215)
—
—
—
2,881
2,023
136
330
—
(215)
—
2,274
912
32
28
3
237
(19)
(31)
—
(107)
1,055
742
148
40
3
(19)
(118)
796
225
6
8
3
6
(16)
—
—
—
232
—
—
13
3
(16)
—
—
219
7
8
2
(6)
(13)
—
8
—
225
—
—
11
2
(13)
—
—
(292)
(237)
(607)
(259)
(232)
(225)
Amounts recognized in the consolidated balance sheet for our pension and other postretirement benefit plans at
December 31, 2017 and 2016, include:
Amounts Recognized in the
Consolidated Balance Sheet at
December 31
Current liabilities
Noncurrent liabilities
Total recognized
Millions of Dollars
Pension Benefits
2017
2016
Other Benefits
2017
2016
U.S.
Int’l.
U.S.
Int’l.
$
$
(25)
(267)
(292)
—
(237)
(237)
(10)
(597)
(607)
—
(259)
(259)
(16)
(216)
(232)
(10)
(215)
(225)
104
134
105
135
2017 PHILLIPS 66 ANNUAL REPORT
Included in accumulated other comprehensive income (loss) at December 31 were the following before-tax amounts that
had not been recognized in net periodic benefit cost:
Components of net periodic benefit cost for all defined benefit plans are presented in the table below:
Millions of Dollars
Pension Benefits
2017
2016
Other Benefits
2017
2016
U.S.
Int’l.
U.S.
Int’l.
Unrecognized net actuarial loss (gain)
Unrecognized prior service cost (credit)
$
545
—
190
(4)
684
3
227
(5)
1
(7)
(5)
(9)
Millions of Dollars
Pension Benefits
2017
2016
Other Benefits
2017
2016
U.S.
Int’l.
U.S.
Int’l.
Sources of Change in Other
Comprehensive Income (Loss)
Net gain (loss) arising during the period
Curtailment gain
Amortization of loss and settlements
included in income
$
(14)
—
153
Net change in unrecognized net actuarial
loss (gain) during the period
$
139
Prior service cost arising during the period $
Amortization of prior service cost (credit)
included in income
Net change in unrecognized prior service
cost (credit) during the period
$
—
3
3
14
—
23
37
—
(1)
(1)
(54)
—
80
26
—
3
3
(129)
31
14
(84)
—
(1)
(1)
(6)
—
—
(6)
—
(2)
(2)
7
—
—
7
—
(1)
(1)
The accumulated benefit obligations for all U.S. and international pension plans were $2,743 million and $1,006 million,
respectively, at December 31, 2017, and $2,601 million and $880 million, respectively, at December 31, 2016.
Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at
December 31 were:
Projected benefit obligations
Accumulated benefit obligations
Fair value of plan assets
Millions of Dollars
Pension Benefits
2017
2016
U.S.
Int’l.
U.S.
Int’l.
$
172
143
—
389
368
196
2,881
2,601
2,274
355
334
166
Millions of Dollars
2017
Pension Benefits
2016
2015
2017
2016
2015
Other Benefits
U.S.
Int’l.
U.S.
Int’l.
U.S.
Int’l.
Components of Net
Periodic Benefit
Cost
Service cost
Interest cost
Expected return on
plan assets
Amortization of prior
service cost (credit)
Recognized net
actuarial loss (gain)
Settlements
Total net periodic
benefit cost
$
132
108
32
27
127
116
32
28
124
109
38
28
(146)
(40)
(128)
(38)
(138)
(37)
3
70
83
$
250
(1)
23
—
41
3
72
8
198
(1)
14
—
35
3
75
80
253
(1)
15
—
43
6
8
—
(2)
—
—
12
7
8
—
(1)
—
—
14
7
7
—
(2)
(1)
—
11
In determining net periodic benefit cost, we amortize prior service costs on a straight-line basis over the average
remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we
amortize 10 percent of the unamortized balance each year. The amount subject to amortization is determined on a plan-
by-plan basis. Amounts included in accumulated other comprehensive income (loss) at December 31, 2017, that are
expected to be amortized into net periodic benefit cost during 2018 are provided below:
Unrecognized net actuarial loss
Unrecognized prior service credit
Millions of Dollars
Pension Benefits
U.S.
Int’l.
Other
Benefits
$
59
—
19
(1)
—
(1)
106
136
107
137
2017 PHILLIPS 66 ANNUAL REPORT The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs
for years ended December 31:
Assumptions Used to Determine
Benefit Obligations:
Discount rate
Rate of compensation increase
Assumptions Used to Determine Net
Periodic Benefit Cost:
Discount rate
Expected return on plan assets
Rate of compensation increase
Pension Benefits
2017
2016
Other Benefits
2017
2016
U.S.
Int’l.
U.S.
Int’l.
3.60%
4.00
3.95%
6.75
4.00
2.36
3.74
2.46
4.74
3.78
3.95
4.00
4.35
6.75
4.00
2.42
3.78
3.35
5.31
3.65
3.35
—
3.65
—
—
3.65
—
4.00
—
—
For both U.S. and international pension plans, the overall expected long-term rate of return is developed from the expected
future return of each asset class, weighted by the expected allocation of pension assets to that asset class. We rely on a
variety of independent market forecasts in developing the expected rate of return for each class of assets.
Our other postretirement benefit plans for health insurance are contributory. Effective December 31, 2012, we terminated
the subsidy for retiree medical plans. Since January 1, 2013, eligible employees have been able to utilize notional
amounts credited to an account during their period of service with the company to pay all, or a portion, of their cost to
participate in postretirement health insurance through the company. In general, employees hired after December 31,
2012, will not receive credits to an account, but will have unsubsidized access to health insurance through the plan. The
cost of health insurance will be adjusted annually by the company’s actuary to reflect actual experience and expected
health care cost trends. The measurement of the accumulated benefit obligation assumes a health care cost trend rate of
6.25 percent in 2018 that declines to 5.00 percent by 2023. A one percentage-point change in the assumed health care
cost trend rate would be immaterial to Phillips 66.
Plan Assets
The investment strategy for managing pension plan assets is to seek a reasonable rate of return relative to an appropriate
level of risk and provide adequate liquidity for benefit payments and portfolio management. We follow a policy of
diversifying pension plan assets across asset classes, investment managers, and individual holdings. As a result, our plan
assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include equities,
fixed income, cash, real estate and insurance contracts. Plan fiduciaries may consider and add other asset classes to the
investment program from time to time. The target allocations for plan assets are approximately 57 percent equity
securities, 41 percent debt securities and 2 percent in all other types of investments. Generally, the investments in the
plans are publicly traded, therefore minimizing the liquidity risk in the portfolio.
•
•
Fair values of real estate investments are valued using real estate valuation techniques and other methods that
include reference to third-party sources and sales comparables where available.
Fair values of investments in common/collective trusts are valued at net asset value (NAV) as determined by the
issuer of each fund. Certain investments that are measured at fair value using the NAV value per share (or its
equivalent) practical expedient have not been classified in the fair value hierarchy.
The fair values of our pension plan assets at December 31, by asset class, were:
Millions of Dollars
U.S.
International
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
2017
Equity securities
Government debt
securities
Mutual funds
Cash and cash equivalents
Insurance contracts
Real estate
Total assets in the fair
value hierarchy
Common/collective trusts
measured at NAV
$
589
632
129
90
—
—
1,440
Total
$ 1,440
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
589
632
129
90
—
—
1,440
1,311
2,751
—
—
—
6
—
—
6
6
—
—
—
—
—
—
—
—
—
—
—
—
14
8
22
22
—
—
—
6
14
8
28
944
972
Millions of Dollars
U.S.
International
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
$
2016
Equity securities
Mutual funds
Cash and cash equivalents
Insurance contracts
Real estate
Total assets in the fair
value hierarchy
Common/collective trusts
measured at NAV
533
47
21
—
—
601
—
—
—
—
—
—
—
—
—
—
—
—
—
—
533
47
21
—
—
601
1,673
2,274
—
—
5
—
—
5
5
—
—
—
—
—
—
—
—
—
—
13
6
19
19
—
—
5
13
6
24
772
796
The following is a description of the valuation methodologies used for the pension plan assets.
Total
$
601
•
•
Fair values of equity securities and government debt securities are based on quoted market prices.
Fair values of mutual funds are valued based on quoted market prices, which represent the net asset value of
shares held.
• Cash and cash equivalents are valued at cost, which approximates fair value.
•
Fair values of insurance contracts are valued at the present value of the future benefit payments owed by the
insurance company to the plans’ participants.
As reflected in the table above, Level 3 activity was not material.
Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income
Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to international plans are
subject to local laws and tax regulations. Actual contribution amounts are dependent upon plan asset returns, changes in
pension obligations, regulatory environments, and other economic factors. In 2018, we expect to contribute
approximately $60 million to our U.S. pension plans and other postretirement benefit plans and $35 million to our
international pension plans.
108
138
109
139
2017 PHILLIPS 66 ANNUAL REPORT
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by us in
the years indicated:
Total share-based compensation expense recognized in income and the associated income tax benefit for the years ended
December 31 were:
2018
2019
2020
2021
2022
2023-2026
Millions of Dollars
Pension Benefits
Other Benefits
U.S.
Int’l.
$
329
302
294
290
292
1,298
22
22
24
26
27
162
27
28
27
26
24
101
Defined Contribution Plans
Most U.S. employees are eligible to participate in the Phillips 66 Savings Plan (Savings Plan). Employees can contribute
up to 75 percent of their eligible pay, subject to certain statutory limits, in the thrift feature of the Savings Plan to a choice
of investment funds. Phillips 66 provides a company match of participant thrift contributions up to 5 percent of eligible
pay. In addition, participants who contribute at least 1 percent to the Savings Plan are eligible for “Success Share,” a
semi-annual discretionary company contribution to the Savings Plan that can range from 0 to 6 percent of eligible pay,
with a target of 2 percent. The total expense related to participants in the Savings Plan was $101 million, $99 million and
$134 million in 2017, 2016 and 2015, respectively.
Note 20—Share-Based Compensation Plans
In accordance with the Employee Matters Agreement related to the Separation, compensation awards based on
ConocoPhillips stock and granted before April 30, 2012 (the Separation Date) were converted to compensation awards
based on both ConocoPhillips and Phillips 66 stock if, on the Separation Date, the awards were: (1) options outstanding
and exercisable; or (2) restricted stock or restricted stock units (RSUs) awarded for completed performance periods under
the ConocoPhillips Performance Share Program. Phillips 66 restricted stock, RSUs and options issued in this conversion
became subject to the “Omnibus Stock and Performance Incentive Plan of Phillips 66” (the 2012 Plan) on the Separation
Date, whether held by grantees working for Phillips 66 or grantees that remained employees of ConocoPhillips. Some of
these awards based on Phillips 66 stock and held by employees of ConocoPhillips are outstanding and appear in the
activity tables for the Stock Option and the Performance Share Programs presented later in this footnote.
In May 2013, shareholders approved the 2013 Omnibus Stock and Performance Incentive Plan of Phillips 66 (the P66
Omnibus Plan). Subsequent to this approval, all new share-based awards are granted under the P66 Omnibus Plan, which
authorizes the Human Resources and Compensation Committee (HRCC) of our Board of Directors to grant stock options,
stock appreciation rights, stock awards (including restricted stock and RSU awards), cash awards, and performance
awards to our employees, non-employee directors and other plan participants. The number of new shares that may be
issued under the P66 Omnibus Plan to settle share-based awards may not exceed 45 million.
Share-based compensation expense
Income tax benefit
Millions of Dollars
2017
2016
2015
$
142
(74)
156
(59)
144
(54)
Stock Options
Stock options granted under the provisions of the P66 Omnibus Plan and earlier plans permit purchases of our common
stock at exercise prices equivalent to the average of the high and low market price of our stock on the date the options
were granted. The options have terms of 10 years and vest ratably, with one-third of the options becoming exercisable on
each anniversary date for the three years following the date of grant. Options awarded to employees eligible for
retirement are not subject to forfeiture six months after the grant date.
The following table summarizes our stock option activity from January 1, 2017, to December 31, 2017:
Outstanding at January 1, 2017
Granted
Forfeited
Exercised
Outstanding at December 31, 2017
Options
5,103,130
864,100
(32,500)
(1,095,875)
4,838,855
Vested at December 31, 2017
4,191,679
Exercisable at December 31, 2017
3,258,015
Weighted-
Average
Exercise Price
Weighted-
Average
Grant-Date
Fair Value
Millions of Dollars
Aggregate
Intrinsic Value
$
16.95
$
$
$
$
49.48
78.48
78.48
32.38
58.34
55.25
48.79
$
$
$
62
195
172
The weighted-average remaining contractual terms of vested options and exercisable options at December 31, 2017, were
5.48 years and 4.62 years, respectively. During 2017, we received $35 million in cash and realized an income tax benefit
of $9 million from the exercise of options. At December 31, 2017, the remaining unrecognized compensation expense
from unvested options was $6 million, which will be recognized over a weighted-average period of 20 months, the
longest period being 27 months. The calculations of realized income tax benefits and weighted-average periods include
awards based on both Phillips 66 and ConocoPhillips stock held by Phillips 66 employees.
110
140
111
141
2017 PHILLIPS 66 ANNUAL REPORT
During 2016 and 2015, we granted options with a weighted-average grant-date fair value of $16.94 and $18.84,
respectively. During 2016 and 2015, employees exercised options with an aggregate intrinsic value of $58 million and
$60 million, respectively.
The following table provides the significant assumptions used to calculate the grant date fair values of options granted
over the years shown below, as calculated using the Black-Scholes-Merton option-pricing model:
Risk-free interest rate
Dividend yield
Volatility factor
Expected life (years)
2017
2016
2015
2.28%
2.90%
26.91%
7.22
1.71
3.00
28.68
7.08
1.60
3.00
34.17
6.66
After the Separation and through 2015, we calculated the volatility of options granted using a formula that adjusts the
pre-Separation historical volatility of ConocoPhillips by the ratio of Phillips 66 implied market volatility on the grant
date divided by the pre-Separation implied market volatility of ConocoPhillips. In 2016, we began calculating the
volatility using historical Phillips 66 end-of-week closing stock prices from the Separation date.
Performance Share Units
Under the P66 Omnibus Plan, we annually grant to senior management restricted performance share units (PSUs) with
three-year performance periods that vest: (1) with respect to awards for performance periods beginning before 2009,
when the employee becomes eligible for retirement; or (2) with respect to awards for performance periods beginning in
2009, the shorter of: (a) the participant’s retirement eligibility date; or (b) five years after the grant date of the award; or
(3) with respect to awards for performance periods beginning in 2013 or later, at the end of the performance period on the
grant date.
For PSU awards with performance periods beginning before 2013, we recognize compensation expense beginning on the
date authorized and ending on the vest date. Since PSU awards with performance periods beginning in 2013 or later vest
on the grant date, we recognize compensation expense beginning on the date of authorization and ending on the grant
date for all employees.
We settle each PSU with performance periods beginning before 2013 by issuing one share of our common stock and
recipients receive a quarterly cash payment of a dividend equivalent beginning on the grant date and ending on the
settlement date.
PSUs with performance periods beginning in 2013 or later are settled by paying cash equal to the fair value of the
awards, which is based on the average of the high and low market prices of our stock near the end of the performance
periods. The HRCC must approve the three-year performance results prior to payout. Dividend equivalents are not paid
on these awards.
We use the average period of time elapsed between grant dates and exercise dates of past grants to estimate the expected
life of new option grants.
The following table summarizes our PSU activity from January 1, 2017, to December 31, 2017:
Restricted Stock Units
Generally, RSUs are granted annually under the provisions of the P66 Omnibus Plan and cliff vest at the end of three
years. The grant date fair value is equal to the average of the high and low market price of our stock on the grant date.
The recipients receive a quarterly cash payment of a dividend equivalent until the RSU is settled by issuing one share
of our common stock for each RSU at the end of the service period. RSUs granted to retirement eligible employees are
not subject to forfeiture six months after the grant date. Special RSUs are granted to attract or retain key personnel and
the terms and conditions may vary by award.
The following table summarizes our RSU activity from January 1, 2017, to December 31, 2017:
Outstanding at January 1, 2017
Granted
Forfeited
Issued
Outstanding at December 31, 2017
Not Vested at December 31, 2017
Stock Units
Weighted-Average
Grant-Date
Fair Value
Total Fair Value
Millions of Dollars
2,643,139
975,164
(58,171)
(1,063,707)
2,496,425
1,615,668
$
$
$
71.28
78.49
77.18
63.67
77.20
77.32
$
85
At December 31, 2017, the remaining unrecognized compensation cost from the unvested RSU awards was $50 million,
which will be recognized over a weighted-average period of 20 months, the longest period being 37 months.
During 2016 and 2015, we granted RSUs with a weighted-average grant-date fair value of $78.56 and $74.09,
respectively. During 2016 and 2015, we issued shares with an aggregate fair value of $109 million and $107 million,
respectively, to settle RSUs.
Outstanding at January 1, 2017
Granted
Issued
Cash settled
Outstanding at December 31, 2017
Not Vested at December 31, 2017
Millions of Dollars
Performance
Share Units
Weighted-Average
Grant-Date
Fair Value
Total Fair Value
3,239,497
642,212
(681,219)
(642,212)
2,558,278
286,031
$
$
$
$
50.12
86.88
42.85
86.88
52.06
66.65
54
56
At December 31, 2017, the remaining unrecognized compensation cost from unvested PSU awards held by employees of
Phillips 66 was $4 million, which will be recognized over a weighted-average period of 23 months, with the longest
period being 9 years. The calculations of unamortized expense and weighted-average periods include awards based on
both Phillips 66 and ConocoPhillips stock held by Phillips 66 employees.
During 2016 and 2015, we granted PSUs with a weighted-average grant-date fair value of $78.62 and $74.14,
respectively. During 2016 and 2015, we issued shares with an aggregate fair value of $26 million and $37 million,
respectively, to settle PSUs. We cash settled PSUs with an aggregate fair value of $60 million in 2016. No PSUs were
cash settled in 2015.
112
142
113
143
2017 PHILLIPS 66 ANNUAL REPORT
Note 21—Income Taxes
Millions of Dollars
On December 22, 2017, the U.S. government enacted comprehensive income tax legislation, referred to as the Tax Cuts
and Jobs Act (the Tax Act). The material provisions of the Tax Act i) reduced the U.S. federal corporate income tax rate
from 35 percent to 21 percent beginning January 1, 2018, ii) required companies to reflect on their 2017 corporate
income tax return a liability for a one-time deemed repatriation tax on foreign-sourced earnings that were previously tax
deferred, and iii) created a new tax regime for post-2017 foreign-sourced earnings.
To account for the reduction in the U.S. federal corporate income tax rate, we remeasured our deferred tax assets and
liabilities based on the rates at which they are expected to reverse in the future, generally 21 percent, which resulted in a
provisional deferred tax benefit of $2,870 million. To account for the one-time deemed repatriation income tax, we
calculated our provisional liability in accordance with the Tax Act and considered previously accrued current and
deferred tax liabilities on undistributed earnings of our foreign subsidiaries and foreign joint ventures. The effects of the
one-time deemed repatriation tax resulted in a provisional income tax expense of $149 million.
The provisions in the Tax Act are broad and complex. We have not yet completed our accounting for the income tax
effects of the Tax Act as of December 31, 2017, but have made reasonable estimates of those effects on our existing
deferred income tax balances and the one-time deemed repatriation tax. The final financial statement impact of the Tax
Act may differ from the above estimates, possibly materially, due to, among other things, changes in interpretations of the
Tax Act, any legislative action to address questions that arise because of the Tax Act, and changes in accounting standards
for income taxes or related interpretations in response to the Tax Act, or any updates or changes to estimates the company
has utilized to calculate the provisional impacts. The Securities and Exchange Commission (SEC) has issued rules that
would allow for a measurement period of up to one year after the enactment date of the Tax Act to finalize the recording
of the related income tax impacts.
Components of income tax expense (benefit) were:
Income Tax Expense (Benefit)
Federal
Current
Deferred
Foreign
Current
Deferred
State and local
Current
Deferred
Millions of Dollars
2017
2016
2015
$
$
9
(1,960)
126
3
61
68
(1,693)
(105)
645
66
(84)
(24)
49
547
1,128
444
(74)
42
227
(3)
1,764
Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred tax
liabilities and assets at December 31 were:
Deferred Tax Liabilities
Properties, plants and equipment, and intangibles
Investment in joint ventures
Investment in subsidiaries
Inventory
Other
Total deferred tax liabilities
Deferred Tax Assets
Benefit plan accruals
Inventory
Asset retirement obligations and accrued environmental costs
Other financial accruals and deferrals
Loss and credit carryforwards
Other
Total deferred tax assets
Less: valuation allowance
Net deferred tax assets
Net deferred tax liabilities
2017
2,942
1,923
594
—
18
5,477
314
10
121
44
96
3
588
28
560
4,917
$
$
2016
4,525
2,442
803
154
19
7,943
669
—
211
188
261
1
1,330
38
1,292
6,651
The loss and credit carryforwards deferred tax assets are primarily related to a German interest deduction carryforward of
$77 million, a U.S. alternative minimum tax credit of $10 million and a capital loss and net operating loss carryforward
in the United Kingdom of $7 million. All losses may be carried forward indefinitely and the alternative minimum credit
of $10 million, if not utilized sooner, will become refundable with the filing of the 2021 U.S. federal income tax return.
Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be
realized. During 2017, valuation allowances decreased by a total of $10 million. Based on our historical taxable income,
expectations for the future and available tax planning strategies, management expects the remaining net deferred tax
assets will be realized as offsets to reversing deferred tax liabilities and the tax consequences of future taxable income.
At December 31, 2017, all undistributed earnings of our foreign subsidiaries and foreign joint ventures have been
included in our provisional computation of the one-time deemed repatriation tax associated with the enactment of the Tax
Act. After considering the effects of the Tax Act described above, we have not provided a deferred tax liability related to
any remaining difference in the book and tax investment in our foreign subsidiaries or foreign joint ventures because such
differences are essentially permanent in duration. Based on our preliminary analysis, which is not yet complete, the
temporary difference and associated unrecorded deferred tax liability are not material.
As a result of the Separation and pursuant to the Tax Sharing Agreement with ConocoPhillips, the unrecognized income
tax benefits related to our operations for which ConocoPhillips was the taxpayer remain the responsibility of
ConocoPhillips, and we have indemnified ConocoPhillips for such amounts. Following is a reconciliation of the changes
in our unrecognized income tax benefits balance:
Balance at January 1
Additions for tax positions of prior years
Reductions for tax positions of prior years
Settlements
Balance at December 31
Millions of Dollars
2017
2016
2015
$
$
70
1
(5)
(32)
34
82
5
(17)
—
70
142
6
(17)
(49)
82
114
144
115
145
2017 PHILLIPS 66 ANNUAL REPORT
Included in the balance of unrecognized income tax benefits for 2017, 2016 and 2015 were $5 million, $13 million and
$34 million, respectively, which, if recognized, would affect our effective income tax rate. With respect to various
unrecognized income tax benefits and the related accrued liability, approximately $2 million may be recognized or paid
within the next twelve months due to completion of audits.
At December 31, 2017, 2016 and 2015, accrued liabilities for interest and penalties, net of accrued income taxes, totaled
$8 million, $12 million and $19 million, respectively. As a result of reversing certain of these accruals, earnings
increased by $1 million, $7 million and $3 million in 2017, 2016 and 2015, respectively.
We file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in significant
jurisdictions are generally complete as follows: United Kingdom (2014), Germany (2011) and United States (2010).
Certain issues remain in dispute for audited years, and unrecognized income tax benefits for years still subject to or
currently undergoing an audit are subject to change. As a consequence, the balance in unrecognized income tax benefits
can be expected to fluctuate from period to period. Although it is reasonably possible such changes could be significant
when compared with our total unrecognized income tax benefits, the amount of change is not estimable.
The amounts of U.S. and foreign income before income taxes, with a reconciliation of income tax at the federal statutory
rate to the recorded income tax expense (benefit), were:
Millions of Dollars
Percentage of
Income Before Income Taxes
2017
2016
2015
2017
2016
2015
Income before income taxes
United States
Foreign
Federal statutory income tax
State income tax, net of federal
benefit
Tax Cuts and Jobs Act
Foreign rate differential
Noncontrolling interests
Federal manufacturing deduction
Change in valuation allowance
Goodwill allocated to assets sold
German tax legislation
Sale of foreign subsidiaries
Other
$
$
$
$
2,799
756
3,555
1,244
79
(2,721)
(210)
(46)
(18)
(4)
—
—
—
(17)
(1,693)
1,713
478
2,191
4,983
1,061
6,044
78.7 %
21.3
100.0 %
78.2
21.8
100.0
82.4
17.6
100.0
767
2,115
35.0 %
12
—
(152)
(26)
—
(81)
—
—
—
27
547
150
—
(239)
(13)
(77)
(17)
41
(103)
(125)
32
1,764
2.2
(76.5)
(5.9)
(1.3)
(0.5)
(0.1)
—
—
—
(0.5)
(47.6)%
35.0
0.6
—
(6.9)
(1.2)
—
(3.7)
—
—
—
1.2
25.0
35.0
2.5
—
(3.9)
(0.2)
(1.3)
(0.2)
0.7
(1.7)
(2.1)
0.4
29.2
Included in the line item “Sale of foreign subsidiaries” is a $72 million income tax benefit realized in 2015 attributable to
the nontaxable gain from the sale of ICHP.
Income tax expense of $81 million and $150 million in 2017 and 2016, respectively, and an income tax benefit of $34
million in 2015 are reflected in the “Capital in Excess of Par” column on our consolidated statement of changes in equity.
Note 22—Accumulated Other Comprehensive Income (Loss)
Changes in the balances of each component of accumulated other comprehensive income (loss) were as follows:
Millions of Dollars
Defined
Benefit
Plans
Foreign
Currency
Translation
Hedging
Accumulated
Other
Comprehensive
Loss
$
(696)
(78)
December 31, 2014
Other comprehensive loss before reclassification
Amounts reclassified from accumulated other comprehensive
loss*
Amortization of defined benefit plan items**
Actuarial losses and settlements
Net current period other comprehensive income (loss)
December 31, 2015
Other comprehensive income (loss) before reclassifications
Amounts reclassified from accumulated other comprehensive
loss*
Amortization of defined benefit plan items**
Actuarial losses and settlements
Net current period other comprehensive income (loss)
December 31, 2016
Other comprehensive income before reclassifications
Amounts reclassified from accumulated other comprehensive
loss*
Amortization of defined benefit plan items**
Actuarial losses and settlements
Net current period other comprehensive income
December 31, 2017
$
112
34
(662)
(112)
61
(51)
(713)
3
112
115
(598)
167
(156)
—
(156)
11
(296)
—
(296)
(285)
259
—
259
(26)
(2)
—
—
—
(2)
5
—
5
3
4
—
4
7
(531)
(234)
112
(122)
(653)
(403)
61
(342)
(995)
266
112
378
(617)
* There were no significant reclassifications related to foreign currency translation or hedging.
** Included in the computation of net periodic benefit cost. See Note 19—Pension and Postretirement Plans, for additional information.
Note 23—Cash Flow Information
Supplemental Cash Flow Information
Cash Payments (Receipts)
Interest
Income taxes*
Millions of Dollars
2017
2016
2015
$
421
(257)
311
(375)
275
1,560
* 2017 and 2016 reflected a net cash refund position; cash payments for income taxes were $102 million and $385 million in 2017 and 2016, respectively.
116
146
117
147
2017 PHILLIPS 66 ANNUAL REPORT
Restricted Cash
At December 31, 2017 and 2016, the company did not have any restricted cash. The restrictions on the cash acquired in
February 2017, as a result of the consolidation of MSLP, were fully removed in May 2017 when MSLP’s outstanding
debt that contained lender restrictions on the use of cash was paid in full. See Note 5—Business Combinations and Note
12—Debt for additional information regarding MSLP.
Note 25—Related Party Transactions
Significant transactions with related parties were:
Millions of Dollars
2016
2017
Note 24—Other Financial Information
Interest and Debt Expense
Incurred
Debt
Other
Capitalized
Expensed
Other Income
Interest income
Gain on consolidation of business*
Other, net**
* See Note 5—Business Combinations regarding the gain recognized in 2017.
** Includes derivatives-related activities.
Research and Development Expenditures—expensed
Advertising Expenses
Foreign Currency Transaction (Gains) Losses—after-tax
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Millions of Dollars
2016
2017
$
$
$
$
$
$
$
$
432
21
453
(15)
438
31
423
67
521
60
76
—
—
(1)
1
—
—
402
17
419
(81)
338
18
—
56
74
60
80
—
—
(10)
1
(2)
(11)
2015
389
27
416
(106)
310
27
—
91
118
65
73
—
—
34
4
—
38
Operating revenues and other income (a)
Purchases (b)
Operating expenses and selling, general and
administrative expenses (c)
$
2,596
10,468
79
2,174
8,109
125
2015
2,452
8,142
129
As discussed more fully in Note 5—Business Combinations, in February 2017, we began accounting for MSLP as a
consolidated subsidiary. Accordingly, the table above only includes processing fees paid to MSLP through the
consolidation date.
(a) We sold NGL and other petrochemical feedstocks, along with solvents, to CPChem, and we sold gas oil and
hydrogen feedstocks to Excel Paralubes (Excel). We sold refined products to our OnCue Holdings, LLC joint
venture. We sold certain feedstocks and intermediate products to WRB and also acted as agent for WRB in
supplying crude oil and other feedstocks for a fee. In addition, we charged several of our affiliates, including
CPChem, for the use of common facilities, such as steam generators, waste and water treaters, and warehouse
facilities.
(b) We purchased crude oil and refined products from WRB and also acted as agent for WRB in distributing
solvents. We purchased natural gas and NGL from DCP Midstream and CPChem, as well as other feedstocks
from various affiliates, for use in our refinery and fractionation processes. We paid NGL fractionation fees to
CPChem. We also paid fees to various pipeline equity companies for transporting crude oil, refined products and
NGL. We purchased base oils and fuel products from Excel for use in our refining and specialty businesses.
(c) We paid utility and processing fees to various affiliates.
Note 26—Segment Disclosures and Related Information
Our operating segments are:
1) Midstream—Provides crude oil and refined products transportation, terminaling and processing services, as
well as natural gas, NGL and liquefied petroleum gas (LPG) transportation, storage, processing and marketing
services, mainly in the United States. The Midstream segment includes our master limited partnership, Phillips
66 Partners, as well as our 50 percent equity investment in DCP Midstream.
2) Chemicals—Consists of our 50 percent equity investment in CPChem, which manufactures and markets
petrochemicals and plastics on a worldwide basis.
3) Refining—Refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and
aviation fuels) at 13 refineries in the United States and Europe.
4) Marketing and Specialties—Purchases for resale and markets refined petroleum products, mainly in the United
States and Europe. In addition, this segment includes the manufacturing and marketing of specialty products, as
well as power generation operations.
118
148
119
149
2017 PHILLIPS 66 ANNUAL REPORT
Corporate and Other includes general corporate overhead, interest expense, our investments in new technologies and
various other corporate activities. Corporate assets include all cash and cash equivalents. In addition, Corporate and
Other includes the provisional income tax benefit from the enactment of the Tax Act on December 22, 2017. See Note 21
—Income Taxes for further discussion.
During the fourth quarter of 2017, the segment performance measure used by our chief executive officer to assess
performance and allocate resources was changed from “net income attributable to Phillips 66” to “net income.” This
change reflects the recognition that management does not differentiate between those earnings attributable to Phillips 66
and those attributable to noncontrolling interests when making operating and resource allocation decisions impacting
segment performance. Prior period segment information has been recast to conform to the current presentation.
Intersegment sales are at prices that we believe approximate market.
Analysis of Results by Operating Segment
Sales and Other Operating Revenues
Midstream
Total sales
Intersegment eliminations
Total Midstream
Chemicals
Refining
Total sales
Intersegment eliminations
Total Refining
Marketing and Specialties
Total sales
Intersegment eliminations
Total Marketing and Specialties
Corporate and Other
Consolidated sales and other operating revenues
Depreciation, Amortization and Impairments
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Consolidated depreciation, amortization and impairments
Millions of Dollars
2016
2017
$
$
$
$
6,620
(1,842)
4,778
5
65,494
(40,284)
25,210
73,565
(1,233)
72,332
29
102,354
299
—
838
116
89
1,342
4,226
(1,299)
2,927
5
52,068
(34,120)
17,948
64,476
(1,109)
63,367
32
84,279
218
—
770
107
78
1,173
2015
3,676
(1,034)
2,642
5
63,470
(40,317)
23,153
74,591
(1,446)
73,145
30
98,975
128
—
741
100
116
1,085
Equity in Earnings of Affiliates
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Consolidated equity in earnings of affiliates
Income Tax Expense (Benefit)
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Consolidated income tax expense (benefit)
Net Income (Loss)
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Consolidated net income
Millions of Dollars
2016
2017
$
$
$
$
$
$
454
713
322
243
—
1,732
174
191
672
334
(3,064)
(1,693)
464
525
1,404
686
2,169
5,248
184
834
164
232
—
1,414
123
256
61
370
(263)
547
280
583
374
891
(484)
1,644
2015
(268)
1,316
325
207
(7)
1,573
73
353
1,104
466
(232)
1,764
74
962
2,555
1,187
(498)
4,280
120
150
121
151
2017 PHILLIPS 66 ANNUAL REPORT
Investments In and Advances To Affiliates
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Consolidated investments in and advances to affiliates
Total Assets
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Consolidated total assets
Capital Expenditures and Investments
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Consolidated capital expenditures and investments
Interest Income and Expense
Interest income
Midstream
Marketing and Specialties
Corporate and Other
Consolidated interest income
Interest and debt expense
Corporate and Other
Millions of Dollars
2016
2017
4,734
6,222
2,398
390
—
13,744
13,231
6,226
23,820
7,103
3,991
54,371
771
—
853
108
100
1,832
1
—
30
31
4,769
5,773
2,420
391
1
13,354
12,832
5,802
22,825
6,227
3,967
51,653
1,453
—
1,149
98
144
2,844
2
—
16
18
2015
4,198
5,177
2,262
342
1
11,980
11,043
5,237
21,993
5,631
4,676
48,580
4,457
—
1,069
122
116
5,764
—
2
25
27
438
338
310
$
$
$
$
$
$
$
$
$
Sales and Other Operating Revenues by Product Line
Refined products
Crude oil resales
NGL
Other
Consolidated sales and other operating revenues by product line $
$
85,405
11,808
4,670
471
102,354
73,385
7,594
3,107
193
84,279
86,249
8,993
2,998
735
98,975
Geographic Information
Sales and Other Operating Revenues*
Long-Lived Assets**
2017
2016
2015
2017
2016
2015
Millions of Dollars
United States
United Kingdom
Germany
Other foreign countries
Worldwide consolidated
$
$
75,684
10,626
6,692
9,352
102,354
59,742
9,895
6,128
8,514
84,279
69,578
12,120
6,584
10,693
98,975
33,264
1,254
591
95
35,204
32,442
1,177
503
87
34,209
29,624
1,459
502
116
31,701
* Sales and other operating revenues are attributable to countries based on the location of the operations generating the revenues.
** Defined as net properties, plants and equipment plus investments in and advances to affiliated companies.
Note 27—Phillips 66 Partners LP
Phillips 66 Partners is a publicly traded master limited partnership formed to own, operate, develop and acquire primarily
fee-based crude oil, refined petroleum product and NGL pipelines and terminals, as well as other midstream assets.
Headquartered in Houston, Texas, Phillips 66 Partners’ assets currently consist of crude oil, refined petroleum products
and NGL transportation, terminaling and storage systems, as well as crude oil and NGL processing facilities.
We consolidate Phillips 66 Partners as a variable interest entity for financial reporting purposes. See Note 3—Variable
Interest Entities for additional information on why we consolidate the partnership. As a result of this consolidation, the
public common and perpetual convertible preferred unitholders’ ownership interests in Phillips 66 Partners are reflected
as noncontrolling interests of $2,314 million and $1,306 million on our consolidated balance sheet as of December 31,
2017, and 2016, respectively. Generally, drop down transactions to Phillips 66 Partners will eliminate in consolidation,
except for third-party debt and third-party equity offerings made by Phillips 66 Partners to finance such transactions.
At December 31, 2017, we owned a 55 percent limited partner interest and a 2 percent general partner interest in Phillips
66 Partners, while the public owned a 43 percent limited partner interest and 13.8 million perpetual convertible preferred
units.
2017 Activities
In October 2017, we contributed to Phillips 66 Partners our 25 percent interests in both Dakota Access and ETCO and
our 100 percent interest in MSLP. Total consideration for the transaction was $1.65 billion, which consisted of $372
million in cash at closing, the assumption of $588 million of promissory notes payable to us, the assumption of a $450
million term loan payable to a third party, and the issuance to us of common and general partner units with a fair value of
$240 million. Shortly after closing, Phillips 66 Partners repaid the $588 million of promissory notes payable to us,
resulting in total cash received by us for the transaction of $960 million.
Phillips 66 Partners financed the consideration paid with the proceeds from the following third-party equity and debt
offerings:
• Net proceeds of $737 million from a private placement of 13,819,791 perpetual convertible preferred units, at a
price of $54.27 per unit. Holders of the preferred units are entitled to receive cumulative quarterly distributions
equal to $0.678375 per unit. Beginning in October 2020, holders are entitled to receive quarterly distributions
equal to the greater of $0.678375 per unit or the per-unit distribution paid to common unitholders.
• Net proceeds of $295 million from a private placement of 6,304,204 common units, at a price of $47.59 per unit.
• A portion of the $643 million of net proceeds from a public offering of $650 million of Senior Notes. See Note
12—Debt for additional information on the Senior Notes.
122
152
123
153
2017 PHILLIPS 66 ANNUAL REPORT
In June 2016, Phillips 66 Partners began issuing common units under a continuous offering program, which allows for
the issuance of up to an aggregate of $250 million of Phillips 66 Partners’ common units, in amounts, at prices and on
terms to be determined by market conditions and other factors at the time of the offerings (such continuous offering
program, or at-the-market program, is referred to as the ATM program). For year ended December 31, 2017, on a
settlement-date basis, Phillips 66 Partners issued 3,372,716 common units under the ATM program, which generated net
proceeds of $173 million. From inception through December 31, 2017, Phillips 66 Partners has issued an aggregate of
3,718,868 common units under the ATM program, which generated net proceeds of $192 million.
Phillips 66 Partners filed a new shelf registration statement for Phillips 66 Partners’ second continuous offering program
that became effective with the SEC on January 23, 2018, which allows for the issuance of up to an aggregate of $250
million of Phillips 66 Partners’ common units, in amounts, at prices and on terms to be determined by market conditions
and other factors at the time of the offerings.
Note 28—New Accounting Standards
In February 2017, the FASB issued ASU No. 2017-05, “Other Income—Gains and Losses from the Derecognition of
Nonfinancial Assets (Subtopic 610-20).” This ASU clarifies the scope and accounting for the sale or transfer of
nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. This ASU will
eliminate the use of carryover basis for most nonmonetary exchanges, including contributions of assets to equity method
joint ventures. These amendments could result in the entity recognizing a gain or loss on the sale or transfer of
nonfinancial assets. Public entities should apply the guidance in ASU No. 2017-05 to annual periods beginning after
December 15, 2017, including interim periods within those periods. There was no impact on our financial statements
from adopting this ASU on January 1, 2018.
In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a
Business,” which clarifies the definition of a business with the objective of adding guidance to assist in evaluating
whether transactions should be accounted for as acquisitions of assets or businesses. The amendment provides a screen
for determining when a transaction involves an acquisition of a business. If substantially all of the fair value of the gross
assets acquired is concentrated in a single identifiable asset, or a group of similar identifiable assets, then the transaction
is not considered an acquisition of a business. If the screen is not met, then the amendment requires that to be considered
a business, the operation must include at a minimum an input and a substantive process that together significantly
contribute to the ability to create an output. The guidance may reduce the number of transactions accounted for as
business acquisitions. Public business entities should apply the guidance in ASU No. 2017-01 to annual periods
beginning after December 15, 2017, including interim periods within those periods, with early adoption permitted. The
amendments should be applied prospectively and no disclosures are required at the effective date. There was no impact
on our financial statements from adopting this ASU on January 1, 2018.
In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of
Credit Losses on Financial Instruments.” The new standard amends the impairment model to utilize an expected loss
methodology in place of the currently used incurred loss methodology, which may result in earlier recognition of losses.
Public business entities should apply the guidance in ASU No. 2016-13 for annual periods beginning after December 15,
2019, including interim periods within those annual periods. Early adoption will be permitted for annual periods
beginning after December 15, 2018. We are currently evaluating the provisions of ASU No. 2016-13 and assessing the
impact on our financial statements.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” The new standard establishes a right-of-use
(ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with
terms longer than 12 months. Leases will continue to be classified as either finance or operating, with classification
affecting the pattern of expense recognition in the income statement. Similarly, lessors will be required to classify leases
as sales-type, finance or operating, with classification affecting the pattern of income recognition. Classification for both
lessees and lessors will be based on an assessment of whether risks and rewards as well as substantive control have been
transferred through a lease contract. Public business entities should apply the guidance in ASU No. 2016-02 for annual
periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is
permitted. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional
practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or entered into
after the earliest comparative period presented in the financial statements. We are currently evaluating the provisions of
ASU No. 2016-02 and assessing its impact on our financial statements. As part of our assessment to-date, we have
formed an implementation team, commenced identification of our lease population and selected a lease software package.
We expect the adoption of ASU 2016-02 will materially gross up our consolidated balance sheet with the recognition of
the ROU assets and operating lease liabilities. The impact to our consolidated statements of income and cash flows is not
expected to be material. The new standard will also require additional disclosures for financing and operating leases.
In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments—Overall (Subtopic 825-10): Recognition
and Measurement of Financial Assets and Financial Liabilities,” to meet its objective of providing more decision-useful
information about financial instruments. The majority of this ASU’s provisions amend only the presentation or
disclosures of financial instruments; however, one provision will also affect net income. Equity investments carried
under the cost method or lower of cost or fair value method of accounting, in accordance with current GAAP, will have to
be carried at fair value upon adoption of ASU No. 2016-01, with changes in fair value recorded in net income. For equity
investments that do not have readily determinable fair values, a company may elect to carry such investments at cost less
impairments, if any, adjusted up or down for price changes in similar financial instruments issued by the investee, when
and if observed. Public business entities should apply the guidance in ASU No. 2016-01 for annual periods beginning
after December 15, 2017, and interim periods within those annual periods, with early adoption prohibited. We are
currently evaluating the provisions of ASU No. 2016-01. Our initial review indicates that ASU No. 2016-01 will have a
limited impact on our financial statements.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This ASU
and other related updates are intended to improve comparability of revenue recognition practices across entities,
industries, jurisdictions and capital markets and expand disclosure requirements. In August 2015, the FASB issued ASU
No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The amendment in
this ASU defers the effective date of ASU No. 2014-09 for all entities for one year. Public business entities should apply
the guidance in ASU No. 2014-09 to annual reporting periods beginning after December 15, 2017, including interim
reporting periods within that reporting period. Our assessment work primarily included the formation of an
implementation work team, training on the new ASU’s revenue recognition model, contract review and documentation
and the monitoring of industry interpretative issues. We adopted the standard on January 1, 2018, using the modified
retrospective application. Our evaluation of the new ASU is near completion, which includes understanding the impact
of adoption on earnings from equity method investments. Based upon our analysis to-date, the primary impact of
adoption of the new standard is the netting of sales-based taxes collected from our customers against revenue. Sales-
based taxes include excise taxes on sales of petroleum products as noted on our consolidated statement of income. We
have not identified any other material impact on our financial statements other than disclosures.
Note 29—Condensed Consolidating Financial Information
Phillips 66 has $6.0 billion of senior notes outstanding, the payment obligations of which are fully and unconditionally
guaranteed by Phillips 66 Company, a 100-percent-owned subsidiary. The following condensed consolidating financial
information presents the results of operations, financial position and cash flows for:
•
Phillips 66 and Phillips 66 Company (in each case, reflecting investments in subsidiaries utilizing the equity
method of accounting).
• All other nonguarantor subsidiaries.
• The consolidating adjustments necessary to present Phillips 66’s results on a consolidated basis.
124
154
125
155
2017 PHILLIPS 66 ANNUAL REPORT This condensed consolidating financial information should be read in conjunction with the accompanying consolidated
financial statements and notes.
Statement of Income
Revenues and Other Income
Sales and other operating revenues
Equity in earnings of affiliates
Net gain on dispositions
Other income
Intercompany revenues
Total Revenues and Other Income
Costs and Expenses
Purchased crude oil and products
Operating expenses
Selling, general and administrative expenses
Depreciation and amortization
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Total Costs and Expenses
Income before income taxes
Income tax benefit
Net Income
Less: net income attributable to noncontrolling interests
Net Income Attributable to Phillips 66
Comprehensive Income
Millions of Dollars
Year Ended December 31, 2017
Phillips 66
Phillips 66
Company
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
$
$
—
5,336
—
3
—
5,339
—
—
7
—
—
—
—
348
355
4,984
(122)
5,106
—
5,106
74,640
3,256
1
471
1,610
79,978
63,812
3,672
1,300
892
20
5,784
17
70
75,567
4,411
(925)
5,336
—
5,336
27,714
559
14
47
13,457
41,791
30,379
1,085
399
426
4
7,678
5
236
40,212
1,579
(646)
2,225
142
2,083
—
(7,419)
—
—
(15,067)
(22,486)
(14,782)
(58)
(11)
—
—
—
—
(216)
(15,067)
(7,419)
—
(7,419)
—
(7,419)
102,354
1,732
15
521
—
104,622
79,409
4,699
1,695
1,318
24
13,462
22
438
101,067
3,555
(1,693)
5,248
142
5,106
5,484
5,714
2,498
(8,070)
5,626
Statement of Income
Revenues and Other Income
Sales and other operating revenues
Equity in earnings of affiliates
Net gain (loss) on dispositions
Other income
Intercompany revenues
Total Revenues and Other Income
Costs and Expenses
Purchased crude oil and products
Operating expenses
Selling, general and administrative expenses
Depreciation and amortization
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction gains
Total Costs and Expenses
Income before income taxes
Income tax expense (benefit)
Net Income
Less: net income attributable to noncontrolling interests
Net Income Attributable to Phillips 66
Comprehensive Income
Millions of Dollars
Year Ended December 31, 2016
Phillips 66
Phillips 66
Company
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
$
$
—
1,797
—
—
—
1,797
—
—
6
—
—
—
—
366
—
372
1,425
(130)
1,555
—
1,555
58,822
1,839
(9)
42
864
61,558
48,171
3,465
1,236
821
1
5,477
16
21
—
59,208
2,350
553
1,797
—
1,797
25,457
296
19
32
9,160
34,964
24,102
846
406
347
4
8,211
5
124
(15)
34,030
934
124
810
89
721
—
(2,518)
—
—
(10,024)
(12,542)
(9,805)
(36)
(10)
—
—
—
—
(173)
—
(10,024)
(2,518)
—
(2,518)
—
(2,518)
84,279
1,414
10
74
—
85,777
62,468
4,275
1,638
1,168
5
13,688
21
338
(15)
83,586
2,191
547
1,644
89
1,555
1,213
1,455
451
(1,817)
1,302
126
156
127
157
2017 PHILLIPS 66 ANNUAL REPORT Statement of Income
Revenues and Other Income
Sales and other operating revenues
Equity in earnings (losses) of affiliates
Net gain (loss) on dispositions
Other income
Intercompany revenues
Total Revenues and Other Income
Costs and Expenses
Purchased crude oil and products
Operating expenses
Selling, general and administrative expenses
Depreciation and amortization
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction losses
Total Costs and Expenses
Income before income taxes
Income tax expense (benefit)
Net Income
Less: net income attributable to noncontrolling interests
Net Income Attributable to Phillips 66
Comprehensive Income
Millions of Dollars
Year Ended December 31, 2015
Phillips 66
Phillips 66
Company
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
$
$
—
4,470
—
—
—
4,470
—
4
5
—
—
—
—
365
—
374
4,096
(131)
4,227
—
4,227
68,478
2,812
(115)
81
1,071
72,327
54,925
3,412
1,265
818
4
5,505
16
25
1
65,971
6,356
1,886
4,470
—
4,470
30,497
(134)
398
37
9,845
40,643
29,221
917
416
260
3
8,572
5
34
48
39,476
1,167
9
1,158
53
1,105
—
(5,575)
—
—
(10,916)
(16,491)
(10,747)
(39)
(16)
—
—
—
—
(114)
—
(10,916)
(5,575)
—
(5,575)
—
(5,575)
98,975
1,573
283
118
—
100,949
73,399
4,294
1,670
1,078
7
14,077
21
310
49
94,905
6,044
1,764
4,280
53
4,227
4,105
4,348
1,032
(5,327)
4,158
128
158
Balance Sheet
Assets
Cash and cash equivalents
Accounts and notes receivable
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments and long-term receivables
Net properties, plants and equipment
Goodwill
Intangibles
Other assets
Total Assets
Liabilities and Equity
Accounts payable
Short-term debt
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Long-term debt
Asset retirement obligations and accrued
environmental costs
Deferred income taxes
Employee benefit obligations
Other liabilities and deferred credits
Total Liabilities
Common stock
Retained earnings
Accumulated other comprehensive loss
Noncontrolling interests
Total Liabilities and Equity
Millions of Dollars
At December 31, 2017
Phillips 66
Phillips 66
Company
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
1,411
5,317
2,386
276
9,390
23,483
13,117
2,853
722
266
49,831
7,272
9
451
513
298
8,543
50
467
3,349
639
4,700
17,748
24,952
7,748
(617)
—
49,831
1,708
4,476
1,009
92
7,285
9,959
8,343
417
154
158
26,316
3,052
32
551
69
102
3,806
3,047
174
1,661
245
3,814
12,747
10,125
1,306
(205)
2,343
26,316
—
(2,297)
—
—
(2,297)
(51,626)
—
—
—
(2)
(53,925)
(2,297)
—
—
—
—
(2,297)
—
—
(2)
—
(8,288)
(10,587)
(35,077)
(9,083)
822
—
(53,925)
3,119
7,506
3,395
370
14,390
13,941
21,460
3,270
876
434
54,371
8,027
41
1,002
582
455
10,107
10,069
641
5,008
884
234
26,943
9,396
16,306
(617)
2,343
54,371
$
$
$
$
—
10
—
2
12
32,125
—
—
—
12
32,149
—
—
—
—
55
55
6,972
—
—
—
8
7,035
9,396
16,335
(617)
—
32,149
129
159
2017 PHILLIPS 66 ANNUAL REPORT Balance Sheet
Assets
Cash and cash equivalents
Accounts and notes receivable
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments and long-term receivables
Net properties, plants and equipment
Goodwill
Intangibles
Other assets
Total Assets
Liabilities and Equity
Accounts payable
Short-term debt
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Long-term debt
Asset retirement obligations and accrued
environmental costs
Deferred income taxes
Employee benefit obligations
Other liabilities and deferred credits
Total Liabilities
Common stock
Retained earnings
Accumulated other comprehensive loss
Noncontrolling interests
Total Liabilities and Equity
Millions of Dollars
At December 31, 2016
Phillips 66
Phillips 66
Company
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
854
4,336
2,198
317
7,705
22,733
13,044
2,853
719
245
47,299
5,626
30
348
475
371
6,850
150
501
4,391
948
3,337
16,177
25,403
6,714
(995)
—
47,299
1,857
3,276
952
103
6,188
8,588
7,811
417
169
168
23,341
2,663
20
457
52
90
3,282
2,518
154
2,354
268
4,060
12,636
10,117
(269)
(478)
1,335
23,341
—
(1,228)
—
—
(1,228)
(48,952)
—
—
—
(2)
(50,182)
(1,228)
—
—
—
—
(1,228)
—
—
(2)
—
(8,431)
(9,661)
(35,520)
(6,474)
1,473
—
(50,182)
2,711
6,397
3,150
422
12,680
13,534
20,855
3,270
888
426
51,653
7,061
550
805
527
520
9,463
9,588
655
6,743
1,216
263
27,928
10,777
12,608
(995)
1,335
51,653
$
$
$
$
—
13
—
2
15
31,165
—
—
—
15
31,195
—
500
—
—
59
559
6,920
—
—
—
1,297
8,776
10,777
12,637
(995)
—
31,195
130
160
Statement of Cash Flows
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments*
Proceeds from asset dispositions**
Intercompany lending activities
Advances/loans—related parties
Collection of advances/loans—related parties
Restricted cash received from consolidation of business
Other
Net Cash Provided by (Used in) Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of common stock
Repurchase of common stock
Dividends paid on common stock
Distributions to noncontrolling interests
Net proceeds from issuance of Phillips 66 Partners LP
common and preferred units
Other*
Net Cash Provided by (Used in) Financing Activities
Effect of Exchange Rate Changes on Cash, Cash
Equivalents and Restricted Cash
Net Change in Cash, Cash Equivalents and
Restricted Cash
Cash, cash equivalents and restricted cash at beginning
of period
Cash, Cash Equivalents and Restricted Cash at End of
Period
$
* Includes intercompany capital contributions.
** Includes return of investments in equity affiliates.
Millions of Dollars
Year Ended December 31, 2017
Phillips 66
Phillips 66
Company
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
2,619
2,702
1,747
(3,420)
3,648
(1,133)
265
1,453
(10)
75
—
(26)
624
—
(17)
—
—
(2,752)
—
—
—
(2,769)
—
557
854
1,411
(839)
84
(1,854)
—
251
318
(8)
(2,048)
2,008
(2,161)
—
—
(668)
(120)
1,205
(129)
135
17
(149)
1,857
1,708
140
(263)
—
—
—
—
—
(123)
—
—
—
—
3,420
—
—
123
3,543
—
—
—
—
(1,832)
86
—
(10)
326
318
(34)
(1,146)
3,508
(3,678)
35
(1,590)
(1,395)
(120)
1,205
(76)
(2,111)
17
408
2,711
3,119
—
—
401
—
—
—
—
401
1,500
(1,500)
35
(1,590)
(1,395)
—
—
(70)
(3,020)
—
—
—
—
131
161
2017 PHILLIPS 66 ANNUAL REPORT Statement of Cash Flows
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments**
Proceeds from asset dispositions***
Intercompany lending activities
Advances/loans—related parties
Collection of advances/loans—related parties
Other
Net Cash Provided by (Used in) Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of common stock
Repurchase of common stock
Dividends paid on common stock
Distributions to noncontrolling interests
Net proceeds from issuance of Phillips 66 Partners LP
common units
Other**
Net Cash Provided by (Used in) Financing Activities
Effect of Exchange Rate Changes on Cash, Cash
Equivalents and Restricted Cash
Net Change in Cash, Cash Equivalents and
Restricted Cash
Cash, cash equivalents and restricted cash at beginning
of period
Millions of Dollars
Year Ended December 31, 2016
Phillips 66
Phillips 66
Company
All Other
Subsidiaries*
Consolidating
Adjustments
Total
Consolidated
$
3,491
2,307
1,552
(4,387)
2,963
—
—
(1,139)
—
—
—
(1,139)
—
—
34
(1,042)
(1,282)
—
—
(62)
(2,352)
—
—
—
(1,425)
1,007
2,046
(75)
—
18
1,571
—
(26)
—
—
(3,604)
—
—
31
(3,599)
—
279
575
(1,457)
156
(907)
(357)
108
(164)
(2,621)
2,090
(807)
—
—
(783)
(75)
972
(980)
417
10
(642)
2,499
38
(1,007)
—
—
—
—
(969)
—
—
—
—
4,387
—
—
969
5,356
—
—
—
(2,844)
156
—
(432)
108
(146)
(3,158)
2,090
(833)
34
(1,042)
(1,282)
(75)
972
(42)
(178)
10
(363)
3,074
Cash, Cash Equivalents and Restricted Cash at End of
2,711
Period
* Revised to eliminate a purchase and sale transaction between two entities consolidated within the column. This revision increased net cash provided by
operating activities by $1,049 million, with an offsetting decrease of $1,049 million in net cash provided by financing activities. The revision did not
impact any issuer or guarantor column, nor did it impact our consolidated cash flows.
1,857
854
—
—
$
** Includes intercompany capital contributions.
*** Includes return of investments in equity affiliates.
Millions of Dollars
Year Ended December 31, 2015
Phillips 66
Phillips 66
Company
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
1,060
4,879
2,564
(2,790)
5,713
—
—
2,461
—
—
—
2,461
—
(800)
31
(1,512)
(1,172)
—
—
—
(68)
(3,521)
—
—
—
—
(2,815)
774
(3,153)
(50)
50
6
(5,188)
—
(23)
—
—
(1,172)
—
—
—
34
(1,161)
(5,283)
178
692
—
—
(50)
(4,463)
1,169
(103)
—
—
(1,576)
(186)
(46)
384
1,585
1,227
—
9
(1,470)
(663)
2,045
575
3,162
2,499
2,334
(882)
—
—
—
—
1,452
—
—
—
—
2,748
186
—
—
(1,596)
1,338
—
—
—
—
(5,764)
70
—
(50)
50
(44)
(5,738)
1,169
(926)
31
(1,512)
(1,172)
—
(46)
384
(45)
(2,117)
9
(2,133)
5,207
3,074
Statement of Cash Flows
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments*
Proceeds from asset dispositions**
Intercompany lending activities
Advances/loans—related parties
Collection of advances/loans—related parties
Other
Net Cash Provided by (Used in) Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of common stock
Repurchase of common stock
Dividends paid on common stock
Distributions to controlling interests
Distributions to noncontrolling interests
Net proceeds from issuance of Phillips 66 Partners LP
common units
Other*
Net Cash Provided by (Used in) Financing Activities
Effect of Exchange Rate Changes on Cash, Cash
Equivalents and Restricted Cash
Net Change in Cash, Cash Equivalents and
Restricted Cash
Cash, cash equivalents and restricted cash at beginning
of period
Cash, Cash Equivalents and Restricted Cash at End of
Period
$
* Includes intercompany capital contributions.
** Includes return of investments in equity affiliates.
Note 30—Subsequent Event
On February 13, 2018, we entered into a Stock Purchase and Sale Agreement (Purchase Agreement) with Berkshire
Hathaway Inc. and National Indemnity Company, a wholly owned subsidiary of Berkshire Hathaway, to repurchase 35
million shares of Phillips 66 common stock for an aggregate purchase price of approximately $3.3 billion. Pursuant to
the Purchase Agreement, the purchase price per share of $93.725 was based on the volume-weighted-average price of our
common stock on the New York Stock Exchange on February 13, 2018. The transaction closed on February 14, 2018.
We funded the repurchase with cash on hand of approximately $1.9 billion and borrowings of approximately $1.4 billion
under our commercial paper program. This specific share repurchase transaction was separately authorized by our Board
of Directors and therefore does not impact previously announced authorizations which total up to $12.0 billion.
132
162
133
163
2017 PHILLIPS 66 ANNUAL REPORT Selected Quarterly Financial Data (Unaudited)
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
Sales and
Other
Operating
Revenues*
$
22,894
24,087
25,627
29,746
2017
First
Second
Third
Fourth**
$
2016
First
Second
Third
Fourth
* Includes excise taxes on sales of petroleum products.
17,409
21,849
21,624
23,397
Millions of Dollars
Income Before
Income Taxes
Net
Income
Net Income
Attributable
to Phillips 66
Per Share of Common Stock
Net Income Attributable to
Phillips 66
Basic
Diluted
797
848
1,256
654
596
720
813
62
563
581
849
3,255
398
516
536
194
535
550
823
3,198
385
496
511
163
1.02
1.06
1.60
6.29
0.72
0.94
0.97
0.31
1.02
1.06
1.60
6.25
0.72
0.93
0.96
0.31
** Includes a $2,721 million provisional income tax benefit from the enactment of the U.S. Tax Cuts and Jobs Act on December 22, 2017.
FINANCIAL DISCLOSURE
None.
Item 9A. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports
we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized
and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and
communicated to management, including our principal executive and principal financial officers, as appropriate, to allow
timely decisions regarding required disclosure. As of December 31, 2017, with the participation of management, our
Chairman and Chief Executive Officer and our Executive Vice President, Finance and Chief Financial Officer carried out
an evaluation, pursuant to Rule 13a-15(b) of the Act, of the effectiveness of our disclosure controls and procedures (as
defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our
Executive Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures
were operating effectively as of December 31, 2017.
There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the
quarterly period ended December 31, 2017, that have materially affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
This report is included in Item 8 and is incorporated herein by reference.
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
This report is included in Item 8 and is incorporated herein by reference.
Item 9B. OTHER INFORMATION
None.
134
164
135
165
2017 PHILLIPS 66 ANNUAL REPORT Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PART III
PART IV
Information regarding our executive officers appears in Part I of this report.
The remaining information required by Item 10 of Part III is incorporated herein by reference from our Proxy Statement
for the Annual Meeting of Stockholders to be held on May 9, 2018, which will be filed within 120 days after
December 31, 2017 (2018 Definitive Proxy Statement).*
Item 11. EXECUTIVE COMPENSATION
The information required by Item 11 of Part III is incorporated herein by reference from our 2018 Definitive Proxy
Statement.*
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information required by Item 12 of Part III is incorporated herein by reference from our 2018 Definitive Proxy
Statement.*
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The information required by Item 13 of Part III is incorporated herein by reference from our 2018 Definitive Proxy
Statement.*
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by Item 14 of Part III is incorporated herein by reference from our 2018 Definitive Proxy
Statement.*
_________________________
* Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing in our 2018
Definitive Proxy Statement are not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a part of this report.
(a) 1.
Financial Statements and Supplementary Data
The financial statements and supplementary information listed in the Index to Financial Statements, which
appears on page 70, are filed as part of this Annual Report on Form 10-K.
2.
Financial Statement Schedules
All financial statement schedules are omitted because they are not required, not significant, not applicable, or
the information is shown in the financial statements or notes thereto.
3. Exhibits
The exhibits listed in the Index to Exhibits, which appears on pages 138 to 141, are filed as part of this Annual
Report on Form 10-K.
(c)
Pursuant to Rule 3-09 of Regulation S-X, the financial statements of Chevron Phillips Chemical Company
LLC as of December 31, 2017 and 2016, and for each of the three years ended December 31, 2017, are
included as an exhibit to this Annual Report on Form 10-K.
Item 16. FORM 10-K SUMMARY
None.
136
166
137
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2017 PHILLIPS 66 ANNUAL REPORT
PHILLIPS 66
INDEX TO EXHIBITS
Exhibit
Number
2.1
3.1
3.2
4.1
10.1
10.2
10.3
10.4
10.5
10.6*
10.7
Exhibit Description
Separation and Distribution Agreement between
ConocoPhillips and Phillips 66, dated April 26, 2012.
Amended and Restated Certificate of Incorporation of
Phillips 66.
Amended and Restated By-Laws of Phillips 66.
Indenture, dated as of March 12, 2012, among Phillips 66,
as issuer, Phillips 66 Company, as guarantor, and The Bank
of New York Mellon Trust Company, N.A., as trustee, in
respect of senior debt securities of Phillips 66.
As permitted by Item 601(b)(4)(iii)(A) of Regulation S-K,
the company has not filed with this Annual Report on
Form 10-K certain instruments defining the rights of
holders of long-term debt of the company and its
subsidiaries because the total amount of securities
authorized thereunder does not exceed 10 percent of the
total assets of the company and its subsidiaries on a
consolidated basis. The company agrees to furnish a copy
of such agreements to the Commission upon request.
Credit Agreement among Phillips 66, Phillips 66 Company,
JPMorgan Chase Bank, N.A., as Administrative Agent, and
the lenders named therein, dated as of February 22, 2012.
First Amendment to Credit Agreement among Phillips 66,
Phillips 66 Company, JPMorgan Chase Bank, N.A., and
lenders named therein, dated as of June 10, 2013.
Second Amendment to Credit Agreement among Phillips
66, Phillips 66 Company, JPMorgan Chase Bank, N.A.,
and lenders named therein, dated as of December 10, 2014.
Third Amendment to Credit Agreement among Phillips 66,
Phillips 66 Company, JPMorgan Chase Bank, N.A., and
lenders named therein, dated as of October 3, 2016.
Third Amended and Restated Limited Liability Company
Agreement of Chevron Phillips Chemical Company LLC,
effective as of May 1, 2012.
First Amendment to Third Amended and Restated Limited
Liability Company Agreement of Chevron Phillips
Chemical Company LLC, effective as of December 31,
2017.
Second Amended and Restated Limited Liability Company
Agreement of Duke Energy Field Services, LLC, dated
July 5, 2005, by and between ConocoPhillips Gas
Company and Duke Energy Enterprises Corporation.
Incorporated by Reference
Form
Exhibit
Number
Filing
Date
SEC
File No.
8-K
8-K
8-K
10
2.1 05/01/2012 001-35349
3.1 05/01/2012 001-35349
3.1 02/09/2017 001-35349
4.3 04/05/2012 001-35349
Exhibit
Number
10.8
10.9
10.10
10.11
10
4.1 03/01/2012 001-35349
10.12
10-Q
10.1 05/01/2014 001-35349
10-K
10.3 02/20/2015 001-35349
10-K
10.4 02/17/2017 001-35349
10-Q
10.14 08/03/2012 001-35349
10
10.12 03/01/2012 001-35349
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
Exhibit Description
First Amendment to Second Amended and Restated
Limited Liability Company Agreement of Duke Energy
Field Services, LLC, dated August 11, 2006, by and
between ConocoPhillips Gas Company and Duke Energy
Enterprises Corporation.
Second Amendment to Second Amended and Restated
Limited Liability Company Agreement of DCP Midstream,
LLC (formerly Duke Energy Field Services, LLC), dated
February 1, 2007, by and between ConocoPhillips Gas
Company, Spectra Energy DEFS Holding, LLC, and
Spectra Energy DEFS Holding Corp.
Third Amendment to Second Amended and Restated
Limited Liability Company Agreement of DCP Midstream,
LLC (formerly Duke Energy Field Services, LLC), dated
April 30, 2009, by and between ConocoPhillips Gas
Company, Spectra Energy DEFS Holding, LLC, and
Spectra Energy DEFS Holding Corp.
Fourth Amendment to Second Amended and Restated
Limited Liability Company Agreement of DCP Midstream,
LLC (formerly Duke Energy Field Services, LLC), dated
November 9, 2010, by and between ConocoPhillips Gas
Company, Spectra Energy DEFS Holding, LLC, and
Spectra Energy DEFS Holding Corp.
Fifth Amendment to July 5, 2005 Second Amended and
Restated Limited Liability Company Agreement of DCP
Midstream, LLC (formerly Duke Energy Field Services,
LLC) dated September 9, 2014, by and between Phillips
Gas Company (formerly ConocoPhillips Gas Company),
Spectra Energy DEFS Holding, LLC, and Spectra Energy
DEFS Holding II, LLC.
Indemnification and Release Agreement between
ConocoPhillips and Phillips 66, dated April 26, 2012.
Intellectual Property Assignment and License Agreement
between ConocoPhillips and Phillips 66, dated April 26,
2012.
Tax Sharing Agreement between ConocoPhillips and
Phillips 66, dated April 26, 2012.
Incorporated by Reference
Form
Exhibit
Number
Filing
Date
SEC
File No.
10
10.13 03/01/2012 001-35349
10
10.14 03/01/2012 001-35349
10
10.15 03/01/2012 001-35349
10
10.16 03/01/2012 001-35349
10-Q
10.1 10/30/2014 001-35349
8-K
10.1 05/01/2012 001-35349
8-K
10.2 05/01/2012 001-35349
8-K
10.3 05/01/2012 001-35349
Employee Matters Agreement between ConocoPhillips and
Phillips 66, dated April 26, 2012.
8-K
10.4 05/01/2012 001-35349
Amendment to the Employee Matters Agreement by and
between ConocoPhillips and Phillips 66, dated April 26,
2012.
Transition Services Agreement between ConocoPhillips
and Phillips 66, dated April 26, 2012.
10-Q
10.1 05/02/2013 001-35349
8-K
10.5 05/01/2012 001-35349
2013 Omnibus Stock and Performance Incentive Plan of
Phillips 66.**
DEF14A
App. A 03/27/2013 001-35349
Phillips 66 Key Employee Supplemental Retirement
Plan.**
10-Q
10.15 08/03/2012 001-35349
138
168
139
169
2017 PHILLIPS 66 ANNUAL REPORT
Exhibit
Number
Exhibit Description
First Amendment to the Phillips 66 Key Employee
Supplemental Retirement Plan.**
Phillips 66 Amended and Restated Executive Severance
Plan.**
Phillips 66 Deferred Compensation Plan for Non-
Employee Directors.**
Phillips 66 Key Employee Deferred Compensation Plan-
Title I.**
Phillips 66 Key Employee Deferred Compensation Plan-
Title II.**
First Amendment to the Phillips 66 Key Employee
Deferred Compensation Plan Title II.**
Incorporated by Reference
Form
Exhibit
Number
Filing
Date
SEC
File No.
10-K
10.18 02/22/2013 001-35349
Exhibit
Number
99.1*
Exhibit Description
The financial statements of Chevron Phillips Chemical
Company, LLC, pursuant to Rule 3-09 of Regulation S-X.
Incorporated by Reference
Form
Exhibit
Number
Filing
Date
SEC
File No.
10-Q
10.1 07/29/2016 001-35349
101.INS* XBRL Instance Document.
10-Q
10.17 08/03/2012 001-35349
10-Q
10.18 08/03/2012 001-35349
101.SCH* XBRL Schema Document.
101.CAL* XBRL Calculation Linkbase Document.
101.LAB* XBRL Labels Linkbase Document.
10-Q
10.19 08/03/2012 001-35349
101.PRE* XBRL Presentation Linkbase Document.
10-K
10.24 02/22/2013 001-35349
101.DEF* XBRL Definition Linkbase Document.
* Filed herewith.
** Management contracts and compensatory plans or arrangements.
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
10.34
12*
21*
23.1*
23.2*
31.1*
31.2*
Phillips 66 Defined Contribution Make-Up Plan Title I.**
Phillips 66 Defined Contribution Make-Up Plan Title II.**
Phillips 66 Key Employee Change in Control Severance
Plan.**
10-Q
10-K
10-K
10.20 08/03/2012 001-35349
10.26 02/22/2013 001-35349
10.27 02/22/2013 001-35349
First Amendment to Phillips 66 Key Employee Change in
Control Severance Plan, Effective October 2, 2015.**
8-K
10.1 11/08/2013 001-35349
Annex to the Phillips 66 Nonqualified Deferred
Compensation Arrangements.**
10-Q
10.23 08/03/2012 001-35349
10-K
10.29 02/22/2013 001-35349
10-K
10.30 02/22/2013 001-35349
10-K
10.31 02/22/2013 001-35349
Form of Stock Option Award Agreement under the 2013
Omnibus Stock and Performance Incentive Plan of Phillips
66.**
Form of Restricted Stock or Restricted Stock Unit Award
Agreement under the 2013 Omnibus Stock and
Performance Incentive Plan of Phillips 66.**
Form of Performance Share Unit Award Agreement under
the 2013 Omnibus Stock and Performance Incentive Plan
of Phillips 66.**
Computation of Ratio of Earnings to Fixed Charges.
List of Subsidiaries of Phillips 66.
Consent of Ernst & Young LLP, independent registered
public accounting firm.
Consent of Ernst & Young LLP, independent auditors for
Chevron Phillips Chemicals Company LLC.
Certification of Chief Executive Officer pursuant to Rule
13a-14(a) under the Securities Exchange Act of 1934.
Certification of Chief Financial Officer pursuant to Rule
13a-14(a) under the Securities Exchange Act of 1934.
32*
Certifications pursuant to 18 U.S.C. Section 1350.
140
170
141
171
2017 PHILLIPS 66 ANNUAL REPORT
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
Date: February 23, 2018
PHILLIPS 66
/s/ Greg C. Garland
Greg C. Garland
Chairman of the Board of Directors
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below, as of
February 23, 2018, by the following persons on behalf of the registrant, and in the capacities indicated.
Signature
Title
/s/ Greg C. Garland
Greg C. Garland
/s/ Kevin J. Mitchell
Kevin J. Mitchell
Chairman of the Board of Directors
and Chief Executive Officer
(Principal executive officer)
Executive Vice President, Finance
and Chief Financial Officer
(Principal financial officer)
/s/ Chukwuemeka A. Oyolu
Chukwuemeka A. Oyolu
Vice President and Controller
(Principal accounting officer)
/s/ Gary K. Adams
Gary K. Adams
/s/ J. Brian Ferguson
J. Brian Ferguson
/s/ William R. Loomis Jr.
William R. Loomis Jr.
/s/ John E. Lowe
John E. Lowe
/s/ Harold W. McGraw III
Harold W. McGraw III
/s/ Denise L. Ramos
Denise L. Ramos
/s/ Glenn F. Tilton
Glenn F. Tilton
/s/ Victoria J. Tschinkel
Victoria J. Tschinkel
/s/ Marna C. Whittington
Marna C. Whittington
Director
Director
Director
Director
Director
Director
Director
Director
Director
142
172
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P H I L L I P S 6 6 . C O M
174
© 2018 PHILLIPS 66 COMPANY. ALL RIGHTS RESERVED
CM 17-0667
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2017 PHILLIPS 66 ANNUAL REPORT