ANNUAL
REPORT
LETTER TO OUR SHAREHOLDERS
TABLE OF CONTENTS
1
4
6
OUR BUSINESSES
MIDSTREAM
FINANCIAL HIGHLIGHTS
CHEMICALS
REFINING
MARKETING AND SPECIALTIES
OUR VALUE CHAIN
OUR STRATEGY
OPERATING EXCELLENCE
GROWTH
RETURNS
DISTRIBUTIONS
HIGH-PERFORMING ORGANIZATION
BOARD OF DIRECTORS
EXECUTIVE LEADERSHIP TEAM
NON-GAAP RECONCILIATIONS
FORM 10-K
7
8
26
28
29
30
| ON THE COVER
Ponca City Refinery Atmospheric Tower PONCA CITY, OK
| Lake Charles Refinery Gasoline Storage Tanks
WESTLAKE, LA
1
TO OUR SHAREHOLDERS
Phillips 66 had a record-setting year in 2018. Our
earnings of $5.6 billion and earnings per share of $11.80
were our highest ever. We generated $7.6 billion of
operating cash flow and rewarded our shareholders with
strong distributions.
We increased our quarterly dividend 14 percent and repurchased
10 percent of shares outstanding, returning $6.1 billion to
shareholders. Since 2012, we have returned $22.5 billion to
shareholders through dividends, share repurchases and share
exchanges, reducing our initial shares outstanding by 30 percent.
What deserves equal attention is that we achieved these
results while continuing our commitment to safe, reliable and
environmentally sustainable operations. We also gave back
to the communities where we live and work through direct
financial support and volunteerism by our employees.
In an industry facing increasing scrutiny on environmental,
safety, human capital and governance issues, we proactively
work to turn risks into opportunities:
Our combined workforce total recordable rate was 0.14,
matching last year’s record low rate.
Refining’s Tier 1 process safety event rate of 0.02 is
industry-leading.
For the second year in a row, one of our refineries received
the AFPM’s Distinguished Safety Award, the highest
annual safety recognition in the industry.
We invested over $900 million to fund reliability, safety and
environmental projects.
We provided $27 million in financial support to organizations
promoting education, environmental sustainability, and
community safety and preparedness.
Our employees volunteered 78,000 hours of their time to hundreds
of charitable and service organizations during the year.
Below are highlights from our business segments, each of which performed
well in 2018.
Midstream achieved record earnings in 2018, driven by growth projects
completed and placed into service during the past two years. As part of
our strategy, we are developing pipelines to link the key shale basins to
the Gulf Coast, expanding export capability from strategic Gulf Coast
terminals, and building out our integrated NGL value chain. During 2018,
we expanded storage capacity at our Beaumont Terminal to 14.6 million
barrels. The 900,000-BPD Gray Oak Pipeline will transport crude oil from
the Permian and Eagle Ford to the U.S. Gulf Coast upon completion by
the end of this year. At the Sweeny Hub, we are adding 300,000 BPD of
fractionation capability expected to be completed in late 2020.
In our Chemicals business, CPChem’s new U.S. Gulf Coast
petrochemical assets are running well and generating strong free cash
flow. The ethane cracker has consistently operated above design rates,
and its capacity was recently increased to 3.8 billion pounds per year,
15 percent above its original design capacity. CPChem is pursuing
further petrochemical opportunities to meet the growing global
demand for polymers, including a second Gulf Coast project that
would include ethylene and derivative capacity.
2018 PHILLIPS 66 ANNUAL REPORT 2
In Refining, we ran well across our integrated system and captured strong
margins from advantaged crude feedstocks. We completed fluid catalytic
cracking (FCC) unit modernization projects at our Bayway and Wood
River refineries to increase clean product yield. At our Sweeny Refinery,
we started an FCC unit upgrade to increase production of higher-value
petrochemical products and higher-octane gasoline.
Our Marketing business delivered solid margins through efficient off-take
of our refining production. We continue to enhance our U.S. fuels brands
through the re-imaging of sites, bringing the total number since the
program’s inception to approximately 2,600. In Europe, we are growing
and enhancing our retail sites, and added 20 new sites in 2018.
We thank our employees for successfully executing the company’s strategy
to deliver strong 2018 results. Our high-performing organization is defined by
culture, capability and performance. Phillips 66 employees embrace our core
values of safety, honor and commitment, and we hold ourselves accountable
to the highest ethical standards.
We are optimistic about the opportunities across our businesses. We
have the right strategy, portfolio and talent in place to compete and
deliver superior value to shareholders. Through our ongoing commitment
to operating excellence, returns-focused growth and disciplined capital
allocation, we are confident that the best is yet to come for Phillips 66.
Greg C. Garland
Chairman and Chief Executive Officer
| CPChem Polyethylene Railcar Area OLD OCEAN, TX
3
| Wood River Refinery Distilling North Vacuum Tower ROXANA, IL
2018 PHILLIPS 66 ANNUAL REPORT 4
FINANCIAL HIGHLIGHTS
(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
Total Shareholder Return
(%)
2018
$111,461
7,445
5,873
5,595
11.87
11.80
3,019
54,302
11,093
27,153
7,573
3.10
5,550
11.71
340
300
260
220
180
140
100
60
20
-20
May-12 May-13 May-14 May-15 May-16 May-17 May-18 Dec-18
PSX +214
Peers* +118
S&P 100 +103
*Celanese Corporation; Delek US Holdings, Inc.; Eastman Chemical Corporation;
Enterprise Products Partners, LP; HollyFrontier Corporation; Huntsman Corporation;
LyondellBasell Industries N.V.; Marathon Petroleum Corporation; Oneok, Inc.; PBF
Energy Inc.; Targa Resources Corporation; Valero Energy Corporation; and Westlake
Chemical Corporation
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
$84,279
2,191
1,644
1,555
2.94
2.92
2,711
51,653
9,588
23,725
2,963
2.45
1,498
2.82
Adjusted Earnings
($ in millions)
5,550
2,269
1,498
16 17 18
Adjusted Return on
Capital Employed (ROCE)
(%)
16
8
5
16 17 18
5
Our 2018 earnings were $5.6 billion or $11.80 per share.
Adjusted earnings were $5.6 billion or $11.71 per share.
The increase in adjusted earnings
in 2018, compared with 2017, was
primarily due to higher Refining
margins associated with strong
market capture from advantaged
crude feedstocks. Midstream and
Chemicals earnings benefited from
growth projects. Our results were
also favorably impacted by lower
income taxes from U.S. tax reform.
During 2018, we generated $7.6
billion of cash from operations,
compared with $3.6 billion in 2017.
We funded $2.6 billion of capital
expenditures, paid $1.4 billion of
dividends and repurchased $4.6
billion of shares. Our ending cash
balance was $3.0 billion.
Total debt at year-end was $11.2
billion, resulting in a debt-to-
capital ratio of 29 percent.
Phillips 66 has a strong balance
sheet and investment grade
credit rating.
Our disciplined capital allocation
enables us to grow our businesses
while also delivering strong
shareholder distributions. Long
term, we expect to re-invest 60
percent of our operating cash
flow back into our business
and distribute 40 percent to our
shareholders. For 2019, we are
funding a $2.9 billion adjusted
capital budget, which includes
$1.9 billion of growth capital and
$1.0 billion of sustaining capital.
Approximately $1.4 billion of the
growth capital is for Midstream
projects, with $0.5 billion for high-
return Refining and Marketing
projects. Our major joint ventures
have self-funded capital programs,
and our proportional share of their
capital expenditures is $1.2 billion.
2019 Consolidated Adjusted Capital Budget
$2.9 billion
$1.9 billion growth capital
- Pipeline and terminal investments
- Fractionation and processing capability
- Export capacity
- Yield and feedstock enhancements
$1.0 billion sustaining capital
- Maintaining safe, reliable assets
Sustaining
Phillips 66 Midstream Growth
Phillips 66 Partners Growth
Returns
Capital Structure
($B)
27.4
27.2
23.7
PSX equity
30%
26%
27%
22%
10.1
10.1
29%
25%
11.2
16 17 18
PSX noncontrolling interest
attributable to PSXP
PSX debt
PSXP third-party debt
PSX debt-to-capital
excluding PSXP
Consolidated debt-to-capital
Consolidated
Capital Expenditures
and Investments
($B)
2.8
2.6
1.8
PSX
PSXP
16 17 18
2018 PHILLIPS 66 ANNUAL REPORT 6
OUR BUSINESSES
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, Texas, Phillips 66 has 14,200 employees committed to safety and operating excellence.
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,
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.
16
North American facilities
5
Middle East 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.
2.2
million barrels per day (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.
7,520
branded U.S. outlets
1,630
branded international outlets
7
OUR VALUE CHAIN
We have an integrated network of businesses and assets across the midstream and downstream value chain. Our
diverse portfolio is well-positioned to benefit from continued oil and gas production growth in the United States.
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
Phillips 66
Phillips 66 Partners
CPChem
DCP Midstream
| Billings Refinery Water Treatment Facility BILLINGS, MT
2018 PHILLIPS 66 ANNUAL REPORT 8
OUR STRATEGY
The Phillips 66 strategic priorities of growth, returns and distributions are supported by a strong
foundation of operating excellence and our high-performing organization. We believe our strategy
creates long-term shareholder value. We made progress executing our key strategic priorities during
2018, achieving numerous milestones and successes.
GROWTH
RETURNS
DISTRIBUTIONS
Enhancing our portfolio by
capturing growth opportunities
in Midstream and Chemicals
Improving returns by
maximizing earnings from
existing assets and investing
capital efficiently
Committed to financial
strength, disciplined capital
allocation, dividend growth
and share repurchases
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
2018 PHILLIPS 66 ANNUAL REPORT
9
| CPChem Polyethylene Units OLD OCEAN, TX
10
OPERATING EXCELLENCE
Operating excellence, with
a focus on safe, reliable and
environmentally responsible
operations, is key to our long-
term strategy and provides us
with a competitive advantage.
Our continually improving health,
safety and environmental record
is a testament to our employees’
commitment. In 2018, we
delivered industry-leading safety
and environmental results. We do
this not only because it’s the right
thing to do for all stakeholders, but
also because we believe we create
long-term shareholder value by
getting this right.
Our 2018 combined workforce
recordable injury rate of 0.14
matched last year’s record low
rate and is approximately 25
times better on average than the
rest of U.S. manufacturing. Our
Refining Tier 1 process safety
event rate of 0.02 is industry-
leading and is down 75 percent
over the last five years.
In our Refining business, we
achieved 95 percent capacity
utilization and successfully executed
a heavy turnaround schedule.
In Midstream, through ongoing
optimization efforts, we had
strong operating performance at
the Sweeny Hub. The Sweeny
fractionator operated in excess
of 100 percent utilization, and
the Freeport LPG Export Terminal
demonstrated capacity of
200,000 BPD.
CPChem's global Olefins
and Polyolefins (O&P)
capacity utilization rate
was 94 percent.
CPChem demonstrated strong
execution with the startup of its
new ethane cracker at Cedar
Bayou. The cracker reached full
operations more quickly than
premised and is operating well
above its original design rates.
1.0
.75
.5
.25
0
Total Recordable Rates
(Incidents per 200,000 hours worked)
.15
.14
.14
.30
.14
.10
.66
.46
.23
16 17 18
Phillips 66
16 17 18
CPChem
16 17 18
DCP
Industry average
Refining Crude Capacity Utilization
(%)
96
95
95
16 17 18
11
S A F E T Y R E C O G N I T I O N
The American Fuel and Petrochemical Manufacturers recognized
four Phillips 66 refineries for exemplary safety performance in 2018.
Our Bayway Refinery received the Distinguished Safety Award,
the industry's highest level of safety recognition, for its leading
performance in process and personal safety. The Sweeny Refinery
was recognized with the Elite Gold Award, which is the second-
highest honor. The Alliance and Wood River refineries each received
the Elite Silver Award, which recognizes the top 5 percent of all
sites in the industry for attaining the highest safety performance.
Forty-five percent of our U.S. refineries have earned the
Environmental Protection Agency ENERGY STAR® Award, which
recognizes top-quartile energy efficiency performance.
Phillips 66 has 27 Refining, Midstream and Lubricants sites
that have received OSHA Voluntary Protection Program
(VPP) certification. VPP recognizes strong safety records and
comprehensive safety and health management systems.
| CPChem Polyethylene Units OLD OCEAN, TX
2018 PHILLIPS 66 ANNUAL REPORT 12
GROWTH
As part of our long-term strategy,
we are investing capital to
capture growth opportunities in
the Midstream and Chemicals
businesses. In Midstream, the
expected growth of crude oil
and NGL production in the
United States provides us with
opportunities to expand our
integrated infrastructure. Our
Midstream growth strategy focuses
on three areas: pipelines from
key shale basins to the U.S. Gulf
Coast; terminals on the Gulf Coast
providing export capability; and the
NGL value chain, including storage,
transportation, fractionation and
export capability. The integration
of our Midstream assets with our
Refining, Marketing and Chemicals
businesses provides us with a
distinct advantage to develop
strong projects.
Our Sweeny Hub is an integrated
NGL fractionation, storage and
export complex strategically
located on the U.S. Gulf Coast
with access to petrochemicals,
fuels and LPG export markets.
We are expanding the hub to add
two 150,000-BPD fractionators,
associated pipeline infrastructure,
and 6 million barrels of storage
capacity at Phillips 66 Partners’
Clemens Caverns. DCP Midstream
committed to supply Y-grade
NGL feedstock and has an
option to acquire up to a 30
percent ownership interest in the
fractionators. Upon completion of
the expansion, expected in late
2020, our Sweeny Hub will have
400,000 BPD of fractionation
capability. Additionally, the hub
will have access to 15 million
barrels of storage capacity, along
with 200,000 BPD of LPG export
capability at our Freeport LPG
Export Terminal.
Phillips 66 Partners
is constructing the
Gray Oak Pipeline,
which will transport
crude oil from the
Permian and Eagle
Ford to destinations
in Corpus Christi and
Freeport, including
our Sweeny Refinery.
The 900,000-BPD
pipeline is backed
by long-term, third-
party, take-or-pay
commitments. Phillips
66 Partners owns a
42.25 percent interest
in the pipeline, which
is anticipated to be
in service by the end
of 2019.
In Corpus Christi, the Gray Oak
Pipeline will connect to the new
South Texas Gateway Terminal
under development by Buckeye
Partners, L.P. The marine terminal
will have planned storage capacity
of approximately 7 million barrels
with two docks capable of
berthing very large crude carrier
tankers. It is expected to begin
operations in mid-2020. Phillips
66 Partners owns a 25 percent
interest in the terminal.
Our Beaumont Terminal is
strategically located on the U.S.
Gulf Coast with connections
to 11 crude oil pipelines and
access to six refineries. During
2018, we commissioned 3.5
million barrels of additional crude
storage, bringing the terminal’s
total crude and products storage
capacity to 14.6 million barrels.
A further expansion of 2.2 million
barrels of crude oil storage is
planned for completion in the first
quarter of 2020. The terminal has
an export name-plate capacity of
600,000 BPD.
The Sand Hills Pipeline transports
NGL from the Permian and Eagle
Ford to the U.S. Gulf Coast,
including Phillips 66 Partners’
Sweeny Fractionator and the
Mont Belvieu market hub. The
pipeline is two-thirds owned by
DCP Midstream and one-third by
Phillips 66 Partners. The Sand Hills
Pipeline capacity was expanded to
485,000 BPD in 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 St.
James, Louisiana, is expected to
be completed in the first quarter of
2019. The Bayou Bridge Pipeline
has a capacity of 480,000 BPD
and facilitates the delivery of
advantaged crude oil to our Lake
Charles Refinery.
Phillips 66 and Phillips 66 Partners
are expanding the logistics
systems from the company’s
Sweeny Hub to Phillips 66
Partners’ Pasadena Terminal.
Phillips 66 Partners’ Sweeny
to Pasadena Pipeline will be
expanded by 80,000 BPD, and
300,000 barrels of storage will be
added at the Pasadena Terminal.
The project is expected to be
completed in the second quarter
of 2020.
13
| Gray Oak Pipeline Construction Pipe Yard BIG LAKE, TX
PHILLIPS 66 PARTNERS
Phillips 66 Partners is an integral part of our Midstream strategy.
It has a competitive cost of capital and maintains stable and
predictable cash flows. Phillips 66 Partners grew rapidly during its
first five years since IPO, delivering industry-leading distribution
growth. With its scale, financial strength and robust portfolio of
growth projects, Phillips 66 Partners is well-positioned to fund and
sustain a larger organic program. Phillips 66 Partners is funding a
$0.6 billion capital program in 2019.
Phillips 66 Partners achieved a 30 percent five-year distribution
compound annual growth rate through 2018 and delivered $1.1
billion of adjusted EBITDA in 2018.
| Beaumont Terminal Methanol Storage Tanks NEDERLAND, TX
2018 PHILLIPS 66 ANNUAL REPORT 14
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MONT BELVIEU
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LAKE CHARLES
ISOMERIZATION UNIT
Lake Charles
SORRENTO
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GL Syste
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S a n d H i
CLEMENS CAVERNS
FREEPORT LPG EXPORT TERMINAL
MEREY SWEENY
SWEENY
FRACTIONATORS
SOUTH TEXAS GATEWAY
| Sweeny Fractionators II and III Construction OLD OCEAN, TX
Line EZ
PASADENA
Sweeny
B a y o u B r i d g e
BEAUMONT
Explorer
MONT BELVIEU
Bayou Bridge
LAKE CHARLES
ISOMERIZATION UNIT
Lake Charles
l s
l
S a n d H i
CLEMENS CAVERNS
FREEPORT LPG EXPORT TERMINAL
MEREY SWEENY
SWEENY
FRACTIONATORS
SOUTH TEXAS GATEWAY
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15
Terminal (PSX)
Terminal (PSXP)
Terminal under construction (PSXP)
Underground storage facility (PSX)
Underground storage facility (PSXP)
Fractionator (PSX)
Fractionator under construction (PSX)
Fractionator (PSXP)
Processing unit (PSXP)
Processing unit under construction (PSXP)
CPChem ethylene and/or polyethylene facility
CPChem USGC Petrochemical Project
Pipeline (PSX)
Pipeline (CPChem owned; PSX operated)
Pipeline (PSXP)
Pipeline under contruction (PSXP)
Third-party terminal
Phillips 66 refinery
The Bakken Pipeline, in which Phillips 66 Partners owns a 25 percent interest,
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. The pipeline has a capacity of 525,000 BPD, and the operator is expanding
the capacity to 570,000 BPD in 2019.
In Chemicals, there is growing
global demand for high-quality
polymers. Furthermore, the
abundant supply of ethane in the
United States is expected to remain
the cost-advantaged feedstock for
petrochemicals growth. CPChem
has a leading position in olefins
and polyolefins production and a
portfolio of cost-advantaged assets
strategically located in the United
States and Middle East.
CPChem completed its world-
scale U.S. Gulf Coast (USGC)
Petrochemicals Project, which
increased its global ethylene
and polyethylene capacity by 31
percent. The new ethane cracker in
Cedar Bayou, Texas, commenced
operations in the first quarter of
2018, and the two polyethylene
units in Old Ocean, Texas, started
up in the third quarter of 2017. The
cracker’s capacity was recently
expanded to 3.8 billion pounds per
year, which is 15 percent above
original design.
CPChem continues to optimize
its new USGC petrochemical
assets and is developing a second
USGC project that would include
integrated ethylene and derivative
capacity. CPChem is also evaluating
additional capacity across multiple
product lines through debottleneck
opportunities on existing units.
| Bakken Pipeline MOUNTRAIL COUNTY, ND
2018 PHILLIPS 66 ANNUAL REPORT
16
RETURNS
In Refining, our focus is on
maintaining safe and reliable
operations, while being good
environmental stewards.
We practice cost and capital
discipline. Our capital allocation
strategy in Refining is to fund
sustaining capital to maintain
the integrity of our assets. We
also selectively invest in high-
return projects to improve our
yield of higher-valued products
and enhance our advantaged
feedstock capability.
Our complex, integrated refining
system is well-positioned to
capture robust margins and
generate strong free cash flow.
Phillips 66 has industry-leading
global coking capacity to process
cost-advantaged heavy crudes
while yielding low production
of high-sulfur fuel oil. With our
commercial supply network and
integration with our Midstream
assets, we have the capability
to maximize cost-advantaged
crude feedstocks throughout our
refining system.
We are the industry’s largest
purchaser of heavy Canadian crude
oil, which we ran at nine of our
refineries in 2018. Phillips 66 refineries
also process a large proportion
of advantaged tight oil, which we
purchase directly from producers in
the key shale basins. Refining has
a clean product yield of 84 percent,
including an industry-leading
distillate yield of 38 percent.
During 2018, we completed projects
to modernize the FCC units at
both the Bayway and Wood River
refineries. The units are performing
as expected and yielding higher-
value clean products.
At our Lake Charles
Refinery, we
completed crude
unit modifications
to run more cost-
advantaged domestic
crudes. Phillips 66
Partners is also
constructing a 25,000-
BPD isomerization
unit at the refinery to
increase production of
higher-octane gasoline
blend components; it
is anticipated to be
completed in the third
quarter of 2019.
An FCC unit upgrade project is
underway at our Sweeny Refinery
to increase production of higher-
value petrochemical products and
higher-octane gasoline. The project
is anticipated to be completed in
the second quarter of 2020.
17
| Lake Charles Refinery Fuels Coker and Premium Coker Derricks, Excel Paralubes Joint Venture Vacuum Tower
LAKE CHARLES, LA
2018 PHILLIPS 66 ANNUAL REPORT 18
Our Marketing business generates strong, stable cash flow with a low capital
intensity. Our independently owned U.S. Marketing branded sites are aligned with
our refining and logistics assets and provide ratable pull-through for our inland and
West Coast refineries.
In the United States, we continue
to update our Phillips 66, 76
and Conoco branded marketing
sites with new signature image
designs. During 2018, we re-
imaged over 1,300 sites, bringing
the total number of re-imaged
sites to approximately 2,600 since
the inception of our program in
2015. Our re-imaged sites are
delivering solid increases in fuel
sales volumes.
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 2018, we
completed construction of eight
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.
In addition, we produce private
label lubricants for many original
equipment manufacturers. Our
strategy is to grow volumes
through the marketer business,
focusing on stronger brands,
premium products, and
commercial and industrial
segments. We are the third-
largest lubricants manufacturer
in the United States and receive
industry high rankings for
supplier satisfaction.
During the first quarter of 2018, we
completed a restructuring of our
Excel Paralubes joint venture. Both
partners contributed their base
oil businesses to the venture to
create an integrated manufacturing
and marketing business. The
restructuring enables Excel
Paralubes to provide quality base
oil solutions to customers with
greater agility.
Our Specialties business markets
high-quality graphite and anode-
grade petroleum cokes in the
United States, Europe and Asia
for use in a variety of industries,
including steel, aluminum, titanium
oxide and battery manufacturing.
5,000+ sites have
implemented mobile pay
| 76 Branded Marketing Site WEIMAR, TX
19
Phillips 66 and Phillips 66 Partners pipelines
Phillips 66 and Phillips 66 Partners facilities
Phillips 66 refinery
Phillips 66 joint venture refinery
EUROPE
During 2018, we completed
construction of
8
new JET branded sites and
12
new COOP sites
| Phillips 66 Branded Marketing Site
CAMDEN COUNTY, MO
| Conoco Branded Marketing Site
SUNRISE BEACH, MO
| JET Branded Marketing Site
HAMBURG, GERMANY
2018 PHILLIPS 66 ANNUAL REPORT 20
DISTRIBUTIONS
Returning capital to shareholders through a secure, competitive and growing
dividend, along with our share repurchase program, is fundamental to our
long-term strategy. During 2018, we distributed $6.1 billion to shareholders
through dividends and share buybacks. Share repurchases during the year
were $4.6 billion and represented 10 percent of our shares outstanding. From
our formation through the end of 2018, we repurchased or exchanged 190
million shares, representing 30 percent of our original shares outstanding.
We distributed $1.4 billion in dividends during 2018. In
May 2018, Phillips 66 increased the quarterly dividend
14 percent to $0.80 per share. This is our eighth increase
since formation, representing a 27 percent compound
annual growth rate.
Share Count and Distributions
626 million
Total shareholder
distributions
$22.5 billion
3Q 2012 4Q 2013 4Q 2014 4Q 2015 4Q 2016 4Q 2017 4Q 2018
Number of shares outstanding
Cumulative shareholder distributions*
* Through share purchases, share exchanges and dividends
456 million
Dividend Growth
(Quarterly ¢/share)
27% CAGR
80¢
20¢
3Q 2012 4Q 2013 4Q 2014 4Q 2015 4Q 2016 4Q 2017 4Q 2018
21
| Bayway Refinery LINDEN, NJ
2018 PHILLIPS 66 ANNUAL REPORT 22
HIGH-PERFORMING ORGANIZATION
Our high-performing organization
is defined by culture, capability
and performance. The employees
of Phillips 66 fully embrace our
corporate values of safety, honor
and commitment, which guide
how we make decisions, conduct
business and engage with
stakeholders. These core values
form the basis of our relationships
with colleagues, customers,
partners and communities. We
hold ourselves accountable to the
highest ethical standards.
We value diversity and are
committed to an inclusive work
environment. Diversity in thought
and ideas brings value to our
company. It is embraced by our
management team and reinforced
throughout the organization — not
only in our people processes, but
also in how we interact and work
with each other every day.
At Phillips 66, we
invest in our people
through training and
development programs.
We believe this investment provides
our company with a competitive
advantage through our employees.
Central to the Phillips 66 vision of
Providing Energy, Improving Lives
is giving back to the communities
where we live and work.
Our employees participated
in many volunteer activities in
2018, including:
Teaching STEM and literacy
summer camps
Building homes with Habitat
for Humanity
Planting trees at local schools
Assembling equipment for
local fire departments
Reading with children at
elementary schools
Preparing meals at community
food banks
Removing invasive species
from local parks
Hosting waste disposal and
recycling days
78,000 hours
volunteered by employees
during 2018
| Garfield Elementary partners in education program. PONCA CITY, OK
23
| Make a Splash Tour presented by Phillips 66 has provided 7 million low- or no-cost swim lessons over the last decade.
ORLANDO, FL
$27 million in financial
support to organizations
promoting education and
literacy, safety and preparedness,
environmental sustainability and
civic enrichment
scholarships, bringing the total
62 new dependent
number of recipients to 227
853 organizations
received volunteer grants
2,030 organizations
received monetary matching gifts
2018 PHILLIPS 66 ANNUAL REPORT 2018 PHILLIPS 66 ANNUAL REPORT
SHAREHOLDER INFORMATION
ANNUAL MEETING
Phillips 66’s annual meeting of
shareholders will be held:
Wednesday, May 8, 2019
9 a.m. Central Daylight Time
Houston Marriott Westchase
2900 Briarpark Drive
Houston, TX 77042
Notice of the meeting and proxy
materials will be provided to
all shareholders.
DIRECT STOCK PURCHASE
AND DIVIDEND
REINVESTMENT PLAN
Phillips 66’s Investor Services
Program is a direct stock purchase
and dividend reinvestment plan that
offers shareholders a convenient
way to buy additional shares
and reinvest their common stock
dividends. Purchases of company
stock through direct cash payment
are commission-free.
Please call Computershare to
request an enrollment package:
Toll-free number: 866-437-0009
Or enroll online at
www.computershare.com/investor
Registered shareholders can
access important investor
communications online and sign
up to receive future shareholder
materials electronically by going to
www.computershare.com/investor
and following the enrollment
instructions.
PRINCIPAL AND
REGISTERED OFFICES
Phillips 66
P.O. Box 421959
Houston, TX 77242-1959
251 Little Falls Drive
Wilmington, DE 19808
STOCK TRANSFER AGENT
AND REGISTRAR
Computershare
462 South 4th Street, Suite 1600
Louisville, KY 40202
www.computershare.com/investor
INFORMATION REQUESTS
For information about dividends and
certificates or to request a change of
address form, shareholders may contact:
Computershare
P.O. BOX 505000
Louisville, KY 40233
Toll-free number: 866-437-0009
Outside the U.S.: 201-680-6578
TDD for hearing impaired:
800-231-5469
TDD outside the U.S.: 201-680-6610
www.computershare.com/investor
Personnel in the following offices
also can answer investors’ questions
about the company:
INSTITUTIONAL INVESTORS
800-624-6440
investorrelations@p66.com
INDIVIDUAL INVESTORS
866-437-0009
web.queries@computershare.com
COMPLIANCE AND ETHICS
For guidance, to express concerns
or to ask questions about compliance
and ethics issues, contact the
Phillips 66 Global Ethics Office:
Toll-free number available 24/7:
855-318-5390
Email: ethics@p66.com
Website:
www.phillips66.ethicspoint.com
Address: Attn: Global Ethics Office
Phillips 66
2331 CityWest Blvd.
Houston, TX 77042
COPIES OF FORM 10-K
AND PROXY STATEMENT
Copies of the Annual Report on
Form 10-K and the Proxy Statement,
as filed with the U.S. Securities and
Exchange Commission, are available
free by making a request on the
company’s website, calling
918-977-2245 or writing:
Phillips 66
2018 Form 10-K
411 S. Keeler
Bartlesville, OK 74003
Additional copies of this Annual
Report may be obtained by calling
918-977-2245 or writing:
Phillips 66
2018 Annual Report
411 S. Keeler
Bartlesville, OK 74003
INTERNET
www.phillips66.com
The website includes resources
of interest to investors, including
news releases and presentations
to securities analysts; copies of
Phillips 66’s Annual Report and
Proxy Statement; reports to the U.S.
Securities and Exchange Commission;
and data on Phillips 66’s health, safety
and environmental performance.
Other websites with information on
topics included in this Annual Report:
www.cpchem.com
www.dcpmidstream.com
www.phillips66partners.com
Phillips 66®, Conoco®, 76®, Kendall®, Red Line®, JET® and their respective logos are registered trademarks of Phillips 66 Company or
a wholly owned subsidiary. Other names and logos mentioned herein are the trademarks of their respective owners.
DISCLOSURE STATEMENTS
Certain disclosures in this Annual Report may be considered “forward-looking” statements. These are made pursuant to “safe
harbor” provisions of the Private Securities Litigation Reform Act of 1995. The “Cautionary Statement” in Management’s Discussion
and Analysis should be read in conjunction with such statements. “Phillips 66,” “the company,” “we,” “us” and “our” are used
interchangeably in this report to refer to the businesses of Phillips 66 and its consolidated subsidiaries.
PHOTOGRAPHY
Andrew Camacho, Ken Childress, Garth Hannum, Mike Lewis and Energy Transfer Partners.
19-0012_001 ©2019 Phillips 66 Company. All rights reserved.
PHILLIPS66.COM
2018
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, 2018
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 every Interactive Data File required to be submitted
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 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.
[ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller
reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,”
“smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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 29, 2018, the last business day of the registrant’s most
recently completed second fiscal quarter, based on the closing price on that date of $112.31, was $52.1 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 454,913,087 shares of common stock outstanding at January 31, 2019.
Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 8, 2019 (Part III).
This Page Intentionally Left Blank
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
PART IV
15. Exhibits, Financial Statement Schedules
16. Form 10-K Summary
Signatures
Page
1
1
2
2
10
12
16
17
17
18
19
26
27
27
28
29
31
32
68
70
71
139
139
139
140
140
140
140
140
141
141
146
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.
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 petroleum product transportation, terminaling and processing
services, as well as natural gas and natural gas liquids (NGL) 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 (M&S)—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, cash equivalents and income tax-related assets.
At December 31, 2018, Phillips 66 had approximately 14,200 employees.
1
SEGMENT AND GEOGRAPHIC INFORMATION
MIDSTREAM
The Midstream segment consists of three business lines:
• Transportation—Transports crude oil and other feedstocks to our refineries and other locations, delivers refined
petroleum products to market, and provides terminaling and storage services for crude oil and refined petroleum
products.
• NGL and Other—Transports, stores, fractionates, exports and markets NGL and provides other fee-based
processing services.
• DCP Midstream—Gathers, processes, transports and markets natural gas and transports, fractionates and markets
NGL.
Phillips 66 Partners
Phillips 66 Partners, headquartered in Houston, Texas, is an MLP we formed in 2013 to own, operate, develop and
acquire primarily fee-based midstream assets. At December 31, 2018, we owned a 54 percent limited partner interest and
a 2 percent general partner interest in Phillips 66 Partners, while the public owned a 44 percent limited partner interest
and 13.8 million perpetual convertible preferred units.
Phillips 66 Partners’ operations currently consist of crude oil, refined petroleum product and NGL transportation,
processing, terminaling and storage assets that are geographically dispersed throughout the United States. The majority
of Phillips 66 Partners’ assets are integral to Phillips 66-operated refineries.
The results of operations 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 transportation, terminaling and storage services. These assets include crude
oil, refined petroleum product, NGL, and natural gas pipeline systems; crude oil, refined petroleum product and NGL
terminals; a petroleum coke handling facility; marine vessels; railcars and trucks.
Pipelines and Terminals
At December 31, 2018, our Transportation business was comprised of over 21,000 miles of crude oil, refined petroleum
product, NGL and natural gas pipeline systems in the United States, including those partially owned or operated by our
affiliates. We owned or operated 39 refined petroleum product terminals, 20 crude oil terminals, 4 NGL terminals, a
petroleum coke exporting facility and various other storage and loading locations.
The Beaumont Terminal in Nederland, Texas, is the largest terminal in the Phillips 66 portfolio. During 2018, we
continued to invest in the terminal by adding 3.5 million barrels of crude oil storage capacity. At December 31, 2018, the
terminal storage capacity was 14.6 million barrels, which included 10.9 million barrels of storage capacity for crude oil
and 3.7 million barrels of storage capacity for refined petroleum products. A further expansion of 2.2 million barrels of
crude oil capacity is planned for completion in the first quarter of 2020.
The Bayou Bridge Pipeline joint venture delivers crude oil from Nederland, Texas, to Lake Charles, Louisiana. Phillips
66 Partners has a 40 percent interest in the joint venture, and our co-venturer serves as the operator. An extension of the
pipeline from Lake Charles to St. James, Louisiana, is expected to be in service in March 2019. The pipeline has a
capacity of approximately 480,000 barrels per day (BPD).
2
The Gray Oak Pipeline system will provide crude oil transportation from the Permian Basin and Eagle Ford to
destinations in the Corpus Christi and Freeport markets on the Texas Gulf Coast, including the Sweeny Refinery. The
planned capacity of the pipeline is 900,000 BPD. At December 31, 2018, Phillips 66 Partners had an effective ownership
interest in the pipeline system of 48.75 percent. In February 2019, another party exercised its option to acquire an
interest in the pipeline system that reduced Phillips 66 Partners’ effective ownership interest to 42.25 percent. The
pipeline system is expected to be in service by the end of 2019.
Phillips 66 Partners owns a 25 percent interest in the South Texas Gateway Terminal, which will connect to the Gray Oak
Pipeline in Corpus Christi, Texas. The marine terminal, under development by a co-venturer, will have two deepwater
docks and an initial storage capacity of 6.5 to 7 million barrels. The terminal is expected to start-up by mid-2020.
An open season commenced for the Red Oak Pipeline system on November 12, 2018. As proposed, this pipeline system
would provide shippers the opportunity to transport crude oil from Cushing, Oklahoma, to Corpus Christi, Houston, and
Beaumont, Texas. The initial throughput capacity on the pipeline is expected to be 400,000 BPD, with potential for
further expansion. The pipeline system is anticipated to be placed in service in the fourth quarter of 2020.
An open season also commenced on the Liberty Pipeline system on November 12, 2018. As proposed, this pipeline
system would provide shippers the opportunity to transport crude oil from the Rockies and Bakken production areas to
Corpus Christi, Texas. The initial throughput capacity on the pipeline is expected to be 350,000 BPD, with potential for
further expansion. The pipeline system is anticipated to be placed in service in the fourth quarter of 2020.
3
The following table depicts our ownership interest in major pipeline systems at December 31, 2018:
Name
Crude Oil
Bakken Pipeline †
Bayou Bridge †
Clifton Ridge †
CushPo †
Eagle Ford Gathering †
Glacier †
Line 100
Line 200
Line 300
Line 400
Line O †
Louisiana Crude Gathering
New Mexico Crude †
North Texas Crude †
Oklahoma Crude †
Sacagawea †
STACK PL †
Sweeny Crude
West Texas Crude †
Refined 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
Yellowstone
State of
Origination/Terminus
Interest
Length
(Miles)
Gross Capacity
(MBD)
25%
40
100
100
100
79
100
100
100
100
100
100
100
100
100
50
50
100
100
50
100
70
100
100
100
100
22
100
33
50
50
100
100
50
100
33
54
100
100
100
100
100
46
1,915
49
10
62
28
865
79
228
61
153
276
80
227
224
217
95
149
56
1,064
293
93
397
287
29
98
5
1,830
686
80
49
19
22
106
562
14
102
19
342
92
120
8
9
710
525
480
260
130
54
126
54
93
48
40
37
25
106
28
100
175
250
265
156
34
76
38
55
57
46
180
660
120
171
30
50
112
96
63
26
33
30
33
72
294
161
238
66
North Dakota/Texas
Texas/Louisiana
Louisiana
Oklahoma
Texas
Montana
California
California
California
California
Oklahoma/Texas
Louisiana
New Mexico/Texas
Texas
Texas/Oklahoma
North Dakota
Oklahoma
Texas
Texas
Texas/New Mexico
Texas
Texas/Colorado
Oklahoma/Missouri
Oklahoma/Kansas
Oklahoma
Texas
Texas/Indiana
Texas/Illinois
New Jersey
Kansas/Iowa
California
California
Kansas
Wyoming/Utah
California
Texas
Texas
Montana/Wyoming
Oklahoma/Kansas
Texas
California
California
Montana/Washington
4
Name
State of
Origination/Terminus
Interest
Length
(Miles)
Gross Capacity
(MBD)
NGL
Blue Line
Brown Line †
Chisholm
Conway to Wichita
Medford †
Powder River
River Parish NGL†
Sand Hills †
Skelly-Belvieu
Southern Hills †
Sweeny LPG
Sweeny NGL
TX Panhandle Y1/Y2
Natural Gas
Rockies Express**
East to West
West to East
Texas/Illinois
Oklahoma/Kansas
Oklahoma/Kansas
Kansas
Oklahoma
Wyoming/Texas
Louisiana
Texas
Texas
Kansas/Texas
Texas
Texas
Texas
Ohio/Illinois
Colorado/Ohio
100%
100
50
100
100
100
100
33
50
33
100
100
100
25
25
688
76
202
55
42
705
510
1,466
571
941
232
18
289
670
1,712
29
26
42
38
10
14
133
485
45
192
942
204
61
2.6 Bcf/d
1.8 Bcf/d
† Owned by Phillips 66 Partners; Phillips 66 held a 56 percent ownership interest in Phillips 66 Partners at December 31, 2018.
* Total pipeline system is 419 miles. Phillips 66 has an ownership interest in multiple segments totaling 49 miles.
** 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.
5
The following table depicts our ownership interest in terminal and storage facilities at December 31, 2018:
Facility Name
Albuquerque †
Amarillo †
Beaumont
Billings
Billings Crude †
Borger
Bozeman
Buffalo Crude †
Casper †
Clemens †
Clifton Ridge †
Coalinga
Colton
Cushing †
Cut Bank †
Denver
Des Moines
East St. Louis †
Freeport
Glenpool †
Great Falls
Hartford †
Helena
Jefferson City †
Jones Creek
Junction
Kansas City †
Keene †
La Junta
LCPL Storage
Lincoln
Linden †
Los Angeles
Lubbock †
Medford Spheres †
Missoula
Moses Lake
Mount Vernon †
North Salt Lake
North Spokane
Odessa †
Oklahoma City †
Location
New Mexico
Texas
Texas
Montana
Montana
Texas
Montana
Montana
Wyoming
Texas
Louisiana
California
California
Oklahoma
Montana
Colorado
Iowa
Illinois
Texas
Oklahoma
Montana
Illinois
Montana
Missouri
Texas
California
Kansas
North Dakota
Colorado
Louisiana
Nebraska
New Jersey
California
Texas
Oklahoma
Montana
Washington
Missouri
Utah
Washington
Texas
Oklahoma
Commodity Handled
Refined Petroleum Products
Refined Petroleum Products
Crude Oil, Refined
Petroleum Products
Refined Petroleum Products
Crude Oil
Crude Oil
Refined Petroleum Products
Crude Oil
Refined Petroleum Products
NGL
Crude Oil
Crude Oil
Refined Petroleum Products
Crude Oil
Crude Oil
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
Crude Oil, Refined
Petroleum Products, NGL
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
Crude Oil
Crude Oil
Refined Petroleum Products
Crude Oil
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
NGL
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
Crude Oil
Crude Oil, Refined
Petroleum Products
Interest
100%
100
100
Gross Storage
Capacity (MBbl)
274
296
14,600
Gross Rack
Capacity (MBD)
18
29
8
100
100
50
100
100
100
100
100
100
100
100
100
100
50
100
100
100
100
100
100
100
100
100
100
50
100
50
100
100
100
100
100
50
50
100
50
100
100
100
88
236
772
130
303
365
9,000
3,800
817
207
675
315
310
217
2,031
3,624
571
198
1,468
195
103
2,580
524
1,410
503
109
3,143
217
360
156
182
70
365
216
365
755
492
521
355
16
N/A
N/A
13
N/A
7
N/A
N/A
N/A
21
N/A
N/A
43
15
78
N/A
19
12
25
10
16
N/A
N/A
66
N/A
10
N/A
21
121
75
17
N/A
29
13
46
41
N/A
N/A
48
6
Facility Name
Palermo †
Paola †
Pasadena †
Pecan Grove †
Ponca City †
Ponca City Crude †
Portland
Renton
Richmond
River Parish †
Rock Springs
Sacramento
San Bernard
Santa Margarita
Sheridan †
Spokane
Tacoma
Torrance
Location
North Dakota
Kansas
Texas
Louisiana
Oklahoma
Oklahoma
Oregon
Washington
California
Louisiana
Wyoming
California
Texas
California
Wyoming
Washington
Washington
California
Commodity Handled
Crude Oil
Refined Petroleum Products
Refined Petroleum Products
Crude Oil
Refined Petroleum Products
Crude Oil
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
NGL
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
Crude Oil
Refined Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
Crude Oil, Refined
Petroleum Products
Refined Petroleum Products
Refined Petroleum Products
Crude Oil
Refined Petroleum Products
Refined Petroleum Products
Interest
70%
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
Gross Storage
Capacity (MBbl)
235
978
3,234
177
51
1,229
650
243
343
1,500
132
146
231
398
94
351
316
2,128
Gross Rack
Capacity (MBD)
N/A
N/A
65
N/A
23
N/A
33
20
28
N/A
19
13
N/A
N/A
15
24
17
N/A
Tremley Point †
Westlake
Wichita Falls †
Wichita North †
Wichita South †
† Owned by Phillips 66 Partners; Phillips 66 held a 56 percent ownership interest in Phillips 66 Partners at December 31, 2018.
New Jersey
Louisiana
Texas
Kansas
Kansas
100
100
100
100
100
1,701
128
225
769
272
25
16
N/A
19
N/A
The following table depicts our ownership interest in marine, rail and petroleum coke loading and offloading facilities at
December 31, 2018:
Facility Name
Location
Commodity Handled
Interest
Gross Loading
Capacity*
Texas
Louisiana
Texas
Illinois
Louisiana
Oregon
California
Texas
Washington
New Jersey
Crude Oil, Refined Petroleum Products
Crude Oil
Crude Oil, Refined Petroleum Products, NGL
Refined Petroleum Products
Crude Oil
Crude Oil
Crude Oil
Refined Petroleum Products
Crude Oil
Refined Petroleum Products
Marine
Beaumont
Clifton Ridge †
Freeport
Hartford †
Pecan Grove †
Portland
Richmond
San Bernard
Tacoma
Tremley Point †
Rail
Bayway †
Beaumont
Ferndale †
Missoula
Palermo †
Thompson Falls
Petroleum Coke
Lake Charles
† Owned by Phillips 66 Partners; Phillips 66 held a 56 percent ownership interest in Phillips 66 Partners at December 31, 2018.
* Marine facilities in thousands of barrels per hour; Rail in thousands of barrels daily (MBD).
Crude Oil
Crude Oil
Crude Oil
Refined Petroleum Products
Crude Oil
Refined Petroleum Products
New Jersey
Texas
Washington
Montana
North Dakota
Montana
Petroleum Coke
Louisiana
100
100
100
50
70
50
50
100%
100
100
100
100
100
100
100
100
100
60
48
46
3
6
10
3
2
12
7
75
20
30
41
100
41
N/A
7
Marine Vessels
At December 31, 2018, we had 13 international-flagged crude oil, refined petroleum product and NGL tankers and two
Jones Act-compliant tankers under time charter contracts, with capacities ranging in size from 300,000 to
1,100,000 barrels. Additionally, we had a variety of inland and offshore tug/barge units. These vessels are used primarily
to transport crude oil and other feedstocks and refined petroleum products for certain of our refineries. In addition, the
NGL tankers are used to export propane and butane from our fractionation, transportation and storage infrastructure.
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 wholly owned subsidiary, Sentinel Transportation LLC.
NGL and Other
Our NGL and Other business includes the following:
• A U.S. Gulf Coast NGL market hub comprised of 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 Caverns 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.
• A 12.5 percent undivided interest in a fractionation plant in Mont Belvieu, Texas. Our net share of its capacity is
30,250 BPD.
• 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 pipeline 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 NGL pipeline systems that connect the Eagle Ford, Permian Basin
and Midcontinent production areas to the Mont Belvieu, Texas, market hub.
Phillips 66 Partners, through its ownership of Merey Sweeny LLC, successor to Merey Sweeny, L.P. (both referred
to herein as Merey Sweeny), owns a vacuum distillation unit with a capacity of 125,000 BPD and a delayed coker
unit with a capacity of 70,000 BPD located at our Sweeny Refinery in Old Ocean, Texas.
Phillips 66 Partners’ Sweeny Fractionator is located adjacent to our Sweeny Refinery in Old Ocean, Texas, and supplies
purity ethane to the petrochemical industry and purity NGL 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 the Clemens Caverns storage facility with access to our liquefied petroleum gas (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 approximately 36,000 barrels per hour. In support of the terminal,
we have a 100,000-BPD unit near the Sweeny Fractionator to upgrade domestic propane for export. In addition, the
terminal exports 10,000 to 15,000 BPD of natural gasoline (C5+) produced at the Sweeny Fractionator.
8
At the Sweeny Hub, we are constructing two 150,000-BPD NGL fractionators and associated pipeline infrastructure, and
Phillips 66 Partners is adding 6 million barrels of storage capacity at Clemens Caverns. DCP Midstream has committed
to supply the fractionators with raw NGL and has an option to acquire up to a 30 percent ownership interest in the
fractionators. Upon completion of the expansion, expected in late 2020, the Sweeny Hub will have 400,000 BPD of NGL
fractionation capability and 15 million barrels of storage capacity at Clemens Caverns.
During 2018, 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 in
the third quarter of 2019.
DCP Midstream
Our Midstream segment includes our 50 percent equity investment in DCP Midstream, which is headquartered in Denver,
Colorado. At December 31, 2018, DCP Midstream owned or operated 49 active natural gas processing facilities, with a
net processing capacity of approximately 6.7 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 62,000 miles of pipeline. DCP Midstream also owned or operated 12 NGL fractionation plants,
along with natural gas and NGL storage facilities, and NGL pipelines.
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. In addition, DCP Midstream markets a portion of its NGL to us and our equity affiliates under
existing contracts.
During 2018, DCP Midstream completed or advanced the following growth projects:
• Construction of the 200-million-cubic-feet-per-day (MMcf/d) Mewbourn 3 natural gas processing plant located
in the Denver-Julesburg (DJ) Basin was completed in the third quarter of 2018.
• Continued construction of the 300-MMcf/d O'Connor 2 natural gas processing facility and associated gathering
infrastructure in the DJ Basin. The O’Connor 2 facility will have 200 MMcf/d of processing capacity and up to
100 MMcf/d of bypass capacity, which are expected to be placed into service in the second and third quarters of
2019, respectively.
• Development of the Gulf Coast Express pipeline project (GCX project), in which DCP Midstream owns a 25
percent interest. The GCX project is designed to transport up to approximately 2 Bcf/d of natural gas to the Gulf
Coast markets. The mostly 42-inch pipeline would traverse approximately 500 miles and be placed in service in
the fourth quarter of 2019.
• 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 Rockies Express Pipeline LLC’s Cheyenne Hub, where it
can then be delivered to numerous markets across the country. DCP Midstream holds an option to invest in this
pipeline at a later date.
• Expansion of the Sand Hills Pipeline to 485,000 BPD was completed in the fourth quarter of 2018. This
expansion included a partial looping of the pipeline and the addition of new pump stations.
9
CHEMICALS
The Chemicals segment consists of our 50 percent equity investment in CPChem, which is headquartered in The
Woodlands, Texas. At December 31, 2018, CPChem owned or had joint venture interests in 28 manufacturing facilities
located in Belgium, Colombia, Qatar, Saudi Arabia, Singapore and the United States. Additionally, CPChem has two
research and development centers in the United States.
We structure our reporting of CPChem’s operations around two primary business lines: Olefins and Polyolefins (O&P)
and Specialties, Aromatics and Styrenics (SA&S). The O&P business line produces and markets ethylene and other
olefin products. The ethylene produced is primarily used by CPChem to produce polyethylene, normal alpha olefins
(NAO) and polyethylene pipe. The SA&S business line manufactures and markets aromatics and styrenics products,
such as benzene, cyclohexane, styrene and polystyrene. SA&S also manufactures and/or markets a variety of specialty
chemical products including organosulfur chemicals, solvents, catalysts, and chemicals used in drilling and mining.
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 by cracking ethane, propane, butane, natural gasoline or certain refinery liquids, such as
naphtha and gas oil. Ethylene primarily is used as a raw material in the production of plastics, such as polyethylene and
polyvinyl chloride (PVC). 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.
The following table reflects CPChem’s petrochemicals and plastics product capacities at December 31, 2018:
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
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.
11,635
2,675
5,305
620
1,590
—
2,335
125
500
24,785
1,600
1,060
1,050
835
440
4,985
29,770
14,110
3,180
7,470
620
1,590
310
2,850
255
500
30,885
2,530
1,455
1,875
1,070
575
7,505
38,390
** Effective January 1, 2019, the U.S. and Worldwide ethylene capacities increased to 11,935 million pounds per year and 14,410 million pounds per year,
respectively.
10
During 2018, CPChem completed its U.S. Gulf Coast (USGC) Petrochemicals Project. The ethane cracker at CPChem’s
Cedar Bayou facility in Baytown, Texas, commenced operations in the second quarter of 2018. Along with the two
polyethylene units that started up in the third quarter of 2017, the USGC project increased CPChem’s global ethylene and
polyethylene capacity by 31 percent from January 1, 2017. Effective January 1, 2019, the capacity of the ethane cracker
increased to 3.8 billion pounds per year.
In the fourth quarter of 2018, CPChem permanently shutdown its paraxylene operations in Pascagoula, Mississippi.
11
REFINING
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 owned and joint venture refineries at December 31, 2018:
Thousands of Barrels Daily
Region/
Refinery
Atlantic Basin/
Europe
Bayway
Humber
MiRO*
Location
Interest
Linden, NJ
N. Lincolnshire,
United Kingdom
Karlsruhe,
Germany
100%
100
19
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
Roxana, IL
Borger, TX
Ponca City, OK
Billings, MT
Ferndale, WA
Carson/
Wilmington, CA
Arroyo Grande/
San Francisco, CA
100
100
100
50
50
100
100
100
100
100
Net Crude Throughput
Capacity
At
December 31
2018
Effective
January 1
Net Clean Product
Capacity**
2019 Gasolines Distillates
258
221
58
537
247
249
256
752
157
73
203
60
493
105
139
258
221
58
537
250
249
265
764
167
75
213
60
515
105
139
120
364
2,146
120
364
2,180
155
95
25
130
100
135
85
50
120
35
65
85
60
130
115
25
120
115
120
60
30
100
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.
12
Primary crude oil characteristics and sources of crude oil for our owned and joint venture refineries are as follows:
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 petroleum 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. 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. Humber is the only coking refinery in the United Kingdom, and a producer of high-quality specialty
graphite and anode-grade petroleum cokes. The refinery also produces a high percentage of transportation fuels. The
majority of the light oils produced by the refinery are distributed to customers in the United Kingdom by pipeline, railcar
and truck, while the other refined petroleum 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 produced include
petrochemical feedstocks, home heating oil, bitumen, and anode- and fuel-grade petroleum cokes. Refined petroleum
products are distributed to customers in Germany, Switzerland and Austria by truck, railcar and barge.
13
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 produced include petrochemical feedstocks, home heating oil and anode-grade
petroleum coke. A majority of the refined petroleum products are distributed to customers in the southeastern and eastern
United States through major common-carrier pipeline systems and by barge. Additionally, refined petroleum products
are exported to customers primarily 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 produced include off-road diesel, home
heating oil, feedstock for our Excel Paralubes joint venture in our M&S segment, and specialty graphite and fuel-grade
petroleum cokes. A majority of the refined petroleum products are distributed to customers in the southeastern and
eastern United States by truck, railcar, barge or major common carrier pipelines. Additionally, refined petroleum
products are exported to customers primarily 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, aromatics
units, and a Phillips 66 Partners owned delayed coking unit. The refinery produces a high percentage of transportation
fuels. Other products include petrochemical feedstocks, home heating oil and fuel-grade petroleum coke. A majority of
the refined petroleum products are distributed to customers throughout the Midcontinent region, southeastern and eastern
United States by pipeline, barge and railcar. Additionally, refined petroleum products are exported to customers
primarily in Latin America by waterborne cargo.
Central Corridor Region
WRB Refining LP (WRB)
We are the operator and managing partner of WRB, a 50-percent-owned joint venture that owns 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 produced include petrochemical feedstocks,
asphalt and fuel-grade petroleum coke. Refined petroleum products are distributed to customers throughout the
Midcontinent region by pipeline, railcar, barge and truck.
• 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. The refinery
produces a high percentage of transportation fuels, as well as fuel-grade petroleum coke, NGL and solvents.
Refined petroleum products are distributed to customers in West Texas, New Mexico, Colorado and the
Midcontinent region by pipeline.
14
Ponca City Refinery
The Ponca City Refinery is located in Ponca City, Oklahoma, approximately 95 miles northwest of Tulsa, Oklahoma.
Refinery 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 anode-grade petroleum
coke. Refined petroleum products are primarily distributed to customers throughout the Midcontinent region by
company-owned and common-carrier pipelines.
Billings Refinery
The Billings Refinery is located in Billings, Montana. Refinery 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 fuel-grade petroleum coke. Refined petroleum products are distributed to
customers in Montana, Wyoming, Idaho, Utah, Colorado and Washington by pipeline, railcar and truck.
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 produced
include residual fuel oil, which is supplied to the northwest marine bunker fuel market. Most of the refined petroleum
products are distributed to customers in the northwest United States by pipeline and barge.
Los Angeles Refinery
The Los Angeles Refinery consists of two facilities linked by pipeline 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. Refinery 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 produced include fuel-
grade petroleum coke. Refined petroleum 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 located in the San
Francisco Bay Area. Intermediate refined products from the Santa Maria facility are shipped by pipeline to the Rodeo
facility for upgrading into finished petroleum products. Refinery 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, including CARB-grade gasoline. Other products produced include fuel-grade
petroleum coke. The majority of the refined petroleum products are distributed to customers in California by pipeline
and barge. Additionally, refined petroleum products are exported to customers primarily in Latin America by waterborne
cargo.
15
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
We market gasoline, diesel and aviation fuel through independently owned outlets that utilize the Phillips 66, Conoco or
76 brands. At December 31, 2018, we had approximately 7,520 independently owned marketing outlets in 48 states.
Our wholesale operations utilized a network of marketers operating approximately 5,600 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 1,120 sites. Our refined petroleum 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 the unbranded channel of trade, which does 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 aviation gasoline and jet fuel. Aviation gasoline
and jet fuel were sold through dealers and independent marketers at approximately 800 Phillips 66-branded locations.
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, we have an equity interest in a
joint venture that markets refined petroleum products in Switzerland under the COOP brand name.
We also market aviation fuels, LPG, heating oils, transportation fuels, marine bunker fuels, bitumen and fuel-grade
petroleum coke specialty products to commercial customers and into the bulk or spot markets in the above countries.
At December 31, 2018, we had 1,310 marketing outlets in Europe, of which 985 were company owned and 325 were
dealer owned. In addition, we had interests in 320 additional sites through our COOP joint venture operations in
Switzerland.
Specialties
We manufacture lubricants and sell a variety of specialty products, including petroleum coke products, waxes, solvents
and polypropylene.
Lubricants
We manufacture and sell automotive, commercial, industrial and specialty lubricants which are marketed worldwide
under the Phillips 66, Kendall, Red Line and other private label brands. We also market Group III Ultra-S base oils
through an agreement with South Korea’s S-Oil Corporation.
In addition, we own a 50 percent interest in Excel Paralubes LLC (Excel), an operated joint venture that 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 Group II clear hydrocracked base oils. Excel markets the
produced base oil under the Pure Performance brand. The facility’s feedstock is sourced primarily from our Lake
Charles Refinery.
16
Other Specialty Products
We market high-quality specialty 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. In addition, we market sulfur for use in agricultural and chemical applications, and
fuel-grade petroleum coke for use in the making of cement, glass and power.
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 to support our current business, provide new
environmental solutions to address governmental regulations, and position us for 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 for
emerging technologies that could impact our business.
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 in many of its major product lines according
to published industry sources, based on average 2018 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, ability to run advantaged feedstocks, 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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GENERAL
At December 31, 2018, we held a total of 382 active patents in 20 countries worldwide, including 298 active U.S.
patents. The overall profitability of any business segment is not dependent on any single patent, trademark, license or
franchise.
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 2018 and those expected
for 2019 and 2020.
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.
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Item 1A. RISK FACTORS
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 the value of an investment in our common stock.
Our operating results and future rate of growth are exposed to the effects of changing commodity prices and refining,
marketing and petrochemical margins.
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 petroleum, petrochemical and plastics 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 petroleum, petrochemical and plastics products.
• Availability of feedstocks and refined petroleum 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 petroleum 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 petroleum products can fluctuate differently based on global, regional and local market
conditions, as well as by type and class of products, which 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 petroleum products. Changes in prices that occur between
when we purchase feedstocks and when we sell the refined petroleum products produced from these feedstocks could
have a significant effect on our financial results. We also purchase refined petroleum products produced by others for
sale to our customers. Price changes that occur between when we purchase and sell these refined petroleum 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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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 Financial Services LLC and Moody’s
Investors Service, Inc. 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.
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The adoption of climate change legislation or regulation could result in increased operating costs and reduced
demand for the refined petroleum 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 recovered 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 petroleum 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.
Political and economic developments could affect our operations and materially reduce our profitability and cash
flows.
Actions of federal, state, local and international governments through 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.
• 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 and from doing
business with entities affiliated with foreign governments, which can include state oil companies and U.S. subsidiaries of
those companies. The Office of Foreign Assets Control (OFAC) of the U.S. Department of the Treasury administers and
enforces economic and trade sanctions based on U.S. foreign policy and national security matters. For example,
sanctions are currently in effect against Venezuela and certain entities affiliated with it. The effect of any such OFAC
sanctions could disrupt transactions with or operations involving entities affiliated with sanctioned countries, and could
limit our ability to obtain optimum crude slates and other refinery feedstocks and effectively distribute refined petroleum
products.
Other risks inherent in doing business internationally include global financial market turmoil; economic volatility and
global economic slowdown; currency exchange rate fluctuations and inflationary pressures; import or export restrictions
and changes in trade regulations; acts of terrorism, war, civil unrest and other political risks; difficulties in developing,
staffing and managing foreign operations; and potentially adverse tax developments. If any of these events occur, our
businesses and those of our joint ventures may be adversely affected.
Additionally, renewable fuels, alternative energy mandates and energy conservation efforts could reduce demand for
refined petroleum products. Tax incentives and other subsidies can make renewable fuels and alternative energy more
competitive with refined petroleum products than they otherwise might be, which may reduce refined petroleum product
margins and hinder the ability of refined petroleum products to compete with renewable fuels.
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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 expected 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
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.
Plans we may have to expand existing assets or construct new assets, particularly in our Midstream segment, are
subject to risks associated with societal and political pressures and other forms of opposition to the future
development, transportation and use of carbon-based fuels. Such risks could adversely impact our ability to realize
certain growth strategies.
Certain of our planned expenditures are based upon the assumption that societal sentiment will continue to enable, and
existing regulations will remain intact to allow for, the future development, transportation and use of carbon-based fuels.
A portion of our growth strategy is dependent on our ability to expand existing assets and to construct additional assets.
Policy decisions relating to the production, refining, transportation and marketing of carbon-based fuels are subject to
political pressures and the influence and protests of environmental and other special interest groups. For example, our
Midstream segment’s growth plans include the construction or expansion of pipelines, which can involve numerous
regulatory, environmental, political, and legal uncertainties, many of which are beyond our control. Our growth projects
may not be completed on schedule or at the budgeted cost. In addition, our revenues may not increase immediately upon
the expenditure of funds on a particular project. Delays or cost increases related to capital spending programs could
negatively impact our results of operations, cash flows and our return on capital employed.
Our operations are subject to business interruptions and casualty losses. Failure to manage risks associated with
business interruptions could adversely impact our operations, financial condition, results of operations and cash
flows.
Our operations are subject to business interruptions due to scheduled refinery turnarounds, unplanned maintenance or
unplanned events such as explosions, fires, refinery or pipeline releases or other incidents, power outages, severe
weather, labor disputes, or other natural or man-made disasters, such as acts of terrorism, including cyber-intrusion. The
inability to operate one or more of our facilities due to any of these events could significantly impair our ability to
manufacture our products. Additionally, 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.
Explosions, fires, refinery or pipeline releases or other incidents involving our assets or operations could result in serious
personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment
of operations and substantial losses to us. 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. Damages resulting from an incident involving any of our assets or operations may result in our
being named as a defendant in one or more lawsuits asserting potentially substantial claims or in our being assessed
potentially substantial fines by governmental authorities. Should any of these risks materialize at any of our equity
affiliates, it could have a material adverse effect on the business and financial condition of the equity affiliate and
negatively impact their ability to make future distributions to us.
22
There are certain hazards and risks inherent in our operations that could adversely affect those operations and our
financial results.
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 petroleum
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.
We do not insure against all potential losses, and, therefore, our business, financial condition, results of operations
and cash flows could be adversely affected by unexpected liabilities and increased costs.
We maintain insurance coverage in amounts we believe to be prudent against many, but not all, potential liabilities arising
from operating hazards. Uninsured liabilities arising from operating hazards, including but not limited to, explosions,
fires, refinery or pipeline releases or other incidents involving our assets or operations, could reduce the funds available
to us for capital and investment spending and could have a material adverse effect on our business, financial condition,
results of operations and cash flows.
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.
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 petroleum products.
We often utilize the services of third parties to transport crude oil, NGL and refined petroleum 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 petroleum products to market if the ability of the pipelines or vessels to transport
crude oil or refined petroleum 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
petroleum 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.
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.
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 a 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
23
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’s 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 petroleum
product markets. We compete with many companies for available supplies of crude oil and other feedstocks and for
outlets for our refined petroleum 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.
We may incur losses as a result of our forward contracts 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.
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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 and employees. 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 malicious actors or breached due to human 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, including the European Union’s General Data Protection Regulation, 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
plans 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.
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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 Internal Revenue 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 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.
26
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
In November 2018, the California Air Resources Board (CARB) demanded penalties to resolve a Notice of Violation
(NOV) alleging that initial fuel certifications submitted by the company in November and December 2016 with respect to
eight batches of gasoline were non-compliant with CARB regulations. We agreed to resolve the NOV with a penalty
payment of $150,000.
In late 2018, Phillips 66 and the EPA agreed to resolve certain flaring violations alleged to have occurred at our Billings
Refinery between May 2010 and September 2018. EPA's proposed resolution includes payments of a $150,000 penalty
and approximately $220,000 for supplemental environmental projects. We are working with the EPA to finalize
settlement terms to resolve this matter.
Matters Previously Reported (unresolved or resolved since the quarterly report on Form 10-Q for the quarterly period
ended September 30, 2018)
In September 2018, the South Coast Air Quality Management District (District) demanded penalties to resolve nine
NOVs issued in 2016 and 2017. The NOVs pertain to alleged violations of air permit requirements or other air pollution
regulatory requirements at our Los Angeles Refinery and Colton Terminal. This matter was resolved with a settlement
payment of $93,500 to the District on December 6, 2018.
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.
27
EXECUTIVE OFFICERS OF THE REGISTRANT
Name
Greg C. Garland
Robert A. Herman
Paula A. Johnson
Brian M. Mandell
Kevin J. Mitchell
Chukwuemeka A. Oyolu
Timothy D. Roberts
* On February 22, 2019.
Position Held
Age*
Chairman and Chief Executive Officer
Executive Vice President, Refining
Executive Vice President, Legal and Government Affairs, General Counsel
and Corporate Secretary
Senior Vice President, Marketing and Commercial
Executive Vice President, Finance and Chief Financial Officer
Vice President and Controller
Executive Vice President, Midstream
61
59
55
55
52
49
57
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 of 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.
Brian M. Mandell is Senior Vice President, Marketing and Commercial of Phillips 66, a position he has held since
August 2018. Previously, Mr. Mandell served as Senior Vice President, Commercial from November 2016 to August
2018, President, Global Marketing from March 2015 to November 2016, and Global Trading Lead, Clean Products,
Commercial from May 2012 to March 2015.
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.
Timothy D. Roberts is Executive Vice President, Midstream of Phillips 66, a position he has held since August 2018.
Previously, Mr. Roberts served as Executive Vice President, Marketing and Commercial, from January 2017 to August
2018 and as Executive Vice President Strategy and Business Development from April 2016 to January 2017. Before
joining Phillips 66, Mr. Roberts served in a number of executive roles at LyondellBasell Industries N.V. since 2011, most
recently as Executive Vice President, Global Olefins and Polyolefins from October 2013 to March 2016.
28
PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Phillips 66’s common stock is traded on the New York Stock Exchange under the symbol “PSX.” At January 31, 2019,
our number of stockholders of record was 36,550.
Performance Graph
The performance graph above includes a peer index (the “Peer Group”) composed of 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. Additionally, Andeavor is included as a peer
for periods prior to its acquisition by Marathon Petroleum Corporation.
29
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
1,972,339
1,339,525
1,761,225
5,073,089
$
$
108.57
96.47
87.35
98.01
$
1,972,339
1,339,525
1,761,225
5,073,089
1,890
1,761
1,607
Period
October 1-31, 2018
November 1-30, 2018
December 1-31, 2018
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, 2018, our Board of Directors has authorized repurchases totaling up to $12 billion of our outstanding common stock. 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
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
Millions of Dollars Except Per Share Amounts
2018
2017
2016
2015
2014
$
111,461
5,873
102,354
5,248
84,279
1,644
98,975
4,280
161,212
4,091
5,595
11.87
11.80
5,873
5,595
5,106
1,555
4,227
4,056
9.90
9.85
5,248
5,106
2.94
2.92
1,644
1,555
7.78
7.73
4,280
4,227
7.15
7.10
4,797
4,762
Total assets
Long-term debt
Cash dividends declared per common share
* Sales and other operating revenues for the years ended December 31, 2014 through 2017, are presented in accordance with accounting standards in effect
prior to our adoption of ASU No. 2014-09 on January 1, 2018. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial
Statements, for further discussion regarding our adoption of ASU No. 2014-09.
9.90
9.85
54,371
10,069
2.73
2.94
2.92
51,653
9,588
2.45
7.78
7.73
48,580
8,843
2.18
8.40
8.33
48,692
7,793
1.89
11.87
11.80
54,302
11,093
3.10
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 year ended December 31, 2014, excludes income from PSPI’s
discontinued operations of $706 million.
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.
31
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
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.
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. The terms “pre-tax income” or “pre-tax loss” as used in Management’s Discussion and
Analysis refer to income (loss) before income taxes.
EXECUTIVE OVERVIEW AND BUSINESS ENVIRONMENT
Phillips 66 is an energy manufacturing and logistics company with midstream, chemicals, refining, and marketing and
specialties businesses. At December 31, 2018, we had total assets of $54.3 billion.
Executive Overview
In 2018, we reported earnings of $5.6 billion, generated $7.6 billion in cash from operating activities and raised net
proceeds of $1.5 billion from the issuance of senior notes. We used available cash primarily for repurchases of our
common stock of $4.6 billion, capital expenditures and investments of $2.6 billion, dividend payments on our common
stock of $1.4 billion and the early repayment of $550 million of debt. We ended 2018 with $3.0 billion of cash and cash
equivalents and approximately $5.6 billion of total committed capacity available under our 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. 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 2018, our
worldwide refining crude oil capacity utilization rate was 95 percent.
32
• Growth. We have budgeted $3.2 billion in capital expenditures and investments in 2019, including $0.9 billion
for Phillips 66 Partners LP (Phillips 66 Partners). The Phillips 66 Partners’ capital budget includes $0.3 billion
of capital expected to be cash funded by noncontrolling interests. Additionally, our share of expected self-
funded capital spending by joint ventures DCP Midstream, LLC (DCP Midstream), Chevron Phillips Chemical
Company LLC (CPChem) and WRB Refining LP (WRB) in 2019 is $1.2 billion. In Midstream, we will
continue building out our integrated logistics infrastructure network, including pipelines, storage, export and
fractionation facilities. In Chemicals, CPChem’s growth capital will fund continuing development of a second
U.S. Gulf Coast petrochemicals project and debottlenecking opportunities on existing assets. Growth capital in
Refining will be directed toward high-return projects to enhance the yield of higher-value products, as well as
other low-capital, quick-payout projects, while in Marketing and Specialties (M&S) it will be to further grow
and enhance 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 2018, our Midstream
segment benefited from higher equity earnings and cash distributions from our investments in joint venture
pipelines. Our Refining segment maintained a strong clean product yield and a high advantaged crude oil
throughput rate at our U.S. refineries. Additionally, our M&S segment continued to enhance our network and
brand by re-imaging sites in the United States.
• 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 14 percent
during 2018, and have increased it every year 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 2018, we repurchased $4.6 billion, or
approximately 48 million shares, of our common stock. 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.
33
Business Environment
The price of U.S. benchmark crude oil, West Texas Intermediate (WTI) at Cushing, Oklahoma, increased to an average of
$64.92 per barrel during 2018, compared with an average of $50.90 per barrel in 2017. The WTI discount versus the
international benchmark Dated Brent widened in 2018, compared with 2017, due to growing U.S. crude production. A
widening differential generally benefits our results. Over the course of 2018, commodity prices had both favorable and
unfavorable impacts on our businesses that vary by segment.
The Midstream segment, which includes our 50 percent equity investment in DCP Midstream, contains fee-based
operations that are not directly exposed to commodity price risk, as well as operations that are directly linked to natural
gas liquids (NGL) prices, natural gas prices and crude oil prices. Natural gas prices were relatively flat in 2018,
compared with 2017, while NGL prices were higher in 2018 due to higher global crude oil prices and increased domestic
demand for ethane.
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 2018, the high-density polyethylene chain margin contracted mainly due to rapidly expanding North
American supply. In addition, lower naptha-based feedstock costs internationally narrowed the difference between
naptha-based and ethane-based margins. However, North American ethane-based crackers integrated through ethylene
derivatives continue to benefit from a feedstock price advantage associated with abundant domestic supply and continue
to capture a higher polyethylene chain margin than crackers in most other regions of the world.
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 petroleum products and crude oil, are used to estimate refining margins. During 2018, the U.S. 3:2:1
crack spread (three barrels of crude oil producing two barrels of gasoline and one barrel of diesel) decreased compared
with 2017, primarily due to lower gasoline crack spreads caused by higher refinery utilization. The average Northwest
Europe crack spread increased slightly in 2018, compared with 2017, due to higher distillate prices.
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 petroleum
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.
34
RESULTS OF OPERATIONS
Basis of Presentation
During the fourth quarter of 2018, the segment performance measure used by our chief executive officer to assess
performance and allocate resources was changed from “net income” to “income before income taxes.” Prior-period
segment information has been recast to conform to the current presentation.
Consolidated Results
A summary of income (loss) before income taxes by business segment with a reconciliation to net income attributable to
Phillips 66 follows:
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Income before income taxes
Income tax expense (benefit)
Net income
Less: net income attributable to noncontrolling interests
Net income attributable to Phillips 66
Millions of Dollars
Year Ended December 31
2018
1,181
1,025
4,535
1,557
(853)
7,445
1,572
5,873
278
5,595
$
$
2017
638
716
2,076
1,020
(895)
3,555
(1,693)
5,248
142
5,106
2016
403
839
435
1,261
(747)
2,191
547
1,644
89
1,555
2018 vs. 2017
Our earnings increased $489 million, or 10 percent, in 2018, mainly reflecting:
• Higher realized refining and marketing margins.
• Higher earnings from equity affiliates in our Midstream and Chemicals segments.
• A lower U.S. federal corporate income tax rate beginning January 1, 2018, as a result of the U.S. Tax Cuts and
Jobs Act (the Tax Act) enacted in December 2017.
These increases were partially offset by:
• A $2,735 million provisional income tax benefit from the enactment of the Tax Act recognized in December
2017, primarily due to the revaluation of deferred income taxes.
• A $261 million noncash, after-tax gain from the consolidation of Merey Sweeny, L.P., predecessor to Merey
Sweeny LLC (both referred to herein as Merey Sweeny), in 2017.
• Higher net income attributable to noncontrolling interests primarily due to the contribution of assets to Phillips
66 Partners in the fourth quarter of 2017.
• Higher interest and debt expense.
35
2017 vs. 2016
Our earnings increased $3,551 million, or 228 percent, in 2017, primarily resulting from:
• Recognition of the $2,735 million provisional income tax benefit from the enactment of the Tax Act in
December 2017.
• Higher realized refining margins.
• Recognition of the $261 million after-tax gain from the consolidation of Merey Sweeny.
•
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.
See the “Segment Results” section for additional information on our segment results.
36
Income Statement Analysis
2018 vs. 2017
Sales and other operating revenues and purchased crude oil and products increased 9 percent and 23 percent, respectively,
in 2018. The increases were mainly due to higher prices for refined petroleum products, crude oil and NGL. The
increase in sales and other operating revenues was partially offset by a change in the presentation of excise taxes on sales
of refined petroleum products resulting from our adoption of Financial Accounting Standard Board (FASB) Accounting
Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” on January 1, 2018. As
part of our adoption of this ASU, prospectively from January 1, 2018, our presentation of excise taxes on sales of refined
petroleum products changed to a net basis from a gross basis. As a result, the “Sales and other operating revenues” and
“Taxes other than income taxes” lines on our consolidated statement of income for the year ended December 31, 2018,
are not presented on a comparable basis to the years ended December 31, 2017 and 2016. See Note 1—Summary of
Significant Accounting Policies and Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial
Statements, for further information on our presentation of excise taxes on sales of refined petroleum products and our
adoption of this ASU, respectively.
Equity in earnings of affiliates increased 55 percent in 2018, primarily resulting from higher equity in earnings from
WRB, CPChem and affiliates in our Midstream segment.
• Equity in earnings of WRB increased $483 million, primarily due to higher realized margins driven by improved
feedstock advantage.
• Equity in earnings of CPChem increased $312 million, primarily due to commencement of full operations at
CPChem’s new U.S. Gulf Coast petrochemicals assets and lower hurricane-related costs and downtime in 2018.
• Equity in earnings for our Midstream segment increased $222 million, primarily due to higher volumes on
affiliate pipelines, including the Bakken Pipeline, which operated for a full year in 2018.
Other income decreased $460 million in 2018. We recognized a noncash, pre-tax gain of $423 million in February 2017
related to the consolidation of Merey Sweeny. See Note 5—Business Combinations, in the Notes to Consolidated
Financial Statements, for additional information.
Taxes other than income taxes decreased 97 percent in 2018. The decrease was primarily attributable to the change in our
presentation of excise taxes on sales of refined petroleum products resulting from our adoption of ASU No. 2014-09 on
January 1, 2018. See the “Sales and other operating revenues” section above for further discussion.
Interest and debt expense increased 15 percent in 2018. The increase was due to higher average debt principal balances
resulting from our issuance of senior notes totaling $1,500 million in March 2018 and Phillips 66 Partners’ issuance of
senior notes totaling $650 million in October 2017.
Income tax expense (benefit) was an expense in 2018, compared with a benefit in 2017. The benefit in 2017 was due to
the recognition of a provisional income tax benefit of $2,735 million from the enactment of the Tax Act in December
2017. The benefit from the Tax Act was primarily due to the revaluation of deferred income taxes. Excluding this
benefit, income tax expense increased in 2018 due to higher income before income taxes, partially offset by the reduction
of the U.S. federal corporate income tax rate from 35 percent to 21 percent beginning January 1, 2018, as a result of the
Tax Act. See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for more information
regarding our income taxes.
Net income attributable to noncontrolling interests increased $136 million in 2018, primarily due to the contribution of
assets to Phillips 66 Partners in the fourth quarter of 2017. See Note 27—Phillips 66 Partners LP, in the Notes to
Consolidated Financial Statements, for more information.
37
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 refined 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 pipeline
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 Merey Sweeny. 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 driven by lower capitalized interest
due to the completion of major projects, including completion of the Freeport LPG Export Terminal project in late 2016,
as well as higher average debt principal balances.
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. The benefit from the Tax Act was
primarily due to the revaluation of deferred income taxes. 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 interests increased $53 million in 2017, primarily due to the contributions 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.
38
Segment Results
Midstream
Income (Loss) Before Income Taxes
Transportation
NGL and Other
DCP Midstream
Total Midstream
Transportation Volumes
Pipelines*
Terminals
Operating Statistics
NGL fractionated**
NGL extracted***
Year Ended December 31
2018
2017
2016
Millions of Dollars
$
$
770
305
106
1,181
530
32
76
638
442
(5)
(34)
403
Thousands of Barrels Daily
3,441
3,153
3,320
2,665
3,321
2,422
170
393
* Pipelines represent the sum of volumes transported through each separately tariffed consolidated pipeline segment. Prior year volumes have been recast
186
374
216
413
to exclude 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.
Weighted-Average NGL Price*
DCP Midstream
* Based on index prices from the Mont Belvieu market hub, which are weighted by NGL component.
$
Dollars Per Gallon
0.75
0.62
0.46
The Midstream segment provides crude oil and refined petroleum product transportation, terminaling and processing
services, as well as natural gas and NGL 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).
2018 vs. 2017
Pre-tax income from the Midstream segment increased $543 million in 2018, compared with 2017, due to improved
results across all business lines.
Pre-tax income from our Transportation business increased $240 million in 2018, compared with 2017. The increase was
mainly driven by higher volumes, tariffs and storage rates from our portfolio of consolidated and joint venture assets.
These increases were partially offset by a decrease in equity earnings from Rockies Express Pipeline LLC (REX) due to a
favorable settlement recorded in 2017.
Pre-tax income from our NGL and Other business increased $273 million in 2018, compared with 2017. The increase
was primarily due to the contribution of Merey Sweeny to Phillips 66 Partners in October 2017, inventory impacts,
improved cargo margins and volumes, and higher equity earnings from pipeline affiliates due to increased volumes.
39
Pre-tax income from our investment in DCP Midstream increased $30 million in 2018, compared with 2017. The
increase was primarily due to higher equity earnings from affiliates as a result of increased volumes, timing of incentive
distribution income allocations from DCP Partners, and favorable hedging results. These increases were partially offset
by higher asset impairments and operating costs in 2018.
See the “Executive Overview and Business Environment” section for information on market factors impacting 2018
results.
2017 vs. 2016
Pre-tax income from the Midstream segment increased $235 million in 2017, compared with 2016, due to improved
results across all business lines.
Pre-tax income from our Transportation business increased $88 million in 2017, compared with 2016. The improvement
was mainly driven by increased equity earnings from affiliates, including our joint ventures that own the Bakken
Pipeline, which started commercial operations in June 2017, as well as REX due to our share of a favorable breach of
contract settlement claim. These increases were partially offset by higher operating costs.
Pre-tax income from our NGL and Other business increased $37 million in 2017, compared with 2016. The increase
reflected a full year of operations at the Freeport LPG Export Terminal, the contribution of Merey Sweeny 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.
Pre-tax income from our investment in DCP Midstream increased $110 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
hedging results.
40
Chemicals
Year Ended December 31
2018
2017
2016
Millions of Dollars
Income Before Income Taxes
$
1,025
716
839
CPChem Externally Marketed Sales Volumes*
Olefins and Polyolefins
Specialties, Aromatics and Styrenics
Millions of Pounds
18,435
4,931
23,366
15,870
4,618
20,488
16,011
4,911
20,922
* 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)
94%
87
91
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 lines: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P
business line 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 line
manufactures and markets aromatics and styrenics products, such as benzene, cyclohexane, styrene and 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.
2018 vs. 2017
Pre-tax income from the Chemicals segment increased $309 million in 2018, compared with 2017. The increased results
reflected the commencement of full operations at CPChem’s new U.S. Gulf Coast petrochemicals assets in the second
quarter of 2018, which resulted in higher production and sales of polyethylene and ethylene, partially offset by lower
capitalized interest. Additionally, lower hurricane-related costs and downtime, as well as lower impairment charges,
contributed to the increased results in 2018.
See the “Executive Overview and Business Environment” section for information on market factors impacting CPChem’s
2018 results.
2017 vs. 2016
Pre-tax income from the Chemicals segment decreased $123 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, pre-tax income from the Chemicals segment was reduced by $64
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. Startup of CPChem’s U.S. Gulf Coast Petrochemicals Project was delayed by the flooding.
41
Refining
Income (Loss) Before Income Taxes
Atlantic Basin/Europe
Gulf Coast
Central Corridor
West Coast
Worldwide
Income (Loss) Before Income Taxes
Atlantic Basin/Europe
Gulf Coast
Central Corridor
West Coast
Worldwide
Year Ended December 31
2018
2017
2016
Millions of Dollars
$
$
$
567
1,040
2,817
111
4,535
3.05
3.55
26.50
0.81
6.29
448
809
755
64
2,076
Dollars Per Barrel
2.25
2.83
8.19
0.48
2.92
187
69
367
(188)
435
0.85
0.24
3.74
(1.49)
0.60
Realized Refining Margins*
6.26
Atlantic Basin/Europe
5.49
Gulf Coast
8.70
Central Corridor
9.15
West Coast
6.99
Worldwide
* See the “Non-GAAP Reconciliations” section for a reconciliation of this non-GAAP measure to the most directly comparable GAAP measure, income (loss)
10.32
9.48
22.22
11.20
12.99
8.25
7.07
12.44
10.49
9.13
$
before income taxes per barrel.
42
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
2018
2017
2016
537
477
89%
514
752
717
95%
808
493
507
103%
530
364
343
94%
373
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
2,146
2,044
95%
2,225
2,116
2,012
95
2,199
2,162
2,075
96
2,241
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.
2018 vs. 2017
Pre-tax income for the Refining segment increased $2,459 million in 2018, compared with 2017. The increase was
primarily due to higher realized refining margins, partially offset by a noncash gain of $423 million recognized on the
consolidation of Merey Sweeny in February 2017.
The increased realized refining margins were primarily driven by higher feedstock advantage, improved premium coke
margins, and increased optimization benefits from using our integrated logistics network to capture market opportunities
related to widening Bakken, Canadian and other inland crude differentials. Improved clean product differentials and
lower renewable identification number (RIN) costs also benefited margins. These items were partially offset by a decline
in market crack spreads.
See the “Executive Overview and Business Environment” section for information on industry crack spreads and other
market factors impacting this year’s results.
Our worldwide refining crude oil capacity utilization rate was 95 percent in both 2018 and 2017.
43
2017 vs. 2016
Pre-tax income for the Refining segment increased $1,641 million in 2017, compared with 2016. The increase was
primarily due to higher realized refining margins and West Coast volumes, as well as a noncash gain of $423 million
recognized on the consolidation of Merey Sweeny, 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 Note 5—Business Combinations, in the Notes to Consolidated Financial Statements, for additional information on
the consolidation of Merey Sweeny in February 2017 and the subsequent contribution of our ownership interest in Merey
Sweeny to Phillips 66 Partners in October 2017.
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.
44
Marketing and Specialties
Income Before Income Taxes
Marketing and Other
Specialties
Total Marketing and Specialties
Income Before Income Taxes
U.S.
International
Year Ended December 31
2018
2017
2016
Millions of Dollars
$
$
$
1,306
251
1,557
1.21
5.00
808
212
1,020
Dollars Per Barrel
0.89
2.23
1,044
217
1,261
1.15
2.36
Realized Marketing Fuel Margins*
U.S.
International
* See the “Non-GAAP Reconciliations” section for a reconciliation of this non-GAAP measure to the most directly comparable GAAP measure, income
1.48
4.21
1.62
6.87
$
1.64
4.05
before income taxes per barrel.
U.S. Average Wholesale Prices*
Gasoline
Distillates
* On third-party branded refined petroleum product sales, excluding excise taxes.
Dollars Per Gallon
$
2.20
2.29
1.87
1.85
1.62
1.48
Marketing Refined Petroleum Product Sales
Gasoline
Distillates
Other
Thousands of Barrels Daily
1,195
975
18
2,188
1,246
931
18
2,195
1,238
947
16
2,201
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.
2018 vs. 2017
Pre-tax income from the M&S segment increased $537 million in 2018, compared with 2017. The increase was
primarily due to higher realized marketing fuel margins, mainly driven by international marketing, benefits from the
retroactive extension of the 2017 U.S. biodiesel blender’s tax incentive in early 2018, as well as improved specialty
product service margins.
See the “Executive Overview and Business Environment” section for information on marketing fuel margins and other
market factors impacting 2018 results.
2017 vs. 2016
Pre-tax income from the M&S segment decreased $241 million in 2017, compared with 2016. The decrease was
primarily due to lower realized marketing margins, as well as the absence of U.S. biofuel tax credits recognized in 2016.
45
Corporate and Other
Income (Loss) Before Income Taxes
Net interest expense
Corporate general and administrative expenses
Technology
Other
Total Corporate and Other
2018 vs. 2017
Millions of Dollars
Year Ended December 31
2018
(459)
(257)
(88)
(49)
(853)
$
$
2017
(408)
(268)
(94)
(125)
(895)
2016
(322)
(246)
(91)
(88)
(747)
Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net
interest expense increased $51 million in 2018, compared with 2017, mainly due to higher average debt principal
balances from our issuance of senior notes totaling $1,500 million in March 2018 and Phillips 66 Partners’ issuance of
senior notes totaling $650 million in October 2017. This increase was partially offset by higher interest income.
The category “Other” includes 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 $76 million decrease
in other costs in 2018, compared with 2017, was primarily attributable to lower environmental-related expenses and
higher equity earnings from our share of income tax benefits recorded by equity affiliates due to the enactment of the Tax
Act in December 2017.
2017 vs. 2016
Net interest expense increased $86 million in 2017, compared with 2016, primarily driven by lower capitalized interest
due to the completion of major projects, including completion of the Freeport LPG Export Terminal project in late 2016,
and higher interest expense driven by higher average debt principal balances due to Phillips 66 Partners’ debt issuances in
October 2017 and 2016.
Corporate general and administrative expenses increased $22 million in 2017, compared with 2016, due to higher
employee-related costs.
Other costs increased $37 million in 2017, compared with 2016, mainly due to higher environmental-related expenses.
46
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
2018
2017
2016
$
3,019
7,573
67
11,160
27,153
29%
11%
3,119
3,648
41
10,110
27,428
27
11
2,711
2,963
550
10,138
23,725
30
3
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 has raised funds for its growth activities
through debt and equity financings. During 2018, we generated $7.6 billion in cash from operations and raised net
proceeds of $1.5 billion from the issuance of senior notes. We used this available cash primarily for repurchases of our
common stock of $4.6 billion; capital expenditures and investments of $2.6 billion; dividend payments on our common
stock of $1.4 billion; and the early repayment of $550 million of debt. During 2018, cash and cash equivalents decreased
by $100 million, to $3.0 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 debt securities 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 2018, cash of $7,573 million was provided by operating activities, a 108 percent increase compared with 2017.
The increase was primarily attributable to higher realized refining and marketing margins, increased distributions from
our equity affiliates and lower employee benefit plan contributions. These increases were partially offset by unfavorable
working capital impacts primarily driven by the effects of changes in commodity prices and the timing of payments and
collections.
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 improved operating results due to higher realized refining margins and
increased distributions from our equity affiliates. These increases were 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.
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.
47
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 both 2018 and 2017.
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, 2018, we received aggregate
distributions from our equity affiliates of $4,712 million, including $201 million from DCP Midstream, $1,603 million
from CPChem and $1,124 million from WRB. CPChem resumed distributions to us in the first quarter of 2018 following
the return to full operations of its Cedar Bayou facility post-Hurricane Harvey and the start-up of its new U.S. Gulf Coast
petrochemicals assets. 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.
Phillips 66 Partners
In 2013, we formed Phillips 66 Partners, a publicly traded MLP, to own, operate, develop and acquire primarily fee-based
midstream assets.
Ownership
At December 31, 2018, we owned a 54 percent limited partner interest and a 2 percent general partner interest in Phillips
66 Partners, while the public owned a 44 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 27—
Phillips 66 Partners LP, 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 of $2,469 million in our consolidated balance sheet at
December 31, 2018.
Debt and Equity Financings
During the three years ended December 31, 2018, Phillips 66 Partners raised net proceeds of approximately $4.1 billion
from the following third-party debt and equity offerings:
•
•
•
•
•
•
•
In June 2018, Phillips 66 Partners completed its initial $250 million continuous offering of common units, or at-
the-market (ATM) program, and commenced issuing common units under its second $250 million ATM
program. Since inception in June 2016 through December 31, 2018, net proceeds of $320 million have been
received under these programs.
In October 2017, Phillips 66 Partners received net proceeds of $643 million from the issuance of $500 million of
3.750% Senior Notes due March 2028 and $150 million of 4.680% Senior Notes due February 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 October 2026 and $625 million of 4.900% Senior Notes due October 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 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.
48
Phillips 66 Partners primarily used these net proceeds to fund the cash portion of acquisitions of assets from Phillips 66
and for capital spending and investments. See Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial
Statements, for additional information on Phillips 66 Partners.
Credit Facilities and Commercial Paper
Phillips 66 has a $5 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 are 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 Financial Services LLC (S&P) and
Moody’s Investors Service, Inc. (Moody’s). The facility also provides for customary fees, including administrative agent
fees and commitment fees. At December 31, 2018, no amount had been drawn under this revolving credit agreement.
Phillips 66 has a $5 billion commercial paper program for short-term working capital needs that is supported by its
revolving credit facility. Commercial paper maturities are generally limited to 90 days. At December 31, 2018, no
borrowings were outstanding under the 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 and contains covenants that are usual and customary for an
agreement of this type for comparable commercial borrowers. At Phillips 66 Partners’ option, outstanding borrowings
under this facility bear interest at either i) the Eurodollar rate plus a margin based on its credit rating; or ii) the base rate
(as described in the facility agreement) plus a margin based on its credit rating. Eurodollar rate borrowings are due on
the facility’s termination date, while base rate borrowings are due the earlier of the facility’s termination date or the
fourteenth business day after such borrowings were made. At December 31, 2018, Phillips 66 Partners had borrowings
of $125 million outstanding under this facility.
Other Debt Issuances and Financings
On March 1, 2018, Phillips 66 closed on a public offering of $1,500 million aggregate principal amount of unsecured
notes consisting of:
•
•
$500 million of floating-rate Senior Notes due February 2021. Interest on these notes is equal to the three-
month LIBOR plus 0.60% per annum and is payable quarterly in arrears on February 26, May 26, August 26 and
November 26, beginning on May 29, 2018.
$800 million of 3.900% Senior Notes due March 2028. Interest on these notes is payable semiannually on
March 15 and September 15 of each year, beginning on September 15, 2018.
• An additional $200 million of our 4.875% Senior Notes due November 2044. Interest on these notes is payable
semiannually on May 15 and November 15 of each year, beginning on May 15, 2018.
Phillips 66 used the net proceeds from the issuance of these notes and cash on hand to repay commercial paper
borrowings during the first quarter of 2018, and for general corporate purposes. The commercial paper borrowings
during the first quarter of 2018, were primarily used to repurchase shares of our common stock. See Note 17—Equity, in
the Notes to Consolidated Financial Statements, for additional information.
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 fifteen years. The present value of our minimum
capital lease payments for these obligations as of December 31, 2018, was $184 million.
49
Availability of Debt and Equity Financing
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.
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 at December 31, 2018. The operating lease term ends in June 2021 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 $300 million at December 31, 2018, which have remaining terms of up to five years.
In addition, we have guarantees outstanding related to certain joint venture debt and purchase obligations, which have
remaining terms of up to seven years. The maximum potential amount of future payments to third parties under these
guarantees was approximately $304 million at December 31, 2018.
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 the “Capital Spending” section below.
Debt Financing
Our debt balance at December 31, 2018, was $11.2 billion and our total debt-to-capital ratio was 29 percent.
In 2018, Phillips 66 made early debt repayments totaling $550 million, comprised of $300 million floating-rate notes due
April 2019 and $250 million of the $450 million outstanding under its three-year term loan facility due April 2020.
See Note 12—Debt, in the Notes to Consolidated Financial Statements, for our annual debt maturities over the next five
years and more information on debt repayments.
Dividends
On February 6, 2019, our Board of Directors declared a quarterly cash dividend of $0.80 per common share, payable
March 1, 2019, to holders of record at the close of business on February 19, 2019. We are forecasting a double-digit
percentage increase in our quarterly dividend rate in 2019.
Share Repurchases
Since July 2012, our Board of Directors has, at various times, authorized repurchases of our outstanding common stock
under our share repurchase program, which aggregate to a total authorization of up to $12 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. Since the inception of our share repurchase program in 2012 through December 31, 2018, we have
repurchased approximately 137 million shares at an aggregate cost of $10.4 billion. Shares of stock repurchased are held
as treasury shares.
50
In February 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 $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 in February 2018. We funded the repurchase
with cash of $1.9 billion and borrowings of $1.4 billion under our commercial paper program. These borrowings were
subsequently refinanced through a public offering of senior notes. This specific share repurchase transaction was
separately authorized by our Board of Directors and therefore did not impact previously announced authorizations under
our share repurchase program, which are discussed above.
Employee Benefit Plan Contributions
For the year ended December 31, 2018, we contributed $150 million to our U.S. employee benefit plans and $34 million
to our international employee benefit plans. In 2019, we expect to contribute approximately $90 million to those plans.
51
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2018:
Millions of Dollars
Payments Due by Period
Up to
1 Year
50
17
67
477
509
31,361
7
76
14
32,511
Years
2-3
1,450
26
1,476
905
573
8,547
44
132
32
11,709
Years
4-5
2,000
22
2,022
743
207
5,317
20
89
46
8,444
After
5 Years
7,576
119
7,695
5,159
292
26,609
190
150
89
40,184
Total
11,076
184
11,260
7,284
1,581
71,834
261
447
181
92,848
$
$
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
Repatriation income tax liability (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 with 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 raw NGL. The products are used to
supply our refineries and fractionators and optimize our supply chain. Product purchase commitments with third
parties totaled $31,242 million. In addition, $20,642 million are product purchases from CPChem, mostly for
fuel gas and natural gasoline over the remaining contractual term of 81 years, and product purchases of $4,797
million from DCP Midstream entities for NGL over the remaining contractual term of ten years.
Purchase obligations of $4,832 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 and unrecognized income tax benefits. From 2019 through 2023, we expect to contribute an
average of $120 million per year to our qualified and nonqualified pension and other postretirement benefit plans
in the United States and an average of $25 million per year to our non-U.S. plans. The U.S. five-year average
consists of approximately $60 million for 2019 and $135 million per year for the remaining four years. Our
minimum funding in 2019 is expected to be $60 million in the United States and $30 million outside the United
States. Unrecognized income tax benefits of $23 million were also excluded because the ultimate disposition
and timing of any payments to be made with regard to such amounts are not reasonably estimable.
(d) We elected to pay the one-time deemed repatriation income tax on foreign-sourced earnings, recognized as a
result of the Tax Act enacted in December 2017, in installments over eight years beginning in 2018. The amount
represents the remaining income tax liability.
52
Capital Spending
Capital Expenditures and Investments
Midstream*
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Selected Equity Affiliates**
DCP Midstream
CPChem
WRB
2019
Budget
1,936
—
923
161
177
3,197
505
572
165
1,242
$
$
$
$
Millions of Dollars
2018
1,548
—
826
125
140
2,639
484
339
156
979
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
* 2019 budget includes $303 million of capital expected to be cash funded by noncontrolling interests.
** Our share of joint venture’s self-funded capital spending.
Midstream
Capital spending in our Midstream segment during the three-year period ended December 31, 2018, included:
• Construction activities related to additional Gulf Coast fractionation capacity and Freeport LPG Export Terminal
projects.
• Construction activities related to increasing storage capacity at our crude oil and refined petroleum products
terminal located near Beaumont, Texas.
• Development of the Gray Oak Pipeline system, which will provide crude oil transportation from the Permian
Basin and Eagle Ford to destinations in the Corpus Christi and Sweeny/Freeport markets on the Texas Gulf
Coast. At December 31, 2018, Phillips 66 Partners had a 48.75 percent effective ownership interest in this
pipeline system. In February 2019, another party exercised its option to acquire an interest in the pipeline
system that reduced Phillips 66 Partners’ effective ownership interest to 42.25 percent.
• Development of the Bayou Bridge Pipeline by Phillips 66 Partners’ 40-percent-owned joint venture.
• 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 Bakken Pipeline system project, in which Phillips 66 Partners owns a 25 percent interest.
• 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.
• Construction activities related to Phillips 66 Partners’ new isomerization unit at the Lake Charles Refinery.
• Expansion activities on the Phillips 66 Partners’ 50-percent owned STACK Pipeline 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.
•
Spending associated with other return, reliability and maintenance projects in our Transportation and NGL
business.
53
During the three-year period ended December 31, 2018, DCP Midstream’s self-funded capital expenditures and
investments were $1.7 billion on a 100 percent basis. Capital spending during this period was primarily for expansion of
owned and joint venture natural gas processing and pipeline capacity.
In 2018, REX repaid $550 million of its debt, reducing its total debt to approximately $2 billion. REX funded the
repayment through member cash contributions, of which our 25 percent share was approximately $138 million.
Chemicals
During the three-year period ended December 31, 2018, 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 $4.2 billion. Capital spending during this period was primarily for the U.S. Gulf
Coast Petrochemicals Project.
Refining
Capital spending for the Refining segment during the three-year period ended December 31, 2018, was $2.8 billion,
primarily for air emission reduction and clean fuels projects to meet new environmental standards, refinery upgrade
projects to increase processing of advantaged crudes and improve product yields, improvements to the operating integrity
of key processing units, and safety-related projects. Generally, our equity affiliates in the Refining segment are expected
to have self-funding capital programs. During this three-year period, on a 100 percent basis, WRB’s capital expenditures
and investments were $892 million.
Key projects completed during the three-year period included:
•
•
•
Installation of facilities to improve clean product yield at the Sweeny, Lake Charles, Ponca City, and Bayway
refineries, as well as the jointly owned Wood River Refinery.
Installation of facilities to improve processing of advantaged crudes at the Billings and Lake Charles 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, Bayway 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 Ferndale Refinery.
Installation of facilities to improve product value at the Sweeny and Lake Charles refineries, as well as the
jointly owned Borger Refinery.
•
Installation of facilities for U.K. biofuels compliance at the Humber Refinery.
Marketing and Specialties
Capital spending for the M&S segment during the three-year period ended December 31, 2018, was primarily for the
acquisition and further development of new international retail sites. In addition, capital was used for reliability and
maintenance projects at our lubricants and power generation facilities.
Corporate and Other
Capital spending for Corporate and Other during the three-year period ended December 31, 2018, was primarily for
information technology and facilities.
54
2019 Budget
Our 2019 capital budget is $3.2 billion including Phillips 66 Partners’ expected capital spending of $0.9 billion. This
excludes our portion of planned capital spending by joint ventures DCP Midstream, CPChem and WRB totaling $1.2
billion, all of which is expected to be self-funded. Phillips 66 Partners’ expected capital spending includes $0.3 billion of
capital expected to be cash funded by noncontrolling interests.
The Midstream capital budget of $1.9 billion includes 300,000 barrels per day of additional fractionation capacity at the
Sweeny Hub, as well as ongoing expansion of the Beaumont Terminal and pipeline investments providing integration
across our value chain. The Midstream capital budget also includes growth capital at Phillips 66 Partners to support
organic projects, including the Gray Oak Pipeline, South Texas Gateway Terminal, Clemens Caverns expansion, an
isomerization unit at the Phillips 66 Lake Charles Refinery, and the Sweeny to Pasadena Pipeline. Refining’s capital
budget of $0.9 billion is primarily directed toward reliability, safety and environmental projects, as well as high-return
projects to enhance the yield of higher-value products, including an upgrade of the fluid catalytic cracking unit at the
Sweeny Refinery, and other low-capital, quick-payout projects. In M&S, we plan to invest approximately $0.2 billion of
growth and sustaining capital; the investment will further grow and enhance retail sites in Europe. In Corporate and
Other, we plan to fund approximately $0.2 billion in projects primarily related to information technology projects,
including implementation of a new enterprise resource planning system.
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.
55
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 (GHG) 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 affect refineries in the Los Angeles metropolitan area. In 2017, SCAQMD required additional nitrogen dioxide
emissions reductions through 2025 and is now promulgating new regulations 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 2019
compliance year, the EPA has set volumes of advanced and total renewable fuel at higher levels than in previous years
(the 2019 compliance year volumes are approximately 3 percent higher than those required for the 2018 and 2017
compliance years); it is uncertain if these increased obligations will be achievable by fuel producers and shippers without
56
drawing on the RIN bank. EISA requires EPA to reset the statutory volumes if EPA waives the volumes by 20 percent or
more for two consecutive years. The 2019 rulemaking triggered this requirement and EPA is currently working on
rulemaking that will set volumes for 2020 through 2022. 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 2018 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
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, 2017, we reported that we had been
notified of potential liability under CERCLA and comparable state laws at 31 sites within the United States. During
2018, we were notified of one new site, one previously resolved site that was returned to active status, four sites that were
deemed resolved and closed, and two sites that were deemed resolved but not closed, leaving 27 unresolved sites with
potential liability at December 31, 2018.
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 2018 and are expected to be approximately $740 million and $700
million in 2019 and 2020, respectively. Capitalized environmental costs were $149 million in 2018 and are expected to
be approximately $115 million and $125 million, in 2019 and 2020, respectively. This amount does not include capital
expenditures made for another purpose that have an indirect benefit on environmental compliance.
57
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 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 reviews, 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 GHG 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 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, which remains the subject of litigation
and administrative review.
• 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
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.
58
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.
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 was 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.
59
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles in the United States
(GAAP) 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. Some 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 expected cash flows. If the sum of the undiscounted expected future 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
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.
Different 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 cost of future asset removals 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.
60
Intangible Assets and Goodwill
At December 31, 2018, we had $753 million of intangible assets that we have determined to have indefinite useful lives,
and therefore are not amortized. The judgmental determination that an intangible asset has an indefinite useful life is
continuously evaluated. 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 determined to have indefinite lives, they will be subject to at least annual impairment tests that require
management’s judgment of their estimated fair value.
At December 31, 2018, 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 tests for impairment at a reporting unit level. A
reporting unit is an operating segment or a component that is one level below an operating segment and they are
determined primarily based on the manner in which the business is managed.
We perform our annual goodwill impairment test using either a qualitative assessment or a quantitative assessment. As
part of our qualitative assessment, we evaluate relevant events and circumstances that could affect the fair value of our
reporting units, including macroeconomic conditions, overall industry and market considerations and regulatory changes,
as well as company-specific market metrics, performance and events. The evaluation of company-specific events and
circumstances includes evaluating changes in our stock price and cost of capital, actual and forecasted financial
performance, as well as the effect of significant asset dispositions. If our qualitative assessment indicates it is likely the
fair value of a reporting unit has declined below its carrying value (including goodwill), or if we elect not to perform a
qualitative assessment, a quantitative assessment is performed.
When a quantitative assessment is performed, management applies judgment in determining the estimated fair values of
the reporting units because quoted market prices for our reporting units are not available. Management uses available
information to make this fair value determination, including estimated cash flows, cost of capital, observed market
earnings multiples of comparable companies, our common stock price and associated total company market
capitalization.
We completed our annual impairment test as of October 1, 2018, and concluded that the fair values of our reporting units
continued to exceed their respective carrying values (including goodwill) by significant percentages. A decline in the
estimated fair value of one or more of our reporting units in the future could result in an impairment. As such, we
continue to monitor for indicators of impairment until our next annual impairment test is performed.
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.
61
Projected Benefit Obligations
Calculation 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 calculation 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. We engage outside actuarial firms to assist in the calculation of these projected benefit obligations and company
contribution requirements due to the specialized nature of these calculations. 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 used for the plan
obligation would increase annual benefit expense by an estimated $50 million, while a one percentage-point decrease in
the return on plan assets assumption would increase annual benefit expense by an estimated $30 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 2018 and 2017, the expected weighted-average long-term rate of return for worldwide pension plan assets was
approximately 6 percent, while the actual weighted-average rate of return was a negative 4 percent in 2018 and a positive
15 percent in 2017. For the past ten years, our actual weighted-average rate of return for worldwide pension plan assets
was 9 percent.
62
NEW ACCOUNTING STANDARDS
In February 2018, the FASB issued ASU No. 2018-02, “Income Statement—Reporting Comprehensive Income (Topic
220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU allows for the
deferred income tax effects stranded in accumulated other comprehensive income (AOCI) resulting from the Tax Act
enacted in December 2017 to be reclassed from AOCI to retained earnings. This ASU is effective for fiscal years, and
interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. Upon
adoption on January 1, 2019, we increased retained earnings by approximately $90 million with the offset to accumulated
other comprehensive loss on our consolidated balance sheet.
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 evaluating the provisions of ASU No. 2016-13, and currently do not expect
our adoption to have a material impact on our consolidated 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. The ASU also requires additional disclosures. 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. We will adopt ASU No. 2016-02 by recognizing a cumulative-
effect adjustment to our opening consolidated balance sheet as of our January 1, 2019, adoption date. As of the adoption
date, we expect to recognize ROU assets and operating lease liabilities on our consolidated balance sheet of
approximately $1.4 billion. The adoption of this ASU is not expected to have a material impact on our consolidated
statements of income and cash flows.
63
NON-GAAP RECONCILIATIONS
Refining
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 realized refining 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. We believe 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.
The GAAP performance measure most directly comparable to realized refining margin per barrel is the Refining
segment’s “income before income taxes per barrel.” Realized 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 income before income taxes, such as general and administrative expenses. It also includes our proportional
share of joint venture refineries’ realized refining margins and excludes special items. Because realized refining margin
per barrel is calculated in this manner, and because realized 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 income before
income taxes to realized refining margins:
64
Realized Refining Margins
Year Ended December 31, 2018
Income before income taxes
Plus:
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)*
Income before income taxes per barrel (dollars per
barrel)**
Realized refining margins (dollars per barrel)***
Year Ended December 31, 2017
Income before income taxes
Plus:
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
$
$
$
Millions of Dollars, Except as Indicated
Atlantic
Basin/
Europe
Gulf
Coast
Central
Corridor
West
Coast Worldwide
$
567
1,040
2,817
111
4,535
56
201
63
950
10
(11)
87
88
268
57
1,312
6
3
43
135
34
488
(812)
(13)
100
237
50
1,040
—
(9)
287
841
204
3,790
(796)
(30)
—
1,565
—
1,652
(5)
1,918
—
2,774
—
4,257
—
1,529
(5)
10,478
186,042
186,042
292,665
292,665
106,299
191,561
136,332
136,332
721,338
806,600
3.05
10.32
3.55
9.48
26.50
22.22
0.81
11.20
6.29
12.99
448
56
192
61
847
11
(10)
59
809
755
64
64
244
48
982
—
5
—
46
129
34
593
(329)
13
959
97
273
55
1,212
(4)
(421)
1
—
2,022
2,076
263
838
198
3,634
(322)
(413)
1,019
(23)
7,270
(23)
1,641
$
—
2,200
—
1,407
Total processed inputs (thousands of barrels)
Adjusted total processed inputs (thousands of barrels)*
199,068
199,068
285,951
285,951
92,146
176,823
134,089
134,089
711,254
795,931
Income before income taxes 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.
** Income before income taxes 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
8.19
12.44
0.48
10.49
2.83
7.07
2.25
8.25
2.92
9.13
$
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.
65
Realized Refining Margins
Year Ended December 31, 2016
Income (loss) before income taxes
Plus:
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
Millions of Dollars, Except as Indicated
Atlantic
Basin/
Europe
Gulf
Coast
Central
Corridor
West
Coast Worldwide
$
187
69
367
(188)
435
58
200
64
817
8
(11)
55
—
(32)
5
30
1,381
$
73
234
51
1,234
(50)
3
42
106
31
465
(122)
(6)
(4)
705
(70)
—
16
—
1,556
—
—
11
—
1,599
80
230
49
979
—
(2)
—
—
—
8
—
1,156
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
Income (loss) before income taxes 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.
** Income (loss) before income taxes 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
(1.49)
9.15
0.85
6.26
3.74
8.70
0.24
5.49
0.60
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.
66
Marketing
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. The realized marketing fuel margins are
adjusted to exclude those items that are not representative of the underlying operating performance of a period, which we
call “special items.” The realized marketing fuel margins are converted to a per-barrel basis by dividing them by sales
volumes measured on a barrel basis. We believe realized 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 realized marketing fuel margin
per barrel is the marketing business’ “income before income taxes per barrel.” Realized 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 income before income taxes, such as general and administrative expenses. Because realized marketing
fuel margin per barrel excludes these items, and because realized 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
income before income taxes to realized marketing fuel margins:
Realized Marketing Fuel Margins
Income before income taxes
Plus:
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
Special items:
Certain tax impacts
Marketing margins
Less: margin for non-fuel related sales
Realized marketing fuel margins
Millions of Dollars, Except as Indicated
U.S.
International
2018
2017
2016
2018
2017
2016
$
843
628
804
505
217
252
(2)
13
763
(8)
(379)
—
(100)
1,130
—
1,130
$
5,481
14
751
(5)
(5,815)
(15)
—
1,039
—
1,039
5,187
12
708
(4)
(5,558)
—
—
1,149
—
1,149
2
71
280
(91)
(32)
2
—
737
44
693
7,579
67
264
(83)
(7,594)
2
—
452
42
410
8,132
63
259
(75)
(8,157)
3
—
477
45
432
Total fuel sales volumes (thousands of barrels)
697,696
703,928
699,111
100,949
97,346
106,574
Income before income taxes per barrel (dollars
per barrel)
Realized marketing fuel margins (dollars per
1.62
barrel)**
* Includes excise taxes on sales of refined petroleum products for periods prior to our adoption of ASU No. 2014-09 on January 1, 2018. See Note 2—
Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for further information on our adoption of this ASU. Other
operating revenues also includes other non-fuel revenues.
0.89
5.00
1.64
1.21
2.23
1.48
4.21
6.87
1.15
$
2.36
4.05
** 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.
67
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 Executive Officer and Chief Financial Officer monitor risks
resulting from foreign currency exchange rates, interest rates and commodity prices.
Commodity Price Risk
We sell into and receive supply from the worldwide crude oil, refined petroleum product, 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 convert our exposure from fixed-price sales
contracts, often specified in contracts with refined petroleum 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:
• Balance physical systems or to meet our refinery requirements and marketing demand. In addition to cash
settlement prior to contract expiration, exchange-traded futures contracts may be settled by physical delivery of the
commodity.
• Manage the risk to our cash flows from price exposures on specific crude oil, refined petroleum 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, 2018, 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, 2018 and 2017, was immaterial to our
cash flows and net income. The VaR for instruments held for purposes other than trading at December 31, 2018 and 2017,
was also immaterial to our cash flows and net income.
68
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 2018
2019
2020
2021
2022
2023
Remaining years
Total
Fair value
Expected Maturity Date
Year-End 2017
2018
2019
2020
2021
2022
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
—
7,576
9,876
9,727
—% $
2.65
—
4.30
—
4.69
$
$
3.65%
3.21
3.23
—
—
—
50
525
625
—
—
—
1,200
1,200
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
$
$
$
$
$
$
For additional information about our use of derivative instruments, see Note 15—Derivatives and Financial Instruments,
in the Notes to Consolidated Financial Statements.
69
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, refined petroleum product 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 chemical products.
Lack of, or disruptions in, adequate and reliable transportation for our NGL, crude oil, natural gas and refined
petroleum products.
The level and success of drilling and quality of production volumes around our Midstream assets.
Our inability to timely obtain or maintain permits, including those necessary for capital projects.
Our inability to 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
petroleum products 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 petroleum 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 petroleum products.
The factors generally described in Item 1A.—Risk Factors in this report.
70
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, 2018, 2017 and 2016
Consolidated Statement of Comprehensive Income for the years ended December 31, 2018, 2017 and 2016
Consolidated Balance Sheet at December 31, 2018 and 2017
Consolidated Statement of Cash Flows for the years ended December 31, 2018, 2017 and 2016
Consolidated Statement of Changes in Equity for the years ended December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
Supplementary Information
Selected Quarterly Financial Data (Unaudited)
Page
72
73
75
76
77
78
79
81
138
71
Report of Management
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,
2018. 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, 2018.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December
31, 2018, and their report is included herein.
/s/ Greg C. Garland
/s/ Kevin J. Mitchell
Greg C. Garland
Chairman and
Chief Executive Officer
Date: February 22, 2019
Kevin J. Mitchell
Executive Vice President, Finance and
Chief Financial Officer
72
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Phillips 66
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheet of Phillips 66 (the Company) as of December 31, 2018
and 2017, 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, 2018, 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, 2018 and 2017, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended December 31, 2018, 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, 2018, 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 22, 2019 expressed an unqualified opinion
thereon.
Adoption of ASU No. 2014-09
As discussed in Note 2 to the consolidated financial statements, the Company adopted ASU No. 2014-09, “Revenue from
Contracts with Customers (Topic 606)” effective January 1, 2018. As a result, for the year ended December 31, 2018, the
Company changed its presentation of excise taxes collected from customers on sales of refined petroleum products.
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 22, 2019
We have served as the Company’s auditor since 2011.
73
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Phillips 66
Opinion on Internal Control over Financial Reporting
We have audited Phillips 66’s internal control over financial reporting as of December 31, 2018, 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, 2018, 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, 2018 and 2017, 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, 2018, and the related notes and our report dated February 22, 2019 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.
/s/ Ernst & Young LLP
Houston, Texas
February 22, 2019
74
Consolidated Statement of Income
Phillips 66
Millions of Dollars
2018
2017
$
111,461
2,676
19
61
114,217
97,930
4,880
1,677
1,356
8
425
23
504
(31)
106,772
7,445
1,572
5,873
278
5,595
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
2016
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
11.87
11.80
9.90
9.85
2.94
2.92
470,708
474,047
515,090
518,508
527,531
530,066
$
13,054
13,381
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
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
Weighted-Average Common Shares Outstanding (thousands)
Basic
Diluted
* Includes excise taxes on sales of refined petroleum products for periods prior to the
adoption of Accounting Standards Update No. 2014-09 on January 1, 2018:
See Notes to Consolidated Financial Statements.
$
$
75
Consolidated Statement of Comprehensive Income
Phillips 66
Millions of Dollars
Years Ended December 31
Net Income
Other comprehensive income (loss)
Defined benefit plans
2018
$
5,873
Net actuarial loss arising during the period
Amortization to income of net actuarial loss, net prior service
cost (credit) and settlements
Curtailment gain
Plans sponsored by equity affiliates
Income taxes on defined benefit plans
Defined benefit plans, net of income taxes
Foreign currency translation adjustments
Income taxes on foreign currency translation adjustments
Foreign currency translation adjustments, net of income taxes
Cash flow hedges
Income taxes on hedging activities
Hedging activities, net of income taxes
Other Comprehensive Income (Loss), Net of Income Taxes
Comprehensive Income
Less: comprehensive income attributable to noncontrolling interests
Comprehensive Income Attributable to Phillips 66
$
See Notes to Consolidated Financial Statements.
(16)
148
5
22
(33)
126
(205)
3
(202)
1
—
1
(75)
5,798
278
5,520
2017
5,248
(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
76
Consolidated Balance Sheet
At December 31
Assets
Cash and cash equivalents
Accounts and notes receivable (net of allowances of $22 million in 2018
and $29 million in 2017)
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 (2018—645,691,761 shares; 2017—643,835,464 shares)
Par value
Capital in excess of par
Treasury stock (at cost: 2018—189,526,331 shares; 2017—141,565,145 shares)
Retained earnings
Accumulated other comprehensive loss
Total Stockholders’ Equity
Noncontrolling interests
Total Equity
Total Liabilities and Equity
See Notes to Consolidated Financial Statements.
77
Phillips 66
Millions of Dollars
2018
2017
$
3,019
5,414
759
3,543
474
13,209
14,421
22,018
3,270
869
515
54,302
6,113
473
67
1,116
724
442
8,935
11,093
624
5,275
867
355
27,149
6
19,873
(15,023)
20,489
(692)
24,653
2,500
27,153
54,302
$
$
$
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
Consolidated Statement of Cash Flows
Phillips 66
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
2018
$
5,873
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
Accounts and notes receivable
Inventories
Prepaid expenses and other current assets
Accounts payable
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.
$
78
1,356
8
23
252
221
(19)
—
132
1,320
(202)
(113)
(1,546)
268
7,573
(2,639)
57
(1)
—
—
112
(2,471)
2,184
(1,144)
39
(4,645)
(1,436)
(207)
128
(86)
(5,167)
(35)
(100)
3,119
3,019
2017
5,248
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
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, 2015
Net income
Other comprehensive loss
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
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
Cumulative effect of accounting
changes
Net income
Other comprehensive loss
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, 2018
$
$
6
—
—
—
—
—
—
—
6
—
—
—
—
—
—
—
6
—
—
—
—
—
—
—
—
6
19,145
—
—
—
— (1,042)
—
106
(7,746)
12,348
—
1,555
—
—
— (1,282)
—
(13)
308
—
—
—
19,559
—
—
—
— (1,590)
—
72
—
—
12,608
(8,788)
5,106
—
—
—
— (1,395)
—
(13)
137
—
—
—
19,768
—
(10,378)
—
16,306
—
—
—
—
— (4,645)
—
63
36
—
5,595
—
—
—
— (1,436)
—
(12)
42
—
—
—
19,873
—
(15,023)
—
20,489
(653)
—
(342)
—
—
—
—
—
(995)
—
378
—
—
—
—
—
(617)
—
—
(75)
—
—
—
—
—
(692)
838
89
—
—
—
—
483
(75)
1,335
142
—
—
—
—
986
(120)
2,343
13
278
—
—
—
—
73
(207)
2,500
Total
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
49
5,873
(75)
(1,436)
(4,645)
51
115
(207)
27,153
79
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
Repurchase of common stock
Shares issued—share-based compensation
December 31, 2018
Shares in Thousands
Common Stock Issued
Treasury Stock
109,926
12,901
—
122,827
18,738
—
141,565
47,961
—
189,526
639,336
—
2,258
641,594
—
2,241
643,835
—
1,857
645,692
Dollars
Years Ended December 31
Dividends Paid Per Share of Common Stock
2016
2017
2018
See Notes to Consolidated Financial Statements.
$
2.45
2.73
3.10
80
Notes to Consolidated Financial Statements
Phillips 66
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 (VIEs) where we are the primary
beneficiary. Undivided interests in pipelines, natural gas plants and terminals are consolidated on a
proportionate basis. See Note 27—Phillips 66 Partners LP, for further discussion on our significant consolidated
VIE.
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, including VIEs of which we are not the
primary beneficiary. Other securities and investments are generally carried at fair value, or cost less
impairments, if any, adjusted up or down for price changes in similar financial instruments issued by the
investee, when and if observed. See Note 7—Investments, Loans and Long-Term Receivables, for further
discussion on our significant nonconsolidated VIEs.
Recasted Financial Information—Certain prior period financial information has been recasted to reflect the
current year’s presentation.
Use of Estimates—The preparation of financial statements in conformity with generally accepted accounting
principles in the United States (GAAP) requires management to make estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and
liabilities. Actual results could differ from these estimates.
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.
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.
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.
Fair Value Measurements—We categorize assets and liabilities measured at fair value into one of three
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.
81
Derivative Instruments—Derivative instruments are recorded on the balance sheet at fair value. We have
master netting agreements with our exchange-cleared instrument counterparties and certain of our counterparties
to other commodity instrument contracts (e.g., physical commodity forward contracts). We have elected to net
derivative assets and liabilities with the same counterparty on the balance sheet if the legal right of offset exists
and certain other criteria are met. We also net collateral payables and 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 cash flow hedges are recognized in other comprehensive income (loss) and appear on the
balance sheet in accumulated other comprehensive income (loss) until the hedged transactions are 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.
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.
Impairment of Investments in Nonconsolidated Entities—Investments in nonconsolidated entities accounted
for under the equity method 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
determined 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.
Depreciation and Amortization—Depreciation and amortization of properties, plants and equipment (PP&E)
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).
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.
Impairment of 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 expected future pre-tax cash flows of an asset group 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 and the write down is reported in the
“Impairments” line on our consolidated statement of income in the period in which the impairment
determination 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 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
82
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.
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.
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.
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 the
indefinite useful life classification. 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.
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
83
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.
Treasury Stock—We record treasury stock purchases at cost, which includes incremental direct transaction
costs. Amounts are recorded as reductions of stockholders’ equity on the consolidated balance sheet.
Revenue Recognition—Our revenues are primarily associated with sales of refined petroleum products, crude
oil and natural gas liquids (NGL). Each gallon, or other unit of measure of product, is separately identifiable and
represents a distinct performance obligation to which a transaction price is allocated. The transaction prices of
our contracts with customers are either fixed or variable, with variable pricing based upon various market
indices. For our contracts that include variable consideration, we utilize the variable consideration allocation
exception, whereby the variable consideration is only allocated to the performance obligations that are satisfied
during the period. The related revenue is recognized at a point in time when control passes to the customer,
which is when title and the risk of ownership passes to the customer and physical delivery of goods occurs,
either immediately or within a fixed delivery schedule that is reasonable and customary in the industry. The
payment terms with our customers vary based on the product or service provided, but usually are 30 days or less.
Revenues associated with pipeline transportation services are recognized at a point in time when the volumes are
delivered based on contractual rates. Revenues associated with terminaling and storage services are recognized
over time as the services are performed based on throughput volume or capacity utilization at contractual rates.
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).
Taxes Collected from Customers and Remitted to Governmental Authorities—Effective for reporting
periods ending after our adoption of Financial Accounting Standards Board (FASB) Accounting Standards
Update (ASU) No. 2014-09 on January 1, 2018, excise taxes on sales of refined petroleum products charged to
our customers are presented net of taxes on sales of refined petroleum products owed to governmental authorities
in the “Taxes other than income taxes” line on our consolidated statement of income. For reporting periods
ending prior to January 1, 2018, excise taxes on sales of refined petroleum products charged to our customers are
presented in the “Sales and other operating revenues” line on our consolidated statement of income, and excise
taxes on sales of refined petroleum products owed to governmental authorities are presented in the “Taxes other
than income taxes” line on our consolidated statement of income. See Note 2—Changes in Accounting
Principles, for more information regarding our adoption of this ASU.
Other sales and value-added taxes are recorded net in the “Taxes other than income taxes” line on our
consolidated statement of income.
Shipping and Handling Costs—We have elected to account for shipping and handling costs as fulfillment
activities and include these activities 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.”
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.
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 have elected
to recognize forfeitures of awards when they occur.
84
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.
Note 2—Changes in Accounting Principles
Effective January 1, 2018, we adopted ASU No. 2017-05, “Other Income—Gains and Losses from the Derecognition of
Nonfinancial Assets (Subtopic 610-20),” which 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 eliminated the use of
carryover basis for most nonmonetary exchanges, including contributions of assets to equity-method joint ventures, and
could result in the entity recognizing a gain or loss on the sale or transfer of nonfinancial assets. At the time of adoption,
there was no impact on our consolidated financial statements from this ASU.
Effective January 1, 2018, we adopted 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 screen is
met and the transaction is not considered an acquisition of a business. If the screen is not met, 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 future transactions
accounted for as business acquisitions. At the time of adoption, there was no impact on our consolidated financial
statements from this ASU.
Effective January 1, 2018, we adopted ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Asset Transfers of
Assets Other Than Inventory.” This ASU requires the income tax consequences of an intra-entity transfer of an asset,
other than inventory, to be recognized when the transfer occurs. At the time of adoption, this ASU did not have a
material impact on our consolidated financial statements.
Effective January 1, 2018, we adopted ASU No. 2016-01, “Financial Instruments—Overall (Subtopic 825-10):
Recognition and Measurement of Financial Assets and Financial Liabilities.” The majority of this ASU’s provisions
amend only the presentation or disclosures of financial instruments; however, one provision could also affect net income.
Equity investments carried under the cost method or the lower of cost or fair value method of accounting, in accordance
with previous GAAP, will have to be carried at fair value 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. At the time of adoption, this ASU did not have a material impact on our consolidated financial
statements.
85
Effective January 1, 2018, we adopted ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” using
the modified retrospective transition method applied to all contracts. Under the new guidance, recognition of revenue
involves a multiple step approach including (i) identifying the contract, (ii) identifying the separate performance
obligations, (iii) determining the transaction price, (iv) allocating the price to the performance obligations and (v)
recognizing the revenue as the obligations are satisfied. Additional disclosures are required to enable users of financial
statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts
with customers.
We recorded noncash cumulative effect adjustments to our opening total equity balance as of January 1, 2018, to increase
retained earnings by $35 million, net of $11 million of income taxes, and noncontrolling interests by $13 million. These
adjustments primarily reflected amounts recorded by our equity-method investees related to contracts that contain tier-
pricing and minimum volume commitments with recovery provisions.
In addition, prospectively from January 1, 2018, our presentation of excise taxes on sales of refined petroleum products
changed to a net basis from a gross basis. As a result, the “Sales and other operating revenues” and “Taxes other than
income taxes” lines on our consolidated statement of income for the year ended December 31, 2018, are not presented on
a comparable basis to the years ended December 31, 2017 and 2016. See Note 1—Summary of Significant Accounting
Policies, for more information on our presentation of excise taxes on sales of refined petroleum products.
Note 3—Sales and Other Operating Revenues
Disaggregated Revenues
The following tables present our disaggregated sales and other operating revenues:
Product Line and Services
Refined petroleum products
Crude oil resales
NGL
Services and other
Consolidated sales and other operating revenues
Geographic Location**
United States
United Kingdom
Germany
Other foreign countries
Consolidated sales and other operating revenues
Millions of Dollars
2017*
2018
$
$
$
$
87,967
16,419
6,161
914
111,461
86,401
11,054
4,352
9,654
111,461
85,405
11,808
4,670
471
102,354
75,684
10,626
6,692
9,352
102,354
2016*
73,385
7,594
3,107
193
84,279
59,742
9,895
6,128
8,514
84,279
* Sales and other operating revenues for the years ended December 31, 2017 and 2016, are presented in accordance with accounting standards in effect prior
to our adoption of ASU No. 2014-09 on January 1, 2018. See Note 2—Changes in Accounting Principles, for further discussion regarding our adoption of
ASU No. 2014-09.
** Sales and other operating revenues are attributable to countries based on the location of the operations generating the revenues.
86
Contract-Related Assets and Liabilities
At December 31, 2018, and January 1, 2018, receivables from contracts with customers were $4,993 million and $6,186
million, respectively. Significant non-customer balances, such as buy/sell receivables and excise tax receivables, were
excluded from these amounts.
Our contract-related assets also include payments we make to our marketing customers related to incentive programs. An
incentive payment is initially recognized as an asset and subsequently amortized as a reduction to revenue over the
contract term, which generally ranges from 5 to 15 years. At December 31, 2018, and January 1, 2018, our asset balances
related to such payments were $248 million and $208 million, respectively.
Our contract liabilities represent advances from our customers prior to product or service delivery. At December 31,
2018, and January 1, 2018, contract liabilities were not material.
Remaining Performance Obligations
Most of our contracts with customers are spot contracts or term contracts with only variable consideration. We do not
disclose remaining performance obligations for these contracts as the expected duration is one year or less or because the
variable consideration has been allocated entirely to an unsatisfied performance obligation. We also have certain
contracts in our Midstream segment that include minimum volume commitments with fixed pricing, which mostly expire
by 2021. At December 31, 2018, the remaining performance obligations related to these minimum volume commitment
contracts were not material.
Note 4—Inventories
Inventories at December 31 consisted of the following:
Crude oil and petroleum products
Materials and supplies
Millions of Dollars
2018
3,238
305
3,543
$
$
2017
3,106
289
3,395
Inventories valued on the LIFO basis totaled $3,123 million and $2,980 million at December 31, 2018 and 2017,
respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately
$2.9 billion and $4.3 billion at December 31, 2018 and 2017, respectively.
LIFO inventory liquidations did not have a material impact on net income for the years ended December 31, 2018 and
2017. For the year ended December 31, 2016, LIFO inventory liquidations, excluding the disposition of the Whitegate
Refinery, decreased net income by approximately $68 million.
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.
87
Note 5—Business Combinations
Merey Sweeny LLC, successor to Merey Sweeny, L.P. (both referred to herein as Merey Sweeny), owns a delayed coker
and related facilities at the Sweeny Refinery. In February 2017, we began accounting for Merey Sweeny as a
consolidated subsidiary because the exercise of a call right triggered by certain defaults by the co-venturer, Petróleos de
Venezuela S.A. (PDVSA), with respect to supply of crude oil to the Sweeny Refinery ceased to be subject to legal
challenge. The purchase price for PDVSA’s 50 percent ownership interest was determined by a contractual formula. As
the distributions PDVSA received from Merey Sweeny exceeded the amounts it contributed to Merey Sweeny, the
contractual formula required no cash consideration for the acquisition.
Based on a third-party appraisal of the fair value of Merey Sweeny’s net assets, utilizing discounted cash flows and
replacement costs, the acquisition of PDVSA’s 50 percent interest resulted in the recognition of 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 Merey Sweeny 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 Merey Sweeny and net
intercompany payables. Our acquisition accounting was finalized in the first quarter of 2017.
The results of Merey Sweeny were included in our Refining segment until October 2017, when we contributed our 100
percent interest in Merey Sweeny to Phillips 66 Partners LP (Phillips 66 Partners), which is included in our Midstream
segment.
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.
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Note 7—Investments, Loans and Long-Term Receivables
Components of investments and long-term receivables at December 31 were:
Equity investments
Other investments
Loans and long-term receivables
Millions of Dollars
2018
14,218
106
97
14,421
$
$
2017
13,733
114
94
13,941
Equity Investments
Significant affiliated companies accounted for under the equity method, including nonconsolidated VIEs, at December
31, 2018 and 2017, included:
• Chevron Phillips Chemical Company LLC (CPChem)—50-percent-owned joint venture that 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 petroleum 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, 2018 and 2017, the book value of our investment in CPChem was $6,233 million and $6,222
million, respectively.
• DCP Midstream, LLC (DCP Midstream)—50-percent-owned joint venture that owns and operates gas plants,
gathering systems, storage facilities and fractionation plants, through its subsidiary DCP Midstream, LP (DCP
Partners). DCP Midstream markets a portion of its NGL to us and our equity affiliates under existing contracts.
At December 31, 2018 and 2017, the book value of our investment in DCP Midstream was $2,240 million and
$2,227 million, respectively.
• WRB Refining LP (WRB)—50-percent-owned joint venture that owns the Wood River and Borger refineries
located in Roxana, Illinois, and Borger, Texas, respectively, for which we are the operator and managing partner.
At December 31, 2018 and 2017, the book value of our investment in WRB was $2,108 million and $2,269
million, respectively.
We have a basis difference for our investment in WRB because the carrying value of our investment is lower than
our share of WRB’s recorded net assets. This basis difference was primarily the result of our contribution of these
refineries to WRB. On the contribution closing date, a basis difference was created because the fair value of the
contributed assets recorded by WRB exceeded our historical book value. The contribution-related basis difference
is primarily being amortized and recognized as a benefit to equity earnings evenly over a period of 26 years,
which was the estimated remaining useful life of the refineries’ PP&E at the contribution closing date. At
December 31, 2018, the aggregate remaining basis difference for this investment was $2,610 million. Equity
earnings for the years ended December 31, 2018, 2017 and 2016, were increased by $177 million, $186 million
and $185 million, respectively, due to the amortization of our aggregate basis difference.
• Dakota Access, LLC (Dakota Access) and Energy Transfer Crude Oil Company, LLC (ETCO)—Phillips 66
Partners’ two 25-percent-owned joint ventures. 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. These two pipeline systems collectively
form the Bakken Pipeline system, which is operated by a co-venturer. The Bakken Pipeline system went into
service in June 2017. At December 31, 2018 and 2017, the aggregate book value of Phillips 66 Partners’
investments in Dakota Access and ETCO was $608 million and $621 million, respectively.
89
• DCP Sand Hills Pipeline, LLC (Sand Hills)—Phillips 66 Partners’ 33-percent-owned joint venture that owns an
NGL pipeline system that extends from the Permian Basin and Eagle Ford to facilities on the Texas Gulf Coast
and to the Mont Belvieu, Texas market hub. The Sand Hills Pipeline system is operated by DCP Partners. At
December 31, 2018 and 2017, the book value of Phillips 66 Partners’ investment in Sand Hills was $601 million
and $515 million, respectively.
• Rockies Express Pipeline LLC (REX)—25-percent-owned joint venture that owns a natural gas pipeline system
that extends from Wyoming and Colorado to Ohio with a bi-directional section that extends from Ohio to Illinois.
The REX Pipeline system is operated by our co-venturer. In July 2018, we contributed $138 million to REX to
cover our 25 percent share of a $550 million debt repayment. Our capital contribution was included in the
“Capital expenditures and investments” line on our consolidated statement of cash flows. At December 31, 2018
and 2017, the book value of our investment in REX was $600 million and $445 million, respectively.
We have a basis difference for our investment in REX because the carrying value of our investment is lower than
our share of REX’s recorded net assets. This basis difference was created by historical impairment charges we
recorded for this investment. This basis difference is being amortized and recognized as a benefit to equity
earnings evenly over a period of 25 years, which was the estimated remaining useful life of REX’s PP&E when
the impairment charges were recorded. At December 31, 2018, the remaining basis difference for this investment
was $357 million. Equity earnings for the years ended December 31, 2018, 2017 and 2016, were each increased
by approximately $20 million due to the amortization of our basis difference.
• Gray Oak Pipeline, LLC (Gray Oak)—Phillips 66 Partners’ consolidated subsidiary, Gray Oak Holdings LLC
(Holdings LLC), owned a 75 percent interest in a joint venture formed in 2018 to develop and construct the Gray
Oak Pipeline system which, upon completion, will provide crude oil transportation from the Permian Basin and
Eagle Ford to destinations in the Corpus Christi and Freeport markets on the Texas Gulf Coast. The pipeline
system is expected to be placed in service by the end of 2019.
Phillips 66 Partners accounts for the investment in Gray Oak under the equity method because it does not have
sufficient voting rights over key governance provisions to assert control over Gray Oak. Gray Oak is considered
a VIE because it does not have sufficient equity at risk to fully fund the construction of all assets required for
principal operations. Phillips 66 Partners has determined it is not the primary beneficiary because it and its co-
venturer jointly direct the activities of Gray Oak that most significantly impact economic performance. At
December 31, 2018, Phillips 66 Partners’ maximum exposure to loss was $373 million, which represented the
book value of the investment in Gray Oak of $288 million and guaranteed purchase obligations of $85 million.
In February 2019, another party exercised its option to acquire a 10 percent interest in Gray Oak, which reduced
Holdings LLC’s ownership interest to 65 percent.
See Note 27—Phillips 66 Partners LP, for additional information regarding Phillips 66 Partners’ ownership in
Holdings LLC and Gray Oak.
• Bayou Bridge Pipeline, LLC (Bayou Bridge)—Phillips 66 Partners’ 40-percent-owned joint venture that owns a
pipeline that delivers crude oil from Nederland, Texas, to Lake Charles, Louisiana. The Bayou Bridge Pipeline is
operated by our co-venturer. An extension of the pipeline from Lake Charles to St. James, Louisiana, is expected
to be in service in March 2019. At December 31, 2018 and 2017, the book value of our investment in Bayou
Bridge was $277 million and $173 million, respectively.
• DCP Southern Hills Pipeline, LLC (Southern Hills)—Phillips 66 Partners’ 33-percent-owned joint venture that
owns an NGL pipeline system that extends from the Midcontinent region to the Mont Belvieu, Texas market hub.
The Southern Hills Pipeline system is operated by DCP Partners. At December 31, 2018 and 2017, the book value
of Phillips 66 Partners’ investment in Southern Hills was $206 million and $209 million, respectively.
• OnCue Holdings, LLC (OnCue)—50-percent-owned joint venture that owns and operates retail convenience
stores. We fully guaranteed various debt agreements of OnCue, and our co-venturer did not participate in the
guarantees. This entity is considered a VIE because our debt guarantees resulted in OnCue not being exposed to
all potential losses. We have determined we are not the primary beneficiary because we do not have the power to
90
direct the activities that most significantly impact economic performance. At December 31, 2018, our maximum
exposure to loss was $122 million, which represented the book value of our investment in OnCue of $69 million
and guaranteed debt obligations of $53 million.
Total distributions received from affiliates were $2,942 million, $1,270 million, and $616 million for the years ended
December 31, 2018, 2017 and 2016, respectively. In addition, at December 31, 2018, retained earnings included
approximately $2,285 million related to the undistributed earnings of affiliated companies.
Summarized 100 percent financial information for all affiliated companies accounted for under the equity method, on a
combined basis, was:
Revenues
Income before income taxes
Net income
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Noncontrolling interests
Millions of Dollars
2018
2017
2016
$
43,627
6,066
5,926
6,791
52,649
8,047
10,695
2,550
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
Related Party Loans and Advances
In 2017, we received payment of the $250 million outstanding sponsor loans to the Dakota Access and ETCO joint
ventures. We also received payment of the $75 million partner loan we made to WRB in 2016. These cash inflows,
totaling $325 million, are 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:
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Millions of Dollars
Net
PP&E
7,563
—
13,109
745
601
22,018
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
9,663
—
22,640
1,671
1,223
35,197
$
$
2018
Accum.
D&A
2,100
—
9,531
926
622
13,179
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Note 9—Goodwill and Intangibles
Goodwill
The carrying amount of goodwill by segment at December 31 was:
Balance at January 1, 2017
Adjustments
Balance at December 31, 2017
Adjustments
Balance at December 31, 2018
Millions of Dollars
Midstream
Refining
Marketing and
Specialties
$
$
626
—
626
—
626
1,805
—
1,805
—
1,805
839
—
839
—
839
Total
3,270
—
3,270
—
3,270
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
2018
2017
$
$
503
250
—
753
503
252
1
756
The net book value of our amortized intangible assets was $116 million and $120 million at December 31, 2018 and
2017, respectively. Acquisitions of amortized intangible assets were not material in 2018 and 2017. For the years ended
December 31, 2018, 2017 and 2016, amortization expense was $14 million, $21 million and $18 million, respectively,
and is expected to be less than $20 million per year in future years.
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Note 10—Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
Millions of Dollars
2018
2017
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.”
$
$
261
447
708
(84)
624
268
458
726
(85)
641
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 the years ended December 31, 2018 and 2017, 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
Foreign currency translation
Balance at December 31
Millions of Dollars
2018
2017
$
$
268
10
3
(15)
(5)
261
244
10
17
(14)
11
268
Accrued Environmental Costs
For the year ended December 31, 2018, the $11 million decrease in total accrued environmental costs 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, 2018, $224 million was primarily related to cleanup at
domestic refineries and underground storage tanks at U.S. service stations; $167 million was associated with nonoperator
sites; and $56 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 discount rate of approximately 5 percent. At December 31, 2018, the accrued
balance for acquired environmental liabilities was $261 million. The expected future undiscounted payments related to
the portion of the accrued environmental costs that have been discounted are: $24 million in 2019, $41 million in 2020,
$23 million in 2021, $22 million in 2022, $15 million in 2023, and $206 million in the aggregate for all years after 2023.
93
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
2018
2017
2016
Basic Diluted
Basic Diluted
Basic Diluted
$ 5,595
(6)
$ 5,589
5,595
—
5,595
5,106
(6)
5,100
5,106
—
5,106
1,555
(6)
1,549
1,555
(5)
1,550
Weighted-average common shares outstanding
(thousands):
Effect of share-based compensation
Weighted-average common shares outstanding—EPS
467,483 470,708
3,339
470,708 474,047
3,225
511,268 515,090
3,418
515,090 518,508
3,822
523,250 527,531
2,535
527,531 530,066
4,281
Earnings Per Share of Common Stock (dollars)
$ 11.87
11.80
9.90
9.85
2.94
2.92
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Note 12—Debt
Short-term and long-term debt at December 31 was:
Phillips 66
4.300% Senior Notes due April 2022
3.900% Senior Notes due March 2028
4.650% Senior Notes due November 2034
5.875% Senior Notes due May 2042
4.875% Senior Notes due November 2044
Floating-rate notes due April 2019 at 2.009% at year-end 2017
Floating-rate notes due April 2020 at 3.186% and 2.109% at year-end 2018 and
$
2017, respectively
Term loan due April 2020 at 3.422% and 2.469% at year-end 2018 and 2017,
respectively
Floating-rate Senior Notes due February 2021 at 3.289% at year-end 2018
Other
Phillips 66 Partners
2.646% Senior Notes due February 2020
3.605% Senior Notes due February 2025
3.550% Senior Notes due October 2026
3.750% Senior Notes due March 2028
4.680% Senior Notes due February 2045
4.900% Senior Notes due October 2046
Tax-exempt bonds due April 2020 and April 2021 at 1.885% and 1.935% at
year-end 2018 and 2017, respectively
Revolving credit facility due January 2019 and October 2021 at weighted-
average rate of 3.669% at year-end 2018
Debt at face value
Capitalized leases
Net unamortized discounts and debt issuance costs
Total debt
Short-term debt
Long-term debt
$
Millions of Dollars
2018
2,000
800
1,000
1,500
1,700
—
300
200
500
1
300
500
500
500
450
625
75
125
11,076
184
(100)
11,160
(67)
11,093
2017
2,000
—
1,000
1,500
1,500
300
300
450
—
1
300
500
500
500
450
625
100
—
10,026
192
(108)
10,110
(41)
10,069
Maturities of borrowings outstanding at December 31, 2018, inclusive of net unamortized discounts and debt issuance
costs, for each of the years from 2019 through 2023 are $67 million, $836 million, $636 million, $2,005 million and $11
million, respectively.
95
Debt Issuances
2018 Issuances
On March 1, 2018, Phillips 66 closed on a public offering of $1,500 million aggregate principal amount of unsecured
notes consisting of:
•
•
$500 million of floating-rate Senior Notes due February 2021. Interest on these notes is equal to the three-month
London Interbank Offered Rate (LIBOR) plus 0.60% per annum and is payable quarterly in arrears on February
26, May 26, August 26 and November 26, beginning on May 29, 2018.
$800 million of 3.900% Senior Notes due March 2028. Interest on these notes is payable semiannually on
March 15 and September 15 of each year, beginning on September 15, 2018.
• An additional $200 million of our 4.875% Senior Notes due November 2044. Interest on these notes is payable
semiannually on May 15 and November 15 of each year, beginning on May 15, 2018.
These notes are guaranteed by Phillips 66 Company, a wholly owned subsidiary. Phillips 66 used the net proceeds from
the issuance of these notes and cash on hand to repay commercial paper borrowings during the three months ended
March 31, 2018, and for general corporate purposes. The commercial paper borrowings during the three months ended
March 31, 2018, were primarily used to repurchase shares of our common stock. See Note 17—Equity, for additional
information.
2017 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 March 2028 and $150 million of 4.680% Senior Notes due
February 2045. Interest on the 3.750% Senior Notes due March 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 February 2045 is
payable semiannually in arrears on February 15 and August 15 of each year.
In April 2017, Phillips 66 completed a private offering of $600 million aggregate principal amount of unsecured notes,
consisting of $300 million of floating-rate notes due April 2019 (2019 Notes) and $300 million of floating-rate notes due
April 2020 (2020 Notes). Interest on these 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. The notes are guaranteed by Phillips 66
Company, a wholly 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 due April 2018 and a $450 million three-year facility due April 2020.
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 Merey Sweeny, Phillips 66 assumed $135 million of 8.850% 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 Merey Sweeny.
Debt Repayments
2018 Repayments
In December 2018, Phillips 66 repaid the $300 million floating-rate notes due April 2019.
In June 2018, Phillips 66 repaid $250 million of the $450 million outstanding under its three-year term loan facility due
April 2020.
96
2017 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, Phillips 66 repaid $1,500 million of 2.950% Senior Notes upon maturity with the funding from the April
2017 debt issuances discussed above. In addition, Phillips 66 repaid $135 million of Merey Sweeny 8.850% Senior
Notes due in 2019 originally recorded in February 2017 as part of the consolidation of Merey Sweeny. See Note 5—
Business Combinations, for additional information regarding the consolidation of Merey Sweeny.
In 2017, Phillips 66 Partners repaid the $210 million of borrowings outstanding under its $750 million revolving credit
facility at December 31, 2016.
Credit Facilities and Commercial Paper
Phillips 66 has a $5 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 are 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 Financial Services LLC and Moody’s Investors Service, Inc. The
facility also provides for customary fees, including administrative agent fees and commitment fees. At December 31,
2018 and 2017, no amount had been drawn under this revolving credit agreement.
Phillips 66 has a $5 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, 2018 and 2017,
no borrowings were outstanding under the 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 and contains covenants that are usual and customary for an
agreement of this type for comparable commercial borrowers. At Phillips 66 Partners’ option, outstanding borrowings
under this facility bear interest at either i) the Eurodollar rate plus a margin based on its credit rating; or ii) the base rate
(as described in the facility agreement) plus a margin based on its credit rating. Eurodollar rate borrowings are due on
the facility’s termination date, while base rate borrowings are due the earlier of the facility’s termination date or the
fourteenth business day after such borrowings were made. At December 31, 2018, Phillips 66 Partners had borrowings of
$125 million outstanding under this facility. There were no borrowings outstanding under this facility at December 31,
2017.
Note 13—Guarantees
At December 31, 2018, 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 guarantees and expect
future performance to be either immaterial or have only a remote chance of occurrence.
Guarantees of Joint Venture Obligations
At December 31, 2018, we had guarantees outstanding for our portion of certain joint venture debt and purchase
obligations, which have remaining terms of up to seven years. The maximum potential amount of future payments to
third parties under these guarantees was approximately $304 million. Payment would be required if a joint venture
defaults on its obligations.
97
Residual Value 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 term ends in June 2021 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 $300 million, which have remaining terms of up to five years. For the years ended December 31, 2018, 2017 and
2016, we recognized incremental operating lease rental expense of $20 million, $45 million and $28 million, respectively,
for residual value deficiencies for certain railcar leases based on third-party appraisals of the railcars’ expected fair value
at the end of the lease terms. These railcar leases were amended in November 2018 and October 2017 resulting in
residual value deficiency settlement payments of $40 million and $53 million, respectively. At December 31, 2018, we
do not have any liabilities recorded for residual value deficiencies under our railcar leases.
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. At December 31,
2018 and 2017, the carrying amount of recorded indemnifications was $171 million and $193 million, respectively.
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. At December 31, 2018 and 2017,
environmental accruals for known contamination of $101 million and $104 million, respectively, were included in the
carrying amount of recorded indemnifications. These environmental accruals were primarily included in the “Asset
retirement obligations and accrued environmental costs” line on our consolidated balance sheet. For additional
information about environmental liabilities, see Note 14—Contingencies and Commitments.
Indemnification and Release Agreement
In 2012, in connection with our separation from ConocoPhillips (the Separation), we entered into the Indemnification and
Release Agreement. 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.
98
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 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.
99
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, 2018, we had performance obligations secured by letters of credit and bank guarantees of $587
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. At
December 31, 2018, the estimated aggregate future payments under these agreements were $318 million per year for each
year from 2019 through 2023 and $2,280 million in the aggregate for all years after 2023. For the years ended December
31, 2018, 2017 and 2016, total payments under these agreements were $323 million, $323 million and $325 million,
respectively.
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 petroleum product, 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.
Commodity Derivative Contracts—We sell into or receive supply from the worldwide crude oil, refined petroleum
product, 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 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.
100
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 legal right of offset exists.
December 31, 2018
December 31, 2017
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
$
1,257
(1,070)
Other assets
Liabilities
Other accruals
Other liabilities and deferred credits
2
—
5
—
(23)
(7)
Total
$
1,264
(1,100)
(89)
—
—
—
(89)
98
2
(23)
(2)
75
43
7
699
—
749
(19)
(3)
(746)
(1)
(769)
—
—
21
—
21
24
4
(26)
(1)
1
At December 31, 2018 and 2017, 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
2018
2017
2016
$
$
192
(15)
(64)
113
(247)
27
(18)
(238)
(451)
29
(62)
(484)
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 twelve months was at least 98 percent at December 31, 2018 and
2017.
Commodity
Crude oil, refined petroleum products and NGL (millions of barrels)
101
Open Position
Long / (Short)
2018
2017
(17)
(11)
Interest Rate Derivative Contracts—In 2016, we entered into interest rate swaps to hedge the variability of lease
payments on our headquarters facility. These monthly lease payments 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 in April 2021. We have designated these
swaps as cash flow hedges.
The aggregate net fair value of these swaps, which is included in the “Prepaid expenses and other current assets” and
“Other assets” lines on our consolidated balance sheet, totaled $15 million and $14 million at December 31, 2018 and
2017, respectively.
We report the mark-to-market gains or losses on our interest rate swaps designated as highly effective 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 transaction affects earnings. Net realized gains and losses from settlements of the swaps
were immaterial for the years ended December 31, 2018 and 2017.
We currently estimate that pre-tax gains of $7 million will be reclassified from accumulated other comprehensive 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.
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of trade receivables and
derivative contracts.
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.
The credit risk from our 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, typically on a daily basis, until settled.
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.
The aggregate fair values of all derivative instruments with such credit-risk-related contingent features that were in a
liability position were immaterial at December 31, 2018 and 2017.
102
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 the price that would be
received to sell an asset or paid to transfer a liability (i.e., an exit price), 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, 2018, derivative assets with an
aggregate value of $246 million and derivative liabilities with an aggregate value of $246 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.
We used the following methods and assumptions to estimate the fair value of financial instruments:
• 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.
Physical commodity forward purchase and sales contracts and over-the-counter (OTC) financial swaps 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, physical commodity purchase
and sales contracts and OTC swaps 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. Physical and OTC 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 notional amounts, 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.
103
• 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 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. The following tables also
reflect the effect of netting derivative assets and liabilities with the same counterparty for which we have the legal right
of offset and collateral netting.
The carrying values and fair values by hierarchy of our financial assets and liabilities, either carried or disclosed at fair
value, including any effects of counterparty and collateral netting, were:
Millions of Dollars
December 31, 2018
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
OTC instruments
Floating-rate debt
Fixed-rate debt, excluding capital
leases
$
$
$
$
674
—
—
104
778
605
—
—
—
—
605
547
39
15
—
601
472
20
3
1,200
9,727
11,422
—
4
—
—
4
—
—
—
—
—
—
1,221
(1,075)
43
15
104
1,383
—
—
N/A
(1,075)
1,077
(1,075)
20
3
1,200
9,727
12,027
—
—
N/A
N/A
(1,075)
(89)
—
—
N/A
(89)
—
—
—
N/A
N/A
—
—
—
—
—
—
—
—
—
—
49
49
57
43
15
104
219
2
20
3
1,200
9,776
11,001
104
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
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. See Note 15—
Derivatives and Financial Instruments, for information regarding where the assets and liabilities related to our
commodity and interest rate derivatives are recorded on our consolidated balance sheet.
Nonrecurring Fair Value Measurements
See Note 5—Business Combinations, for information on the remeasurement of our investment in Merey Sweeny to fair
value in 2017. For the years ended December 31, 2018 and 2017, there were no other material nonrecurring fair value
remeasurements of assets subsequent to their initial recognition.
105
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
under our share repurchase program, which aggregate to a total authorization of up to $12 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 repurchase program in 2012 through December 31, 2018, we have
repurchased a total of 137,103,716 shares at an aggregate cost of $10,393 million.
In February 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 35,000,000
shares of Phillips 66 common stock for an aggregate purchase price of $3,280 million. 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 in February 2018. We funded the
repurchase with cash of $1,880 million and borrowings of $1,400 million under our commercial paper program. These
borrowings were subsequently refinanced through a public offering of senior notes. This specific share repurchase
transaction was separately authorized by our Board of Directors and therefore did not impact previously announced
authorizations under our share repurchase program, which are discussed above.
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 $1,350 million. This specific share repurchase transaction was also separately authorized by our Board of
Directors and therefore did not impact previously announced authorizations under our share repurchase program, which
are discussed above.
Common Stock Dividends
On February 6, 2019, our Board of Directors declared a quarterly cash dividend of $0.80 per common share, payable
March 1, 2019, to holders of record at the close of business on February 19, 2019.
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.
106
Note 18—Leases
We lease ocean transport vessels, tugboats, barges, pipelines, storage tanks, railcars, service station sites, 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 $196 million and $210 million at December 31, 2018 and 2017, respectively.
Future minimum lease payments at December 31, 2018, for capital and operating lease obligations were:
2019
2020
2021
2022
2023
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
$
$
$
23
19
18
16
16
138
230
—
230
46
184
509
392
181
124
83
292
1,581
38
1,543
Operating lease rental expense for the years ended December 31 was:
Minimum rentals
Contingent rentals
Less: sublease rental income
Millions of Dollars
2018
2017
2016
$
$
669
5
71
603
680
6
73
613
669
6
95
580
107
Note 19—Pension and Postretirement Plans
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 Obligations
Benefit obligations at January 1
Service cost
Interest cost
Plan participant contributions
Net actuarial loss (gain)
Benefits paid
Curtailment gain
Foreign currency exchange rate change
Benefit obligations 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
2018
2017
Other Benefits
2018
2017
U.S.
Int’l.
U.S.
Int’l.
3,043
136
104
—
(167)
(386)
—
—
2,730
2,751
(122)
134
—
(386)
—
2,377
1,209
29
28
2
(165)
(27)
(5)
(64)
1,007
972
(29)
34
2
(27)
(50)
902
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
232
6
7
4
(9)
(20)
—
—
220
—
—
16
4
(20)
—
—
225
6
8
3
6
(16)
—
—
232
—
—
13
3
(16)
—
—
(353)
(105)
(292)
(237)
(220)
(232)
Amounts recognized in the consolidated balance sheet for our pension and other postretirement benefit plans at
December 31 include:
Amounts Recognized in the
Consolidated Balance Sheet
Noncurrent assets
Current liabilities
Noncurrent liabilities
Total recognized
Millions of Dollars
Pension Benefits
2018
2017
Other Benefits
2018
2017
U.S.
Int’l.
U.S.
Int’l.
$
$
—
(25)
(328)
(353)
78
—
(183)
(105)
—
(25)
(267)
(292)
—
—
(237)
(237)
—
(16)
(204)
(220)
—
(16)
(216)
(232)
108
Included in accumulated other comprehensive loss at December 31 were the following pre-tax amounts that had not been
recognized in net periodic benefit cost:
Millions of Dollars
Pension Benefits
2018
2017
Other Benefits
2018
2017
U.S.
Int’l.
U.S.
Int’l.
Unrecognized net actuarial loss (gain)
Unrecognized prior service credit
$
539
—
64
(3)
545
—
190
(4)
(8)
(6)
1
(7)
Millions of Dollars
Pension Benefits
2018
2017
Other Benefits
2018
2017
U.S.
Int’l.
U.S.
Int’l.
Sources of Change in Other
Comprehensive Loss
Net actuarial gain (loss) arising during the
period
Curtailment gain
Amortization of net actuarial loss and
settlements included in income
Net change in unrecognized net actuarial
loss (gain) during the period
Prior service cost (credit) arising during
the period
Amortization of prior service cost (credit)
included in income
Net change in unrecognized prior service
cost (credit) during the period
$
$
$
$
(125)
—
131
6
—
—
—
102
5
19
126
—
(1)
(1)
(14)
—
153
139
—
3
3
14
—
23
37
—
(1)
(1)
9
—
—
9
—
(1)
(1)
(6)
—
—
(6)
—
(2)
(2)
The accumulated benefit obligations for all U.S. and international pension plans were $2,466 million and $878 million,
respectively, at December 31, 2018, and $2,743 million and $1,006 million, respectively, at December 31, 2017.
Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at
December 31 were:
Millions of Dollars
Pension Benefits
2018
2017
U.S.
Int’l.
U.S.
Int’l.
$
123
—
345
182
143
—
368
196
Accumulated benefit obligations
Fair value of plan assets
109
Information for U.S. and international pension plans with a projected benefit obligation in excess of plan assets at
December 31 were:
Projected benefit obligations
Fair value of plan assets
Millions of Dollars
Pension Benefits
2018
2017
U.S.
Int’l.
U.S.
Int’l.
$ 2,730
2,377
365
182
3,043
2,751
1,209
972
Components of net periodic benefit cost for all defined benefit plans are presented in the table below:
Millions of Dollars
2018
Pension Benefits
2017
2016
2018
2017
2016
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)
Amortization of net
actuarial loss
Settlements
Total net periodic
benefit cost*
$
136
104
29
28
132
108
32
27
127
116
32
28
(169)
(46)
(146)
(40)
(128)
(38)
—
59
72
$
202
(1)
19
—
29
3
70
83
250
(1)
23
—
41
3
72
8
198
(1)
14
—
35
6
7
—
(1)
—
—
12
6
8
—
(2)
—
—
12
7
8
—
(1)
—
—
14
* Included in the “Operating expenses” and “Selling, general and administrative expenses” lines on our consolidated statement of income.
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.
110
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
Interest crediting rate on cash balance
plan
Assumptions Used to Determine Net
Periodic Benefit Cost:
Discount rate
Expected return on plan assets
Rate of compensation increase
Interest crediting rate on cash balance
plan
Pension Benefits
2018
2017
Other Benefits
2018
2017
U.S.
Int’l.
U.S.
Int’l.
4.30%
4.00
3.25
3.60%
6.50
4.00
3.00
2.59
3.34
—
2.36
4.78
3.74
—
3.60
4.00
3.00
3.95
6.75
4.00
3.55
2.36
3.74
—
2.46
4.74
3.78
—
4.15
—
—
3.35
—
—
—
3.35
—
—
3.65
—
—
—
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.
For the year ended December 31, 2018, actuarial gains resulted in decreases in our U.S. and international pension benefit
obligations of $167 million and $165 million, respectively. The primary drivers for the actuarial gains were increases in
the discount rates and changes to the census data demographics. For the year ended December 31, 2017, actuarial losses
resulted in an increase in our U.S. pension benefit obligations of $267 million. The primary drivers for the actuarial
losses were decreases in the discount rates and changes to the census data demographics.
For the year ended December 31, 2018, the weighted-average actual return on plan assets for our U.S. pension plans was
negative 4 percent, which resulted in a $122 million reduction in plan assets. For the year ended December 31, 2017, the
weighted-average actual return on plan assets for our U.S. pension plans was positive 18 percent, which resulted in a
$399 million increase in plan assets. The primary driver of the return on plan assets in 2018 and 2017 was fluctuations in
the equity markets.
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 7.00 percent in 2019 that declines
to 5.00 percent by 2027.
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
111
investment program from time to time. The target allocations for plan assets are approximately 50 percent equity
securities, 42 percent debt securities and 8 percent in all other types of investments. Generally, the investments in the
plans are publicly traded, therefore minimizing the liquidity risk in the portfolio.
The following is a description of the valuation methodologies used for the pension plan assets.
•
•
•
Fair values of equity securities and government debt securities are based on quoted market prices.
Fair values of corporate debt securities are estimated using recently executed transactions and market price
quotations. If there have been no market transactions in a particular fixed income security, its fair value is
calculated by pricing models that benchmark the security against other securities with actual market prices.
Fair values of mutual funds are valued based on quoted market prices, which represent the net asset value (NAV)
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.
Fair values of investments in common/collective trusts and real estate funds are valued at NAV as a practical
expedient. The NAV is based on the underlying net assets owned by the fund and the relative interest of each
participating investor in the fair value of the underlying assets. These investments valued at NAV are not
classified within the fair value hierarchy, but are presented in the fair value table to permit reconciliation of total
plan assets to the amounts presented in the notes to consolidated financial statements.
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
2018
Equity securities
Government debt
securities
Corporate debt securities
Cash and cash equivalents
Insurance contracts
Total assets in the fair
value hierarchy
Common/collective trusts
measured at NAV
Real estate funds
measured at NAV
$
421
610
—
50
—
1,081
—
—
129
—
—
129
—
—
—
—
—
—
Total
$ 1,081
129
—
421
610
129
50
—
1,210
1,048
119
2,377
—
—
—
7
—
7
—
—
—
—
—
—
—
—
—
—
14
14
7
—
14
—
—
—
7
14
21
873
8
902
112
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
Total assets in the fair
value hierarchy
Common/collective trusts
measured at NAV
Real estate funds
measured at NAV
$
589
632
129
90
—
1,440
—
—
—
—
—
—
—
—
—
—
—
—
Total
$ 1,440
—
—
589
632
129
90
—
1,440
1,311
—
2,751
—
—
—
6
—
6
—
—
—
—
—
—
—
—
—
—
14
14
6
—
14
—
—
—
6
14
20
944
8
972
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 2019, we expect to contribute
approximately $60 million to our U.S. pension plans and other postretirement benefit plans and $30 million to our
international pension plans.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid to plan
participants in the years indicated:
2019
2020
2021
2022
2023
2024-2028
Millions of Dollars
Pension Benefits
Other Benefits
U.S.
Int’l.
$
412
292
285
299
274
1,205
19
20
22
23
26
158
25
27
27
26
25
102
113
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. For the years ended December 31, 2018, 2017 and 2016, Phillips 66 provided a company match of
participant thrift contributions up to 5 percent of eligible pay. In addition, participants who contributed at least 1 percent
to the Savings Plan were 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. For the years ended December 31,
2018, 2017 and 2016, we recorded expense of $178 million, $101 million and $99 million, respectively, related to our
contributions to the Savings Plan.
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.
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 have elected to recognize forfeitures of awards when they occur.
Total share-based compensation expense recognized in income and the associated income tax benefit for the years ended
December 31 were:
Share-based compensation expense
Income tax benefit
Millions of Dollars
2018
2017
2016
$
100
(45)
142
(74)
156
(59)
114
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, 2018, to December 31, 2018:
Outstanding at January 1, 2018
Granted
Forfeited
Exercised
Outstanding at December 31, 2018
Vested at December 31, 2018
Options
4,838,855
650,000
(49,027)
(687,020)
4,752,808
3,941,271
Exercisable at December 31, 2018
3,331,259
Weighted-
Average
Exercise Price
Weighted-
Average
Grant-Date
Fair Value
Millions of Dollars
Aggregate
Intrinsic Value
$
20.69
$
$
$
$
58.34
94.85
89.93
57.61
63.11
57.79
53.51
$
$
$
37
109
106
The weighted-average remaining contractual terms of vested options and exercisable options at December 31, 2018, were
4.87 years and 4.29 years, respectively. During 2018, we received $39 million in cash and realized an income tax benefit
of $7 million from the exercise of options. At December 31, 2018, the remaining unrecognized compensation expense
from unvested options was $6 million, which will be recognized over a weighted-average period of 21 months, the
longest period being 25 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.
During 2017 and 2016, we granted options with a weighted-average grant-date fair value of $16.95 and $16.94,
respectively. During 2017 and 2016, employees exercised options with an aggregate intrinsic value of $62 million and
$58 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)
2018
2017
2016
2.81%
2.80%
25.41%
7.18
2.28
2.90
26.91
7.22
1.71
3.00
28.68
7.08
We calculate the volatility factor using historical Phillips 66 end-of-week closing stock prices since the Separation Date.
We periodically calculate the average period of time elapsed between grant dates and exercise dates of past grants to
estimate the expected life of new option grants.
115
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 dividend equivalent cash payment 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, 2018, to December 31, 2018:
Outstanding at January 1, 2018
Granted
Forfeited
Issued
Outstanding at December 31, 2018
Not Vested at December 31, 2018
Stock Units
Weighted-Average
Grant-Date
Fair Value
Millions of Dollars
Total Fair Value
2,496,425
822,457
(63,977)
(995,076)
2,259,829
1,565,641
$
$
$
77.20
96.16
84.61
75.77
84.52
84.99
$
102
At December 31, 2018, the remaining unrecognized compensation cost from unvested RSU awards was $53 million,
which will be recognized over a weighted-average period of 22 months, the longest period being 36 months.
During 2017 and 2016, we granted RSUs with a weighted-average grant-date fair value of $78.49 and $78.56,
respectively. During 2017 and 2016, we issued shares with an aggregate fair value of $85 million and $109 million,
respectively, to settle RSUs.
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 when the HRCC approves the three-year performance results on the grant date.
PSUs granted under the P66 Omnibus Plan are classified as liability awards and compensation expense is recognized
beginning on the authorization date and ending on the vesting date.
PSUs granted under the P66 Omnibus Plan are settled by cash payments equal to the fair value of the awards, which is
based on the 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.
PSUs granted under prior incentive compensation plans were classified as equity awards. These equity awards are settled
upon an employee’s retirement by issuing one share of our common stock for each PSU held. Dividend equivalents are
paid on these awards.
116
The following table summarizes our PSU activity from January 1, 2018, to December 31, 2018:
Outstanding at January 1, 2018
Granted
Forfeited
Issued
Cash settled
Outstanding at December 31, 2018
Not Vested at December 31, 2018
Millions of Dollars
Performance
Share Units
Weighted-Average
Grant-Date
Fair Value
Total Fair Value
2,558,278
494,277
(16,716)
(639,060)
(494,277)
1,902,502
153,236
$
$
$
$
52.06
99.74
69.90
59.15
99.74
49.52
65.59
70
49
At December 31, 2018, the remaining unrecognized compensation cost from unvested PSU awards was $1 million, which
will be recognized over a weighted-average period of 14 months, with the longest period being 4 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 2017 and 2016, we granted PSUs with a weighted-average grant-date fair value of $86.88 and $78.62,
respectively. During 2017 and 2016, we issued shares with an aggregate fair value of $54 million and $26 million,
respectively, to settle PSUs. During 2017 and 2016, we cash settled PSUs with an aggregate fair value of $56 million and
$60 million, respectively.
Note 21—Income Taxes
In December 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
the recognition of a provisional deferred tax benefit of $2,870 million in the year ended December 31, 2017. 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 the recognition of
a provisional income tax expense of $149 million in the year ended December 31, 2017.
During the year ended December 31, 2018, we recorded adjustments to finalize our accounting for the income tax effects
of the Tax Act, which increased our income tax expense by $36 million. The adjustments were primarily due to the
revision of our estimated deferred income tax balances in conjunction with the filing of our 2017 income tax return and
the issuance of additional guidance by the U.S. Internal Revenue Service related to the calculation of the one-time
deemed repatriation tax.
117
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
2018
2017
2016
$
$
739
257
326
53
255
(58)
1,572
9
(1,960)
126
3
61
68
(1,693)
(105)
645
66
(84)
(24)
49
547
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
Asset retirement obligations and accrued environmental costs
Loss and credit carryforwards
Other financial accruals and deferrals
Inventory
Other
Total deferred tax assets
Less: valuation allowance
Net deferred tax assets
Net deferred tax liabilities
Millions of Dollars
2018
3,074
2,041
602
66
14
5,797
395
109
59
16
—
—
579
8
571
5,226
$
$
2017
2,942
1,923
594
—
18
5,477
314
121
96
44
10
3
588
28
560
4,917
At December 31, 2018, the loss and credit carryforward deferred tax assets were primarily related to a German interest
deduction carryforward of $51 million, and capital loss and net operating loss carryforwards in the United Kingdom of $5
million. All losses may be carried forward indefinitely.
118
Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be
realized. During the year ended December 31, 2018, our total valuation allowance balance decreased by $20 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 were included in
our computation of the one-time deemed repatriation tax associated with the enactment of the Tax Act. Earnings of our
foreign subsidiaries and foreign joint ventures after December 31, 2017, are generally not subject to incremental income
taxes in the United States or withholding taxes in foreign countries upon repatriation. As such, we only assert that the
earnings of one of our foreign subsidiaries are permanently reinvested. At December 31, 2018 and 2017, the unrecorded
deferred tax liability related to the undistributed earnings of this foreign subsidiary was 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
2018
2017
2016
$
$
34
1
(2)
(10)
23
70
1
(5)
(32)
34
82
5
(17)
—
70
Included in the balance of unrecognized income tax benefits at December 31, 2018, 2017 and 2016 were $1 million, $5
million and $13 million, respectively, which, if recognized, would affect our effective income tax rate. With respect to
various unrecognized income tax benefits and the related accrued liabilities, we do not expect any to be recognized or
paid within the next twelve months.
At December 31, 2018, 2017 and 2016, accrued liabilities for interest and penalties, net of accrued income taxes, totaled
$5 million, $8 million and $12 million, respectively. As a result of reversing certain of these accruals, net income
increased by $1 million and $7 million for the years ended December 31, 2017 and 2016, 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 (2015), Germany (2014) and United States Phillips 66
audits (2013) and United States ConocoPhillips audits (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.
119
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:
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
Change in valuation allowance
Federal manufacturing deduction
Other
Millions of Dollars
Percentage of
Income Before Income Taxes
2018
2017
2016
2018
2017
2016
$
$
$
$
5,716
1,729
7,445
2,799
756
3,555
1,713
478
2,191
76.8%
23.2
100.0%
78.7
21.3
100.0
1,563
1,244
767
21.0%
35.0
155
36
(91)
(58)
(20)
—
(13)
1,572
79
(2,721)
(210)
(46)
(4)
(18)
(17)
(1,693)
12
—
(152)
(26)
(81)
—
27
547
2.1
0.5
(1.2)
(0.8)
(0.3)
—
(0.2)
21.1%
2.2
(76.5)
(5.9)
(1.3)
(0.1)
(0.5)
(0.5)
(47.6)
78.2
21.8
100.0
35.0
0.6
—
(6.9)
(1.2)
(3.7)
—
1.2
25.0
Income tax expense of $13 million, $81 million and $150 million for the years ended December 31, 2018, 2017 and
2016, respectively, is reflected in the “Capital in Excess of Par” column on our consolidated statement of changes in
equity.
120
Note 22—Accumulated Other Comprehensive Loss
Changes in the balances of each component of accumulated other comprehensive loss were as follows:
Millions of Dollars
Defined
Benefit
Plans
Foreign
Currency
Translation
Hedging
Accumulated
Other
Comprehensive
Loss
$
(662)
(112)
11
(296)
(2)
5
December 31, 2015
Other comprehensive income (loss) before reclassifications
Amounts reclassified from accumulated other comprehensive
loss*
Amortization of defined benefit plan items**
Net actuarial loss, prior service cost (credit) 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**
Net actuarial loss, prior service cost (credit) and
settlements
Net current period other comprehensive income
December 31, 2017
Other comprehensive income (loss) before reclassifications
Amounts reclassified from accumulated other comprehensive
loss
Amortization of defined benefit plan items**
Net actuarial loss, prior service cost (credit) and
settlements
Foreign currency translation
Hedging
Net current period other comprehensive income (loss)
December 31, 2018
$
61
(51)
(713)
3
112
115
(598)
14
112
—
—
126
(472)
—
(296)
(285)
259
—
259
(26)
(192)
—
(10)
—
(202)
(228)
—
5
3
4
—
4
7
4
—
—
(3)
1
8
* There were no significant reclassifications related to foreign currency translation or hedging in the years ended December 31, 2017 and 2016.
** Included in the computation of net periodic benefit cost. See Note 19—Pension and Postretirement Plans, for additional information.
121
(653)
(403)
61
(342)
(995)
266
112
378
(617)
(174)
112
(10)
(3)
(75)
(692)
Note 23—Cash Flow Information
Supplemental Cash Flow Information
Cash Payments (Receipts)
Interest
Income taxes*
Millions of Dollars
2018
2017
2016
$
465
984
421
(257)
311
(375)
* 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.
Restricted Cash
At December 31, 2018, 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 Merey Sweeny, were fully removed in May 2017 when
Merey Sweeny’s outstanding debt that contained lender restrictions on the use of cash was paid in full. See Note 5—
Business Combinations, for additional information regarding our consolidation of Merey Sweeny.
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**
Millions of Dollars
2017
2018
$
$
$
$
493
28
521
(17)
504
45
—
16
61
2016
402
17
419
(81)
338
18
—
56
74
60
80
—
—
(13)
1
(3)
(15)
432
21
453
(15)
438
31
423
67
521
60
76
—
—
(2)
1
1
—
* See Note 5—Business Combinations, for more information regarding the gain recognized in 2017.
** Includes derivatives-related activities. See Note 15—Derivatives and Financial Instruments, for additional information.
Research and Development Expenses
Advertising Expenses
Foreign Currency Transaction (Gains) Losses
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
$
$
$
$
122
55
68
—
—
(24)
1
(8)
(31)
Note 25—Related Party Transactions
Significant transactions with related parties were:
Millions of Dollars
2017
2018
Operating revenues and other income (a)
Purchases (b)
Operating expenses and selling, general and
administrative expenses (c)
$
3,514
12,755
59
2,596
10,468
79
2016
2,174
8,109
125
(a) We sold NGL and other petrochemical feedstocks, along with solvents, to CPChem, gas oil and hydrogen
feedstocks to Excel Paralubes (Excel), and refined petroleum products to OnCue. We also sold certain feedstocks
and intermediate products to WRB and 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, refined petroleum products and NGL from WRB and also acted as agent for WRB in
distributing solvents. We also 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. In addition, we
purchased base oils and fuel products from Excel for use in our specialty and refining businesses. We paid NGL
fractionation fees to CPChem. We also paid fees to various pipeline affiliates for transporting crude oil, refined
petroleum products and NGL.
(c) We paid utility and processing fees to various affiliates.
As discussed more fully in Note 5—Business Combinations, in February 2017, we began accounting for Merey Sweeny
as a consolidated subsidiary. Accordingly, the table above only includes processing fees paid to Merey Sweeny through
the consolidation date.
123
Note 26—Segment Disclosures and Related Information
During the fourth quarter of 2018, the segment performance measure used by our chief executive officer to assess
performance and allocate resources was changed from “net income” to “income before income taxes.” Prior-period
segment information has been recast to conform to the current presentation.
Our operating segments are:
1) Midstream—Provides crude oil and refined petroleum product transportation, terminaling and processing
services, as well as natural gas and NGL transportation, storage, processing and marketing services, mainly in
the United States. The Midstream segment includes our master limited partnership (MLP), 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.
Corporate and Other includes general corporate overhead, interest expense, our investment in new technologies and
various other corporate activities. Corporate assets include all cash, cash equivalents and income tax-related assets.
Intersegment sales are at prices that we believe approximate market.
124
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
Millions of Dollars
2017*
2018
$
8,293
(2,176)
6,117
5
83,140
(49,343)
33,797
6,620
(1,842)
4,778
5
65,494
(40,284)
25,210
2016*
4,226
(1,299)
2,927
5
52,068
(34,120)
17,948
73,414
(1,899)
71,515
27
111,461
73,565
(1,233)
72,332
29
102,354
64,476
(1,109)
63,367
32
84,279
Corporate and Other
Consolidated sales and other operating revenues
* Sales and other operating revenues for the years ended December 31, 2017 and 2016, are presented in accordance with accounting standards in effect
prior to our adoption of ASU No. 2014-09 on January 1, 2018. See Note 2—Changes in Accounting Principles, for further discussion regarding our
adoption of ASU No. 2014-09.
$
** See Note 3—Sales and Other Operating Revenues, for further details on our disaggregated sales and other operating revenues.
Equity in Earnings of Affiliates
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Consolidated equity in earnings of affiliates
Depreciation, Amortization and Impairments
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Consolidated depreciation, amortization and impairments
$
$
$
$
676
1,025
796
164
15
2,676
326
—
841
114
83
1,364
454
713
322
243
—
1,732
299
—
838
116
89
1,342
184
834
164
232
—
1,414
218
—
770
107
78
1,173
125
Millions of Dollars
2017
2018
—
—
—
—
45
45
1
—
—
—
30
31
2016
2
—
—
—
16
18
504
438
338
1,181
1,025
4,535
1,557
(853)
7,445
5,423
6,233
2,226
349
—
14,231
638
716
2,076
1,020
(895)
3,555
4,734
6,222
2,398
390
—
13,744
13,231
6,226
23,780
7,052
4,082
54,371
403
839
435
1,261
(747)
2,191
4,769
5,773
2,420
391
1
13,354
12,832
5,802
22,781
6,179
4,059
51,653
Interest Income and Expense
Interest income
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Consolidated interest income
Interest and debt expense
Corporate and Other
Income (Loss) Before Income Taxes
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Consolidated income before income taxes
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
* Prior-period segment information has been recast to include all income tax-related assets in Corporate and Other.
14,329
6,235
23,230
6,572
3,936
54,302
$
$
126
Capital Expenditures and Investments
Midstream
Chemicals
Refining
Marketing and Specialties
Corporate and Other
Consolidated capital expenditures and investments
Geographic Information
Millions of Dollars
2017
2018
$
$
1,548
—
826
125
140
2,639
771
—
853
108
100
1,832
Long-lived assets, defined as net PP&E plus investments and long-term receivables, by geographic location at
December 31 were:
United States
United Kingdom
Germany
Other foreign countries
Worldwide consolidated
Millions of Dollars
2017
2018
$
$
34,587
1,191
570
91
36,439
33,457
1,254
593
97
35,401
2016
1,453
—
1,149
98
144
2,844
2016
32,619
1,177
505
88
34,389
127
Note 27—Phillips 66 Partners LP
Phillips 66 Partners, headquartered in Houston, Texas, is a publicly traded MLP formed in 2013 to own, operate, develop
and acquire primarily fee-based midstream assets. Phillips 66 Partners’ operations currently consist of crude oil, refined
petroleum product and NGL transportation, processing, terminaling and storage assets.
We consolidate Phillips 66 Partners because we determined it is a VIE of which 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 that most significantly impact its economic performance. 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 $2,469 million and $2,314 million on our consolidated balance sheet at December 31, 2018
and 2017, 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, 2018, we owned a 54 percent limited partner interest and a 2 percent general partner interest in Phillips
66 Partners, while the public owned a 44 percent limited partner interest and 13.8 million perpetual convertible preferred
units. 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.
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, were:
Millions of Dollars
December 31
2018
December 31
2017
Cash and cash equivalents
Equity investments*
Net properties, plants and equipment
Long-term debt
* Included in “Investments and long-term receivables” line on the Phillips 66 consolidated balance sheet.
$
1
2,448
3,052
2,998
185
1,932
2,918
2,920
2018 Activities
Phillips 66 Partners’ initial $250 million continuous offering of common units, or at-the-market (ATM) program, was
completed in June 2018. At that time, Phillips 66 Partners commenced issuing common units under its second $250
million ATM program. For the years ended December 31, 2018 and 2017, on a settlement-date basis, Phillips 66 Partners
generated net proceeds of $128 million and $173 million, respectively, from common units issued under the ATM
programs. Since inception in June 2016 through December 31, 2018, the ATM programs have generated net proceeds of
$320 million.
Phillips 66 Partners’ investment in the Gray Oak Pipeline development is held through Holdings LLC. In December
2018, a third party exercised its option to acquire a 35 percent interest in Holdings LLC. Because Holdings LLC’s sole
asset was its 75 percent ownership interest in Gray Oak, which is considered a financial asset, and because certain
restrictions were placed on the third party’s ability to transfer or sell its interest in Holdings LLC during the construction
of the Gray Oak Pipeline, the legal sale of the 35 percent interest did not qualify as a sale under GAAP. As such, the
contributions the third party will make to Holdings LLC in 2019 to cover its share of previously incurred and future
construction costs plus a premium to Phillips 66 Partners will be reflected as a long-term obligation on our consolidated
balance sheet and financing cash inflows on our consolidated statement of cash flows. After construction of the Gray
Oak Pipeline is completed, these restrictions expire, and the sale will be recognized under GAAP. Phillips 66 Partners
will continue to control and consolidate Holdings LLC after sale recognition, and therefore the third party’s 35 percent
interest will be recharacterized from a long-term obligation to a noncontrolling interest in our financial statements at that
time. Also at that time, the premium paid will be recharacterized from a long-term obligation to a gain in our
consolidated statement of income. During January and February of 2019, the third party contributed an aggregate of
128
$294 million into Holdings LLC, which Holdings LLC used to fund its portion of Gray Oak’s cash calls. See Note 7—
Investments, Loans and Long-Term Receivables, for further discussion regarding Phillip 66 Partners’ investment in Gray
Oak.
2017 Activities
In October 2017, we contributed to Phillips 66 Partners our 25 percent ownership interests in both Dakota Access and
ETCO and our 100 percent ownership interest in Merey Sweeny. 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.
• 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.
Note 28—New Accounting Standards
In February 2018, the FASB issued ASU No. 2018-02, “Income Statement—Reporting Comprehensive Income (Topic
220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU allows for the
deferred income tax effects stranded in accumulated other comprehensive income (AOCI) resulting from the Tax Act
enacted in December 2017 to be reclassed from AOCI to retained earnings. This ASU is effective for fiscal years, and
interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. Upon
adoption on January 1, 2019, we increased retained earnings by approximately $90 million with the offset to accumulated
other comprehensive loss on our consolidated balance sheet.
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 evaluating the provisions of ASU No. 2016-13, and currently do not expect
our adoption to have a material impact on our consolidated 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. The ASU also requires additional disclosures. 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. We will adopt ASU No. 2016-02 by recognizing a cumulative-
effect adjustment to our opening consolidated balance sheet as of our January 1, 2019, adoption date. As of the adoption
date, we expect to recognize ROU assets and operating lease liabilities on our consolidated balance sheet of
approximately $1.4 billion. The adoption of this ASU is not expected to have a material impact on our consolidated
statements of income and cash flows.
129
Note 29—Condensed Consolidating Financial Information
Phillips 66 has 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.
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
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, 2018
Phillips 66
Phillips 66
Company
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
$
$
—
5,918
—
—
—
5,918
—
—
7
—
—
—
—
402
—
409
5,509
(86)
5,595
—
5,595
85,486
4,030
8
33
3,493
93,050
79,559
3,769
1,297
926
3
321
18
146
—
86,039
7,011
1,093
5,918
—
5,918
25,975
747
11
28
14,085
40,846
35,563
1,193
383
430
5
104
5
250
(31)
37,902
2,944
565
2,379
278
2,101
—
(8,019)
—
—
(17,578)
(25,597)
(17,192)
(82)
(10)
—
—
—
—
(294)
—
(17,578)
(8,019)
—
(8,019)
—
(8,019)
111,461
2,676
19
61
—
114,217
97,930
4,880
1,677
1,356
8
425
23
504
(31)
106,772
7,445
1,572
5,873
278
5,595
5,520
5,843
2,291
(7,856)
5,798
130
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
131
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
132
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
Assets 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
Year Ended December 31, 2018
Phillips 66
Phillips 66
Company
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
1,648
4,255
2,489
373
8,765
22,799
13,218
2,853
726
335
48,696
5,415
11
458
663
227
6,774
54
458
3,541
676
4,611
16,114
24,960
8,314
(692)
—
48,696
1,371
3,202
1,054
99
5,726
9,829
8,800
417
143
173
25,088
2,464
56
658
61
149
3,388
3,111
166
1,735
191
4,287
12,878
8,754
1,249
(293)
2,500
25,088
—
(1,293)
—
—
(1,293)
(50,919)
—
—
—
(2)
(52,214)
(1,293)
—
—
—
—
(1,293)
—
—
(2)
—
(8,598)
(9,893)
(33,714)
(9,592)
985
—
(52,214)
3,019
6,173
3,543
474
13,209
14,421
22,018
3,270
869
515
54,302
6,586
67
1,116
724
442
8,935
11,093
624
5,275
867
355
27,149
4,856
20,489
(692)
2,500
54,302
$
$
$
$
—
9
—
2
11
32,712
—
—
—
9
32,732
—
—
—
—
66
66
7,928
—
1
—
55
8,050
4,856
20,518
(692)
—
32,732
133
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
Assets 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
Year Ended 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
134
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
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 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 return of investments in equity affiliates.
Millions of Dollars
Year Ended December 31, 2018
Phillips 66
Phillips 66
Company
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
2,955
6,962
2,642
(4,986)
7,573
(998)
462
(3,031)
—
27
(3,540)
—
(11)
—
—
(3,174)
—
—
—
(3,185)
(1,641)
50
817
(1)
85
(690)
675
(583)
—
—
(1,812)
(207)
128
(455)
(2,254)
—
(35)
237
1,411
1,648
(337)
1,708
1,371
—
(455)
—
—
—
(455)
—
—
—
—
4,986
—
—
455
5,441
—
—
—
—
(2,639)
57
—
(1)
112
(2,471)
2,184
(1,144)
39
(4,645)
(1,436)
(207)
128
(86)
(5,167)
(35)
(100)
3,119
3,019
—
—
2,214
—
—
2,214
1,509
(550)
39
(4,645)
(1,436)
—
—
(86)
(5,169)
—
—
—
—
135
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)
—
—
—
—
136
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
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, 2016
Phillips 66
Phillips 66
Company
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
3,491
2,307
1,552
(4,387)
2,963
(1,425)
1,007
2,046
(75)
—
18
1,571
—
(26)
—
—
(3,604)
—
—
31
(3,599)
—
279
575
854
(1,457)
156
(907)
(357)
108
(164)
(2,621)
2,090
(807)
—
—
(783)
(75)
972
(980)
417
10
(642)
2,499
1,857
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
2,711
—
—
(1,139)
—
—
—
(1,139)
—
—
34
(1,042)
(1,282)
—
—
(62)
(2,352)
—
—
—
—
137
Selected Quarterly Financial Data (Unaudited)
Sales and
Other
Operating
Revenues*
$
23,595
28,980
29,788
29,098
2018
First
Second
Third
Fourth
$
2017
797
First
848
Second
1,256
Third
654
Fourth**
* 2017 amounts include excise taxes on sales of refined petroleum products.
22,894
24,087
25,627
29,746
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
717
1,835
1,975
2,918
585
1,404
1,568
2,316
563
581
849
3,255
524
1,339
1,492
2,240
535
550
823
3,198
1.07
2.86
3.20
4.85
1.02
1.06
1.60
6.29
1.07
2.84
3.18
4.82
1.02
1.06
1.60
6.25
** Includes a $2,721 million provisional income tax benefit from the enactment of the U.S. Tax Cuts and Jobs Act in December 2017.
138
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
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, 2018, 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, 2018.
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, 2018, 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.
139
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding our executive officers appears in Part I of this report.
PART III
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 8, 2019, which will be filed within 120 days after December
31, 2018 (2019 Definitive Proxy Statement).*
Item 11. EXECUTIVE COMPENSATION
The information required by Item 11 of Part III is incorporated herein by reference from our 2019 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 2019 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 2019 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 2019 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 2019
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.
140
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PART IV
(a) 1.
Financial Statements and Supplementary Data
The financial statements and supplementary information listed in the Index to Financial Statements, which
appears on page 71, 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 142 to 145, are filed as part of this Annual
Report on Form 10-K.
Item 16. FORM 10-K SUMMARY
None.
141
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 Amendment to Third Amended and Restated
Limited Liability Company Agreement of Chevron Phillips
Chemical Company LLC, effective as of June 1, 2018.
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
10
4.1 03/01/2012 001-35349
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-K
10.6 02/23/2018 001-35349
10-Q
10.1 07/27/2018 001-35349
142
Exhibit
Number
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
Exhibit Description
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.
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
10.12 03/01/2012 001-35349
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
143
10.20
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*
10.35*
10.36
21*
23.1*
31.1*
Exhibit
Number
Exhibit Description
2013 Omnibus Stock and Performance Incentive Plan of
Phillips 66.**
Phillips 66 Key Employee Supplemental Retirement
Plan.**
First Amendment to the Phillips 66 Key Employee
Supplemental Retirement Plan.**
Incorporated by Reference
Form
Exhibit
Number
Filing
Date
SEC
File No.
DEF14A
App. A 03/27/2013 001-35349
10-Q
10.15 08/03/2012 001-35349
10-K
10.18 02/22/2013 001-35349
Phillips 66 Amended and Restated Executive Severance
Plan.**
10-Q
10.1 07/29/2016 001-35349
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.**
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
10.17 08/03/2012 001-35349
10-Q
10.18 08/03/2012 001-35349
10-Q
10.19 08/03/2012 001-35349
10-K
10.24 02/22/2013 001-35349
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
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.**
Stock Purchase and Sale Agreement between Phillips 66,
Berkshire Hathaway Inc., and National Indemnity
Company, dated February 13, 2018.
List of Subsidiaries of Phillips 66.
Consent of Ernst & Young LLP, independent registered
public accounting firm.
Certification of Chief Executive Officer pursuant to Rule
13a-14(a) under the Securities Exchange Act of 1934.
144
8-K
10.1 02/14/2018 001-35349
Incorporated by Reference
Form
Exhibit
Number
Filing
Date
SEC
File No.
Exhibit
Number
31.2*
Exhibit Description
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.
101.INS* XBRL Instance Document.
101.SCH* XBRL Schema Document.
101.CAL* XBRL Calculation Linkbase Document.
101.LAB* XBRL Labels Linkbase Document.
101.PRE* XBRL Presentation Linkbase Document.
101.DEF* XBRL Definition Linkbase Document.
* Filed herewith.
** Management contracts and compensatory plans or arrangements.
145
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 22, 2019
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 22, 2019, 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)
146
/s/ Gary K. Adams
Gary K. Adams
/s/ J. Brian Ferguson
J. Brian Ferguson
/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
147
This Page Intentionally Left Blank
2018 PHILLIPS 66 ANNUAL REPORT
SHAREHOLDER INFORMATION
ANNUAL MEETING
Phillips 66’s annual meeting of
shareholders will be held:
Wednesday, May 8, 2019
9 a.m. Central Daylight Time
Houston Marriott Westchase
2900 Briarpark Drive
Houston, TX 77042
Notice of the meeting and proxy
materials will be provided to
all shareholders.
DIRECT STOCK PURCHASE
AND DIVIDEND
REINVESTMENT PLAN
Phillips 66’s Investor Services
Program is a direct stock purchase
and dividend reinvestment plan that
offers shareholders a convenient
way to buy additional shares
and reinvest their common stock
dividends. Purchases of company
stock through direct cash payment
are commission-free.
Please call Computershare to
request an enrollment package:
Toll-free number: 866-437-0009
Or enroll online at
www.computershare.com/investor
Registered shareholders can
access important investor
communications online and sign
up to receive future shareholder
materials electronically by going to
www.computershare.com/investor
and following the enrollment
instructions.
PRINCIPAL AND
REGISTERED OFFICES
Phillips 66
P.O. Box 421959
Houston, TX 77242-1959
251 Little Falls Drive
Wilmington, DE 19808
STOCK TRANSFER AGENT
AND REGISTRAR
Computershare
462 South 4th Street, Suite 1600
Louisville, KY 40202
www.computershare.com/investor
INFORMATION REQUESTS
For information about dividends and
certificates or to request a change of
address form, shareholders may contact:
Computershare
P.O. BOX 505000
Louisville, KY 40233
Toll-free number: 866-437-0009
Outside the U.S.: 201-680-6578
TDD for hearing impaired:
800-231-5469
TDD outside the U.S.: 201-680-6610
www.computershare.com/investor
Personnel in the following offices
also can answer investors’ questions
about the company:
INSTITUTIONAL INVESTORS
800-624-6440
investorrelations@p66.com
INDIVIDUAL INVESTORS
866-437-0009
web.queries@computershare.com
COMPLIANCE AND ETHICS
For guidance, to express concerns
or to ask questions about compliance
and ethics issues, contact the
Phillips 66 Global Ethics Office:
Toll-free number available 24/7:
855-318-5390
Email: ethics@p66.com
Website:
www.phillips66.ethicspoint.com
Address: Attn: Global Ethics Office
Phillips 66
2331 CityWest Blvd.
Houston, TX 77042
COPIES OF FORM 10-K
AND PROXY STATEMENT
Copies of the Annual Report on
Form 10-K and the Proxy Statement,
as filed with the U.S. Securities and
Exchange Commission, are available
free by making a request on the
company’s website, calling
918-977-2245 or writing:
Phillips 66
2018 Form 10-K
411 S. Keeler
Bartlesville, OK 74003
Additional copies of this Annual
Report may be obtained by calling
918-977-2245 or writing:
Phillips 66
2018 Annual Report
411 S. Keeler
Bartlesville, OK 74003
INTERNET
www.phillips66.com
The website includes resources
of interest to investors, including
news releases and presentations
to securities analysts; copies of
Phillips 66’s Annual Report and
Proxy Statement; reports to the U.S.
Securities and Exchange Commission;
and data on Phillips 66’s health, safety
and environmental performance.
Other websites with information on
topics included in this Annual Report:
www.cpchem.com
www.dcpmidstream.com
www.phillips66partners.com
Phillips 66®, Conoco®, 76®, Kendall®, Red Line®, JET® and their respective logos are registered trademarks of Phillips 66 Company or
a wholly owned subsidiary. Other names and logos mentioned herein are the trademarks of their respective owners.
DISCLOSURE STATEMENTS
Certain disclosures in this Annual Report may be considered “forward-looking” statements. These are made pursuant to “safe
harbor” provisions of the Private Securities Litigation Reform Act of 1995. The “Cautionary Statement” in Management’s Discussion
and Analysis should be read in conjunction with such statements. “Phillips 66,” “the company,” “we,” “us” and “our” are used
interchangeably in this report to refer to the businesses of Phillips 66 and its consolidated subsidiaries.
PHOTOGRAPHY
Andrew Camacho, Ken Childress, Garth Hannum, Mike Lewis and Energy Transfer Partners.
19-0012_001 ©2019 Phillips 66 Company. All rights reserved.
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