Phillips 66 - Annual Report: 2014 (Form 10-K)

Closing Stock Price at December 31, 2014

Closing Stock Price at January 30, 2015

Number of Stockholders of Record at January 30, 2015



2014



	UNITED STATES
	SECURITIES AND EXCHANGE COMMISSION
	Washington, D.C. 20549
	FORM 10-K



(Mark One)
[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended	December 31, 2014
	OR
[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



For the transition period from		to
	Commission file number: 001-35349



	Phillips 66
	(Exact name of registrant as specified in its charter)



	Delaware		45-3779385
	(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)



	3010 Briarpark Drive, 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		Name of each exchange on which registered
	Common Stock, $.01 Par Value		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.				[X] Yes [ ] No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.				[ ] Yes [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.				[X] Yes [ ] No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).				[X] Yes [ ] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.				[X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer [X]	Accelerated filer [ ]	Non-accelerated filer [ ]	Smaller reporting company [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).				[ ] Yes [X] No

The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $80.43, was $44.9 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 543,497,802 shares of common stock outstanding at January 31, 2015.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 6, 2015 (Part III).

Table of Contents

Index to Financial Statements

TABLE OF CONTENTS

Item	Page

PART I

1 and 2. Business and Properties	1
Corporate Structure	1
Segment and Geographic Information	2
Midstream	2
Chemicals	9
Refining	12
Marketing and Specialties	16
Discontinued Operations	18
Technology Development	18
Competition	18
General	18
1A. Risk Factors	20
1B. Unresolved Staff Comments	27
3. Legal Proceedings	27
4. Mine Safety Disclosures	28
Executive Officers of the Registrant	29

PART II

5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
6. Selected Financial Data	31
7. Management's Discussion and Analysis of Financial Condition and Results of Operations	32
7A. Quantitative and Qualitative Disclosures About Market Risk	62
Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995	64
8. Financial Statements and Supplementary Data	65
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	135
9A. Controls and Procedures	135
9B. Other Information	135

PART III

10. Directors, Executive Officers and Corporate Governance	136
11. Executive Compensation	136
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	136
13. Certain Relationships and Related Transactions, and Director Independence	136
14. Principal Accounting Fees and Services	136

PART IV

15. Exhibits, Financial Statement Schedules	137
Signatures	143

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Index to Financial Statements

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,” beginning on page 64.

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 resulting in the separation of 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). Each ConocoPhillips stockholder received one share of Phillips 66 stock for every two shares of ConocoPhillips stock held at the close of business on the record date of April 16, 2012. On May 1, 2012, Phillips 66 stock began trading “regular-way” on the New York Stock Exchange under the “PSX” stock symbol.

Our business is organized into four operating segments:

Midstream—Gathers, processes, transports and markets natural gas; and transports, fractionates and markets natural gas liquids (NGL) in the United States. In addition, this segment transports crude oil and other feedstocks to our refineries and other locations, delivers refined and specialty products to market, and provides storage services for crude oil and petroleum products. The Midstream segment includes, among other businesses, our 50 percent equity investment in DCP Midstream, LLC (DCP Midstream) and our investment in Phillips 66 Partners LP.


2)	Chemicals—Manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC (CPChem).


3)	Refining—Buys, sells and refines crude oil and other feedstocks at 14 refineries, mainly in the United States and Europe.


4)	Marketing and Specialties (M&S)—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, as well as power generation operations.

Corporate and Other includes general corporate overhead, interest expense, our investment in new technologies and various other corporate activities. Corporate assets include all cash and cash equivalents.

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Index to Financial Statements

Effective January 1, 2014, we changed the organizational structure of the internal financial information reviewed by our chief executive officer, and determined this resulted in a change in the composition of our operating segments. The primary effects of this reporting reorganization were as follows:


•	We moved two of our equity investments, Excel Paralubes and Jupiter Sulphur, LLC, as well as the commission revenues related to needle and anode coke, polypropylene and solvents, from the Refining segment to the M&S segment.


•	We moved several refining logistics projects from the Refining segment to the Midstream segment.

The new segment alignment is presented for the periods ending December 31, 2014, with prior periods recast for comparability.

At December 31, 2014, Phillips 66 had approximately 14,000 employees.

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 27—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

MIDSTREAM

The Midstream segment consists of three business lines:


•	Transportation—transports crude oil and other feedstocks to our refineries and other locations, delivers refined and specialty products to market, and provides storage services for crude oil and petroleum products. The operations of our master limited partnership, Phillips 66 Partners LP, are included in this business line.


•	DCP Midstream—gathers, processes, transports and markets natural gas and transports, fractionates and markets NGL.


•	NGL—transports, fractionates and markets natural gas liquids.

Transportation

We own or lease various assets to provide environmentally safe, strategic and timely delivery and storage of crude oil, refined products, natural gas and NGL. These assets include pipeline systems; petroleum product, crude oil and liquefied petroleum gas (LPG) terminals; a petroleum coke handling facility; marine vessels; railcars and trucks.

Pipelines and Terminals

At December 31, 2014, our Transportation business managed over 18,000 miles of crude oil, natural gas, NGL and petroleum products pipeline systems in the United States, including those partially owned or operated by affiliates. We owned or operated 39 finished product terminals, 37 storage locations, 5 LPG terminals, 15 crude oil terminals and 1 petroleum coke exporting facility.

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Index to Financial Statements

In 2014, we acquired a 7.1 million-barrel-storage-capacity crude oil and petroleum products terminal located near Beaumont, Texas (Beaumont Terminal), and purchased an additional 5.7 percent interest in Explorer Pipeline Company, which transports refined petroleum products. The Beaumont Terminal is the largest terminal in the Phillips 66 portfolio and is strategically located on the U.S. Gulf Coast. It provides deep-water access and multiple interconnections with major crude oil and refined product pipelines serving 3.6 million barrels per day of refining capacity. The terminal has:


•	4.7 million barrels of crude oil storage capacity and 2.4 million barrels of refined product storage capacity.


•	Two marine docks capable of handling Aframax tankers and one barge dock.


•	Rail and truck loading and unloading facilities.

The following table depicts our ownership interest in major pipeline systems as of December 31, 2014:



Name	Origination/Terminus	Interest		Size	Length(Miles)	Capacity (MBD)
Crude and Feedstocks
Glacier	Cut Bank, MT/Billings, MT	79	%	8”-12”	865	100
Line 80	Gaines, TX/Borger, TX	100		8”, 12”	237	28
Line O	Cushing, OK/Borger, TX	100		10”	276	37
WA Line	Odessa, TX/Borger, TX	100		12”, 14”	289	104
Cushing	Cushing, OK/Ponca City, OK	100		18”	62	130
North Texas Crude	Wichita Falls, TX	100		2”-16”	301	28
Oklahoma Mainline	Wichita Falls, TX/Ponca City, OK	100		12”	217	100
Clifton Ridge †	Clifton Ridge, LA/Westlake, LA	75		20”	10	260
Louisiana Crude Gathering	Rayne, LA/Westlake, LA	100		4”-8”	80	25
Sweeny Crude	Sweeny, TX/Freeport, TX	100		12”, 24”, 30”	56	265
Line 100	Taft, CA/Lost Hills, CA	100		8”, 10”, 12”	79	54
Line 200	Lost Hills, CA/Rodeo, CA	100		12”, 16”	228	93
Line 300	Nipomo, CA/Arroyo Grande, CA	100		8”, 10”, 12”	56	48
Line 400	Arroyo Grande, CA/Lost Hills, CA	100		8”, 10”, 12”	147	40

Petroleum Product
Harbor	Woodbury, NJ/Linden, NJ	33		16”	80	57
Pioneer	Sinclair, WY/Salt Lake City, UT	50		8”, 12”	562	63
Seminoe	Billings, MT/Sinclair, WY	100		6”-10”	342	33
Yellowstone	Billings, MT/Moses Lake, WA	46		6”-10”	710	66
Borger to Amarillo	Borger, TX/Amarillo, TX	100		8”, 10”	93	76
ATA Line	Amarillo, TX/Albuquerque, NM	50		6”, 10”	293	17
Borger-Denver	McKee, TX/Denver, CO	70		6”-12”	405	38
Gold Line †	Borger, TX/East St. Louis, IL	75		8”-16”	681	120
SAAL	Amarillo, TX/Abernathy, TX	33		6”	102	11
SAAL	Abernathy, TX/Lubbock, TX	54		6”	19	16
Cherokee South	Ponca City, OK/Oklahoma City, OK	100		8”	90	46
Heartland*	McPherson, KS/Des Moines, IA	50		8”, 6”	49	30
Paola Products †	Paola, KS/Kansas City, KS	75		8”, 10”	106	96
Standish	Marland Junction, OK/Wichita, KS	100		18”	92	72
Cherokee North	Ponca City, OK/Wichita, KS	100		8”, 10”	105	55
Cherokee East	Medford, OK/Mount Vernon, MO	100		10”, 12”	287	55
Explorer	Texas Gulf Coast/Chicago, IL	19		24”, 28”	1,830	660
Sweeny to Pasadena †	Sweeny, TX/Pasadena, TX	75		12”, 18”	120	264
LAX Jet Line	Wilmington, CA/Los Angeles, CA	50		8"	19	25
Torrance Products	Wilmington, CA/Torrance, CA	100		10”, 12”	8	161
Los Angeles Products	Torrance, CA/Los Angeles, CA	100		6”, 12”	22	112
Watson Products Line	Wilmington, CA/Long Beach, CA	100		20”	9	238
Richmond	Rodeo, CA/Richmond, CA	100		6”	14	26

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Index to Financial Statements



Name	Origination/Terminus	Interest		Size	Length (Miles)	Capacity (MBD)
NGL
Powder River	Sage Creek, WY/Borger, TX	100	%	6”-8”	695	14
Skelly-Belvieu	Skellytown, TX/Mont Belvieu, TX	50		8”	571	45
TX Panhandle Y1/Y2	Sher-Han, TX/Borger, TX	100		3”-10”	299	61
Chisholm	Kingfisher, OK/Conway, KS	50		4”-10”	202	42
Sand Hills**	Permian Basin/Mont Belvieu, TX	33		20”	905	200
Southern Hills**	U.S. Midcontinent/Mont Belvieu, TX	33		20”	895	175

LPG
Blue Line	Borger, TX/East St. Louis, IL	100		8”-12”	667	29
Conway to Wichita	Conway, KS/Wichita, KS	100		12”	55	38
Medford	Ponca City, OK/Medford, OK	100		4”-6”	42	10

Natural Gas
Rockies Express	Meeker, CO/Clarington, OH	25		36”-42”	1,698	1.8 BCFD

*Total pipeline system is 419 miles. Phillips 66 has ownership interest in multiple segments totaling 49 miles.

**Operated by DCP Midstream Partners; Phillips 66 has a direct one-third ownership in the pipeline entities; reported within NGL.

†Owned by Phillips 66 Partners LP.

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Index to Financial Statements

The following table depicts our ownership interest in finished product terminals as of December 31, 2014:



Facility Name	Location	Interest	Storage Capacity (MBbl)	Rack Capacity (MBD)
Albuquerque	New Mexico	100%	244	18
Amarillo	Texas	100	277	29
Beaumont	Texas	100	2,400	8
Billings	Montana	100	88	16
Bozeman	Montana	100	113	13
Colton	California	100	211	21
Denver	Colorado	100	310	43
Des Moines	Iowa	50	206	15
East St. Louis*	Illinois	75	2,245	78
Glenpool North	Oklahoma	100	366	19
Great Falls	Montana	100	157	12
Hartford*	Illinois	75	1,075	25
Helena	Montana	100	178	10
Jefferson City*	Missouri	75	110	16
Kansas City*	Kansas	75	1,294	66
La Junta	Colorado	100	101	10
Lincoln	Nebraska	100	219	21
Linden	New Jersey	100	429	121
Los Angeles	California	100	116	75
Lubbock	Texas	100	179	17
Missoula	Montana	50	348	29
Moses Lake	Washington	50	186	13
Mount Vernon	Missouri	100	363	46
North Salt Lake	Utah	50	657	41
Oklahoma City	Oklahoma	100	341	48
Pasadena*	Texas	75	3,210	65
Ponca City	Oklahoma	100	51	23
Portland	Oregon	100	664	33
Renton	Washington	100	228	20
Richmond	California	100	334	28
Rock Springs	Wyoming	100	125	19
Sacramento	California	100	141	13
Sheridan	Wyoming	100	86	15
Spokane	Washington	100	351	24
Tacoma	Washington	100	307	17
Tremley Point	New Jersey	100	1,593	39
Westlake	Louisiana	100	128	16
Wichita Falls	Texas	100	303	15
Wichita North*	Kansas	75	679	19

*Owned by Phillips 66 Partners LP.

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Index to Financial Statements

The following table depicts our ownership interest in crude and other terminals as of December 31, 2014:



Facility Name	Location	Interest		Storage Capacity (MBbl)	Loading Capacity**
Crude
Beaumont	Texas	100	%	4,704	N/A
Billings	Montana	100		270	N/A
Borger	Texas	100		678	N/A
Clifton Ridge*	Louisiana	75		3,410	N/A
Cushing	Oklahoma	100		700	N/A
Junction	California	100		523	N/A
McKittrick	California	100		237	N/A
Odessa	Texas	100		523	N/A
Pecan Grove*	Louisiana	75		142	N/A
Ponca City	Oklahoma	100		1,200	N/A
Santa Margarita	California	100		335	N/A
Santa Maria	California	100		112	N/A
Tepetate	Louisiana	100		152	N/A
Torrance	California	100		309	N/A
Wichita Falls	Texas	100		240	N/A

Coke
Lake Charles	Louisiana	50		N/A	N/A

Rail
Bayway*	New Jersey	75		N/A	75
Beaumont	Texas	100		N/A	20
Ferndale*	Washington	75		N/A	30
Missoula	Montana	50		N/A	41
Thompson Falls	Montana	50		N/A	42

Marine
Beaumont	Texas	100		N/A	13
Clifton Ridge*	Louisiana	75		N/A	48
Hartford*	Illinois	75		N/A	3
Pecan Grove*	Louisiana	75		N/A	6
Portland	Oregon	100		N/A	10
Richmond	California	100		N/A	3
Tacoma	Washington	100		N/A	12
Tremley Point	New Jersey	100		N/A	7

*Owned by Phillips 66 Partners LP.

**Rail in thousands of barrels daily (MBD); Marine in thousands of barrels per hour.

Rockies Express Pipeline LLC (REX)

We have a 25 percent interest in REX. The REX natural gas pipeline runs 1,698 miles from Meeker, Colorado, to Clarington, Ohio, and has a natural gas transmission capacity of 1.8 billion cubic feet per day (BCFD), with most of its system having a pipeline diameter of 42 inches. Numerous compression facilities support the pipeline system. The REX pipeline is designed to enable natural gas producers in the Rocky Mountain region to deliver natural gas supplies to the Midwest and eastern regions of the United States. Additionally, REX is exploring opportunities to bring Appalachian production into the system.

Phillips 66 Partners LP

In 2013, we formed Phillips 66 Partners, a master limited partnership (MLP), to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum product and NGL pipelines and terminals, as well as other transportation and midstream assets. At December 31, 2014, we owned a 73 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while the public owned a 25 percent limited partner interest.

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Index to Financial Statements

Headquartered in Houston, Texas, Phillips 66 Partners’ assets consist of crude oil and refined petroleum product pipeline, terminal, rail rack and storage systems in the Central, Gulf Coast, Atlantic Basin and Western regions of the United States, each of which is integral to a Phillips 66-operated refinery.

During 2014, Phillips 66 Partners expanded its business through acquisitions from us:

•

Effective March 1, 2014, Phillips 66 Partners acquired the Gold Line products system and the Medford spheres. The Gold Line products system includes a refined petroleum product pipeline system that runs from the Borger Refinery in Texas to Cahokia, Illinois. The system includes four terminals. The Medford spheres are two recently constructed refinery-grade propylene storage spheres located in Medford, Oklahoma, that connect to the Ponca City Refinery.


•	On December 1, 2014, Phillips 66 Partners acquired two newly constructed rail unloading facilities connected to the Bayway and Ferndale refineries.

Phillips 66 Partners also made several smaller acquisitions from us in late 2014, consisting of terminal and pipeline projects under development. Phillips 66 Partners is a consolidated subsidiary of Phillips 66.

Marine Vessels

At December 31, 2014, we had 13 double-hulled, international-flagged crude oil and product tankers under term charter, with capacities ranging in size from 300,000 to 1,100,000 barrels. Additionally, we had under term charter two Jones Act compliant tankers and 59 barges. These vessels are used primarily to transport feedstocks or provide product transportation for certain of our refineries, including delivery of domestic crude oil to our Gulf Coast and East Coast refineries.

Truck and Rail

Truck and rail operations support our feedstock and distribution operations. Rail movements are provided via a fleet of more than 11,400 owned and leased railcars. Truck movements are provided through approximately 150 third-party truck companies, as well as through Sentinel Transportation LLC, in which we hold an equity interest.

DCP Midstream

Our Midstream segment includes our 50 percent equity investment in DCP Midstream, which is headquartered in Denver, Colorado. As of December 31, 2014, DCP Midstream owned or operated 64 natural gas processing facilities, with a net processing capacity of approximately 7.8 BCFD. 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 67,900 miles of pipeline. DCP Midstream also owned or operated 12 NGL fractionation plants, along with natural gas and NGL storage facilities, a propane wholesale marketing business and NGL pipeline assets.

In 2014, DCP Midstream gathered, processed and/or transported an average of 7.3 trillion British thermal units (TBTU) per day of natural gas, and produced approximately 454,000 barrels per day of NGL, compared with 7.1 TBTU per day and 426,000 barrels per day in 2013.

The residual natural gas, primarily methane, which results from processing raw natural gas, is sold by DCP Midstream at market-based prices to marketers and end users, including large industrial companies, natural gas distribution companies and electric utilities. DCP Midstream purchases or takes custody of substantially all of its raw natural gas from producers, principally under contractual arrangements that expose DCP Midstream to the prices of NGL, natural gas and condensate. DCP Midstream also has fee-based arrangements with producers to provide midstream services such as gathering and processing.

DCP Midstream markets a portion of its NGL to us and CPChem under existing 15-year contracts, the primary commitment of which expired in December 2014. The contracts provide for a wind-down period which expires in January 2019, if not renegotiated or renewed. These purchase commitments are on an “if-produced, will-purchase” basis.

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Index to Financial Statements

During 2014, DCP Midstream and DCP Midstream Partners, LP (DCP Partners), the MLP formed by DCP Midstream, completed or advanced natural gas processing capacity increases in the Denver-Julesburg (DJ) and the Eagle Ford Shale basins:


•	In the DJ Basin, DCP Partners is constructing the Lucerne 2 gas processing plant, which has a planned capacity of 200 million cubic feet per day. The plant is expected to go into service in the second quarter of 2015.


•	Also in the DJ Basin, the O’Connor natural gas processing plant expansion, which increased processing capacity from 110 to 160 million cubic feet per day, was placed into service. Both the Lucerne 2 and O’Connor plants connect to the Front Range NGL pipeline, in which DCP Partners owns a one-third interest. The Front Range NGL pipeline was placed into service in the first quarter of 2014.

•

In the Eagle Ford Shale Basin, the Goliad gas processing plant was placed into service during the first quarter of 2014. The Goliad plant has a processing capacity of 200 million cubic feet per day, and its completion brought the collective natural gas processing capacity of DCP Midstream and DCP Partners in the Eagle Ford Shale Basin to 1.2 billion cubic feet per day. The Goliad plant is connected to the Sand Hills pipeline.

The Sand Hills pipeline is engaged in the business of transporting NGL and provides takeaway service from the Permian and Eagle Ford Shale basins to fractionation facilities along the Texas Gulf Coast and at the Mont Belvieu, Texas, market hub. The Southern Hills pipeline is also engaged in the business of transporting NGL and provides takeaway service from the Midcontinent to fractionation facilities at the Mont Belvieu, Texas, market hub. Phillips 66, Spectra Energy Partners, and DCP Partners each have a one-third direct interest in each of the DCP Southern Hills and DCP Sand Hills pipeline entities, the owners of these NGL pipelines.

NGL

Our NGL business includes the following:


•	A 22.5 percent equity interest in Gulf Coast Fractionators, which owns an NGL fractionation plant in Mont Belvieu, Texas. We operate the facility, and our net share of capacity is 32,625 barrels per day.


•	A 12.5 percent equity interest in a fractionation plant in Mont Belvieu, Texas. Our net share of capacity is 26,000 barrels per day.


•	A 40 percent interest in a fractionation plant in Conway, Kansas. Our net share of capacity is 43,200 barrels per day.


•	A one-third direct interest in both the DCP Sand Hills and DCP Southern Hills pipeline entities, connecting Eagle Ford, Permian and Midcontinent production to the Mont Belvieu, Texas, market.

During 2014, final Board of Directors approval was received on the Sweeny Fractionator One and Freeport LPG Export Terminal projects. These two projects represent an estimated investment of more than $3 billion as part of the company’s Midstream growth program.

The Sweeny Fractionator One is located in Old Ocean, Texas, close to our Sweeny Refinery, and will supply NGL products to the petrochemical industry and heating markets. Raw NGL supply to the fractionator is expected from nearby major pipelines, including the Sand Hills pipeline. The 100,000 barrel-per-day NGL fractionator is expected to start up in the second half of 2015.

The Freeport LPG Export Terminal is located at the site of our existing marine terminal in Freeport, Texas, and will leverage our midstream, transportation and storage infrastructure to supply petrochemical, heating and transportation markets globally. The terminal will have an initial export capacity of 4.4 million barrels per month with a ship loading rate of 36,000 barrels per hour. Startup of the export terminal is expected in the second half of 2016.

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Index to Financial Statements

Each of these projects will include NGL storage and additional pipelines with connectivity to market hubs in Mont Belvieu, Texas. Also included with these projects is a 100,000 barrel-per-day de-ethanizer unit that will be installed close to the Sweeny Refinery to upgrade domestic propane for export.

To support these facilities, we are also installing significant infrastructure, including connectivity to three NGL supply pipelines, a new salt dome storage facility with an initial 6 million barrels of underground storage (expandable to 32 million barrels) and a 180,000 barrel-per-day, bi-directional pipeline connecting Sweeny to the Mont Belvieu market center. In support of these projects, we have successfully secured long-term fee-based commitments for the majority of the feedstocks and products for Sweeny Fractionator One.

In response to the challenging market conditions driven by the recent decline in global crude oil prices, we have delayed the timing of investment decisions on a second-phase of Midstream projects in Texas, including our plans to build a second NGL fractionator, a crude and condensate pipeline, and a condensate splitter.

CHEMICALS

The Chemicals segment consists of our 50 percent equity investment in CPChem, which is headquartered in The Woodlands, Texas. At the end of 2014, CPChem owned or had joint-venture interests in 34 manufacturing facilities and two research and development centers located around the world.

CPChem’s business is structured around two primary operating segments: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P segment produces and markets ethylene and other olefin products; the ethylene produced is primarily consumed within CPChem for the production of polyethylene, normal alpha olefins and polyethylene pipe. The SA&S segment manufactures and markets aromatics products, such as benzene, styrene, paraxylene and cyclohexane, as well as polystyrene and styrene-butadiene copolymers. SA&S also manufactures and/or markets a variety of specialty chemical products including organosulfur chemicals, solvents, catalysts, drilling chemicals and mining chemicals.

The manufacturing of petrochemicals and plastics involves the conversion of hydrocarbon-based raw material feedstock into higher-value products, often through a thermal process referred to in the industry as “cracking.” For example, ethylene can be produced from cracking the feedstocks ethane, propane, butane, natural gasoline or certain refinery liquids, such as naphtha and gas oil. The produced ethylene has a number of uses, primarily as a raw material for the production of plastics, such as polyethylene and polyvinyl chloride. Plastic resins, such as polyethylene, are manufactured in a thermal/catalyst process, and the produced output is used as a further raw material for various applications, such as packaging and plastic pipe.

CPChem, including through its subsidiaries and equity affiliates, has manufacturing facilities located in Belgium, China, Colombia, Qatar, Saudi Arabia, Singapore, South Korea and the United States.

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The following table reflects CPChem’s petrochemicals and plastics product capacities at December 31, 2014:



	Millions of Pounds per Year
	U.S.	Worldwide
O&P
Ethylene	8,030	10,505
Propylene	2,675	3,180
High-density polyethylene	4,205	6,500
Low-density polyethylene	620	620
Linear low-density polyethylene	490	490
Polypropylene	—	310
Normal alpha olefins	2,115	2,630
Polyalphaolefins	105	235
Polyethylene pipe	590	590
Total O&P	18,830	25,060

SA&S
Benzene	1,600	2,530
Cyclohexane	1,060	1,455
Paraxylene	1,000	1,000
Styrene	1,050	1,875
Polystyrene	835	1,070
K-Resin^® SBC	—	70
Specialty chemicals	425	545
Polymer conversion	—	64
Total SA&S	5,970	8,609
Total O&P and SA&S	24,800	33,669

Capacities include CPChem’s share in equity affiliates and excludes CPChem’s NGL fractionation capacity.

In 2014, CPChem began the construction of a world-scale ethane cracker and polyethylene facilities in the U.S. Gulf Coast region. The project will leverage the development of the significant shale resources in the United States. CPChem’s Cedar Bayou facility, in Baytown, Texas, will be the location of the 3.3 billion-pound-per-year ethylene unit. The polyethylene facility will have two polyethylene units, each with an annual capacity of 1.1 billion pounds, and will be located near CPChem’s Sweeny facility in Old Ocean, Texas. The project is expected to be completed in 2017.

In June 2014, CPChem completed the commissioning and start-up of an on-purpose 1-hexene plant, capable of producing up to 550 million pounds per year at its Cedar Bayou facility in Baytown, Texas. 1-hexene, a normal alpha olefin, is a critical component used in the manufacturing of polyethylene, a plastic resin commonly converted into film, plastic pipe, milk jugs, detergent bottles and food and beverage containers. The new plant is the third such plant to utilize CPChem’s proprietary selective 1-hexene technology, which produces co-monomer-grade 1-hexene from ethylene with exceptional product purity.

In June 2014, CPChem’s Board of Directors approved construction to expand normal alpha olefin (NAO) production capacity at its Cedar Bayou plant in Baytown, Texas. This investment will provide an additional 220 million pounds per year of capacity. Completion of construction is anticipated in July 2015. NAO and its derivatives are used extensively as polyethylene co-monomers, synthetic motor oils, lubricants, automotive additives and in a wide range of specialty applications.

In the second quarter of 2014, CPChem completed its sulfur-based products expansion and the new on-purpose hydrogen sulfide unit project at its facility in Tessenderlo, Belgium.

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In July 2014, a localized fire occurred in the olefins unit at CPChem’s Port Arthur, Texas facility, shutting down ethylene production. The Port Arthur ethylene unit restarted in November. Because the Port Arthur ethylene unit was down due to the fire, CPChem experienced a significant reduction in production and sales in several of its product lines stemming from the lack of the Port Arthur ethylene supply.

In December 2014, CPChem completed an ethylene expansion at its Sweeny complex in Old Ocean, Texas. With the addition of a tenth furnace to ethylene unit 33 at the Sweeny complex, the expansion is expected to increase annual production by 200 million pounds per year.

During 2014, CPChem made a decision to permanently shut down the K-Resin® styrene-butadiene copolymer (SBC) plant at its Pasadena Plastics Complex in Pasadena, Texas. The plant was temporarily idled in February 2013. In December 2014, CPChem completed the sale of substantially all of the assets of its Ryton® polyphenylene sulfide (PPS) product line.

Saudi Polymers Company (SPCo), a 35-percent-owned joint venture company of CPChem, owns an integrated petrochemicals complex adjacent to S-Chem (two 50/50 SA&S joint ventures) at Jubail Industrial City, Saudi Arabia. SPCo produces ethylene, propylene, polyethylene, polypropylene, polystyrene and 1-hexene.

In association with the SPCo project, CPChem committed to build a nylon 6,6 manufacturing plant and a number of polymer conversion projects at Jubail Industrial City, Saudi Arabia. The projects are being undertaken through CPChem’s 50-percent-owned joint venture company, Petrochemical Conversion Company Ltd. The projects are slated to begin operations in stages through 2015. During 2014, commercial operations began on two polymer conversion units, polyethylene pipe and drip irrigation.

Our agreement with Chevron U.S.A. Inc. (Chevron), an indirect, wholly owned subsidiary of Chevron Corporation, regarding CPChem permits Chevron to buy our 50 percent interest in CPChem for fair market value if, at any time after the Separation, we experience a change in control or if both Standard & Poor’s Ratings Services (S&P) and Moody’s Investors Service (Moody’s) lower our credit ratings below investment grade and the credit rating from either rating agency remains below investment grade for 365 days thereafter, with fair market value determined by agreement or by nationally recognized investment banks.

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REFINING

Our Refining segment buys, sells, and refines crude oil and other feedstocks into petroleum products (such as gasolines, distillates and aviation fuels) at 14 refineries, mainly in the United States and Europe.

The table below depicts information for each of our U.S. and international refineries at December 31, 2014:



				Thousands of Barrels Daily
Region/Refinery	Location	Interest		Net Crude Throughput Capacity		Net Clean Product Capacity**		Clean Product Yield Capability
Region/Refinery	Location	Interest		At December 31 2014	Effective January 1 2015	Gasolines	Distillates	Clean Product Yield Capability
Atlantic Basin/Europe
Bayway	Linden, NJ	100.00	%	238	238	145	115	91	%
Humber	N. Lincolnshire, United Kingdom	100.00		221	221	85	115	81
Whitegate	Cork, Ireland	100.00		71	71	15	30	65
MiRO*	Karlsruhe, Germany	18.75		58	58	25	25	86
				588	588

Gulf Coast
Alliance	Belle Chasse, LA	100.00		247	247	125	120	87
Lake Charles	Westlake, LA	100.00		239	244	90	115	70
Sweeny	Old Ocean, TX	100.00		247	247	125	120	87
				733	738

Central Corridor
Wood River	Roxana, IL	50.00		157	157	75	55	81
Borger	Borger, TX	50.00		73	73	50	25	90
Ponca City	Ponca City, OK	100.00		196	203	110	90	92
Billings	Billings, MT	100.00		59	59	35	25	89
				485	492

Western/Pacific
Ferndale	Ferndale, WA	100.00		101	101	55	30	80
Los Angeles	Carson/ Wilmington, CA	100.00		139	139	80	65	89
San Francisco	Arroyo Grande/San Francisco, CA	100.00		120	120	55	60	84
				360	360
				2,166	2,178

*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.

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Primary crude oil characteristics and sources of crude oil for our refineries are as follows:



	Characteristics				Sources
	Sweet	Medium Sour	Heavy Sour	High TAN^*	United States	Canada	South America	Europe	Middle East & Africa
Bayway	l				l	l			l
Humber	l	l		l				l	l
Whitegate	l							l	l
MiRO	l	l							l
Alliance	l				l
Lake Charles	l	l	l	l	l		l		l
Sweeny	l		l	l	l		l
Wood River	l		l	l	l	l
Borger		l	l		l	l
Ponca City	l	l	l		l	l
Billings		l	l			l
Ferndale	l	l			l	l
Los Angeles		l	l	l	l	l	l		l
San Francisco	l	l	l	l	l				l

*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 refining units include a fluid catalytic cracking unit, two hydrodesulfurization units, a naphtha reformer, an alkylation unit and other processing equipment. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuels, as well as petrochemical feedstocks, residual fuel oil and home heating oil. Refined products are distributed to East Coast customers by pipeline, barge, railcar and truck. The complex also includes a 775-million-pound-per-year polypropylene plant.

Humber Refinery

The Humber Refinery is located on the east coast of England in North Lincolnshire, United Kingdom. It produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuels. Humber’s facilities encompass fluid catalytic cracking, thermal cracking and coking. The refinery has two coking units with associated calcining plants, which upgrade the heaviest part of the crude barrel and imported feedstocks into light oil products and high-value graphite and anode petroleum cokes. Humber is the only coking refinery in the United Kingdom, and a major producer of specialty graphite cokes and anode coke. Approximately 70 percent of the light oils produced in the refinery are marketed in the United Kingdom, while the other products are exported to the rest of Europe, West Africa and the United States.

Whitegate Refinery

The Whitegate Refinery is located in Cork, Ireland, and is Ireland’s only refinery. The refinery primarily produces transportation fuels, such as gasoline, diesel and fuel oil, which are distributed to the inland market, as well as being exported to international markets. In the first quarter of 2015 we sold the Bantry Bay terminal, a crude oil and products storage complex located in Bantry Bay, about 80 miles southwest of the refinery in southern Cork County.

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MiRO Refinery

The Mineraloelraffinerie Oberrhein GmbH (MiRO) Refinery, located on the Rhine River in Karlsruhe in southwest Germany, is a joint venture in which we own an 18.75 percent interest. Facilities include three crude unit trains, fluid catalytic cracking, petroleum coking and calcining, hydrodesulfurization, naphtha reformer, isomerization, ethyl tert-butyl ether and alkylation units. MiRO produces a high percentage of transportation fuels, such as gasoline and diesel fuels. Other products include petrochemical feedstocks, home heating oil, bitumen, and anode- and fuel-grade petroleum coke. Refined products are delivered to customers in southwest Germany, northern Switzerland and western Austria by truck, railcar and barge.

Gulf Coast Region

Alliance Refinery

The Alliance Refinery is located on the Mississippi River in Belle Chasse, Louisiana. The single-train facility includes fluid catalytic cracking units, alkylation, delayed coking, hydrodesulfurization units, a naphtha reformer and aromatics unit. Alliance produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuels. Other products include petrochemical feedstocks, home heating oil and anode-grade petroleum coke. The majority of the refined products are distributed to customers in the southeastern and eastern United States through major common carrier pipeline systems and by barge. Refined products are also sold into export markets through the refinery’s marine terminal.

Lake Charles Refinery

The Lake Charles Refinery is located in Westlake, Louisiana. Its facilities include fluid catalytic cracking, hydrocracking, delayed coking and hydrodesulfurization units. The refinery produces a high percentage of transportation fuels, such as low-sulfur gasoline and off-road diesel, along with home heating oil. The majority of its refined products are distributed by truck, railcar, barge or major common carrier pipelines to customers in the southeastern and eastern United States. Refined products can also be sold into export markets through the refinery’s marine terminal. Refinery facilities also include a specialty coker and calciner, which produce graphite petroleum coke for the steel industry.

Sweeny Refinery

The Sweeny Refinery is located in Old Ocean, Texas, approximately 65 miles southwest of Houston. Refinery facilities include fluid catalytic cracking, delayed coking, alkylation, a naphtha reformer and hydrodesulfurization units. The refinery receives crude oil primarily via tankers, through wholly and jointly owned terminals on the Gulf Coast, including a deepwater terminal at Freeport, Texas. It produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuels. Other products include petrochemical feedstocks, home heating oil and fuel-grade petroleum coke. We operate nearby terminals and storage facilities, along with pipelines that connect these facilities to the refinery. Refined products are distributed throughout the Midwest and southeastern United States by pipeline, barge and railcar.

MSLP

Merey Sweeny, L.P. (MSLP) owns a delayed coker and related facilities at the Sweeny Refinery. MSLP processes long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. See the “Other” section of Note 8—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for information on the ownership of MSLP.

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Central Corridor Region

WRB Refining LP (WRB)

We are the operator and managing partner of WRB, a 50/50 joint venture with Cenovus Energy Inc., which consists of the Wood River and Borger refineries.

WRB’s gross processing capability of heavy Canadian or similar crudes ranges between 235,000 and 255,000 barrels per day.


•	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. Operations include three distilling units, two fluid catalytic cracking units, alkylation, hydrocracking, two delayed coking units, naphtha reforming, hydrotreating and sulfur recovery. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuels. Other products include petrochemical feedstocks, asphalt and coke. Finished product leaves Wood River by pipeline, rail, barge and truck.


•	Borger Refinery

The Borger Refinery is located in Borger, Texas, in the Texas Panhandle, approximately 50 miles north of Amarillo. The refinery facilities encompass coking, fluid catalytic cracking, alkylation, hydrodesulfurization and naphtha reforming, and a 45,000-barrel-per-day NGL fractionation facility. It produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuels, as well as coke, NGL and solvents. Refined products are transported via pipelines from the refinery to West Texas, New Mexico, Colorado and the Midcontinent region.

Ponca City Refinery

The Ponca City Refinery is located in Ponca City, Oklahoma. Its facilities include fluid catalytic cracking, alkylation, delayed coking and hydrodesulfurization units. It produces a high percentage of transportation fuels, such as gasoline, diesel, and jet fuels, as well as LPG and anode-grade petroleum coke. Finished petroleum products are primarily shipped by company-owned and common-carrier pipelines to markets throughout the Midcontinent region.

Billings Refinery

The Billings Refinery is located in Billings, Montana. Its facilities include fluid catalytic cracking and hydrodesulfurization units, in addition to a delayed coker, which converts heavy, high-sulfur residue into higher-value light oils. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and aviation fuels, as well as fuel-grade petroleum coke. Finished petroleum products from the refinery are delivered by pipeline, railcar and truck. The pipelines transport most of the refined products to markets in Montana, Wyoming, Idaho, Utah, Colorado and Washington State.

Western/Pacific 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 a fluid catalytic cracker, an alkylation unit and a diesel hydrotreaterunit. The refinery produces transportation fuels such as gasoline and diesel fuels. Other products include residual fuel oil, which supplies the northwest marine transportation market. Most refined products are distributed by pipeline and barge to major markets in the northwest United States.

Los Angeles Refinery

The Los Angeles Refinery consists of two linked facilities located about five miles apart in Carson and Wilmington, California, approximately 15 miles southeast of Los Angeles International Airport. Carson serves as the front end of the refinery by processing crude oil, and Wilmington serves as the back end by upgrading the intermediate products to finished products. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuels. Other products include fuel-grade petroleum coke. The facilities include fluid catalytic cracking, alkylation, hydrocracking, coking, and naphtha reforming units. The refinery produces California Air Resources Board (CARB)-grade gasoline. Refined products are distributed to customers in California, Nevada and Arizona by pipeline and truck.

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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, about 200 miles south of San Francisco, California, while the Rodeo facility is in the San Francisco Bay Area. Semi-refined liquid products from the Santa Maria facility are sent by pipeline to the Rodeo facility for upgrading into finished petroleum products. The refinery produces a high percentage of transportation fuels, such as gasoline and diesel fuels. Other products include petroleum coke. Process facilities include coking, hydrocracking, hydrotreating and naphtha reforming units. It also produces CARB-grade gasoline. The majority of the refined products are distributed by pipeline, railcar and barge to customers in California.

Melaka Refinery

In December 2014, we sold our interest in the Melaka Refinery, in Melaka, Malaysia.

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, as well as power generation operations.

Marketing

Marketing—United States

In the United States, as of December 31, 2014, we marketed gasoline, diesel and aviation fuel through approximately 8,600 marketer-owned or -supplied outlets in 48 states. These sites utilize the Phillips 66, Conoco or 76 brands.

At December 31, 2014, our wholesale operations utilized a network of marketers operating approximately 7,000 outlets. We have placed a strong emphasis on the wholesale channel of trade because of its lower capital requirements. In addition, we held brand-licensing agreements with approximately 700 sites. Our refined products are marketed on both a branded and unbranded basis. A high percentage of our branded marketing sales are made in the Midcontinent, Rockies and West Coast regions, where our wholesale marketing operations provide efficient off-take from our refineries.

The Gulf Coast and East Coast regions do not require a highly integrated marketing and distribution infrastructure to secure product placement for refinery pull through. In these markets, most sales are conducted via unbranded sales. 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.

During 2013, we entered into multi-year consignment fuels agreements with several marketers. We own the fuel inventory and control the selling of fuel at the retail sites and the marketer is paid a fixed monthly fee. Also in 2013, we temporarily acquired a small number of retail sites, some of which were sold in 2013 and 2014, with the remainder expected to be sold in the future. The consignment fuels agreements and the temporary retail site acquisitions were designed to support branded pull through of our refinery production.

During 2014, we acquired a 50 percent interest in OnCue Holdings, LLC, which operated 44 convenience stores in Oklahoma as of December 31, 2014. We are evaluating growth opportunities within this joint venture.

In addition to automotive gasoline and diesel, we produce and market jet fuel and aviation gasoline, which is used by smaller piston-engine aircraft. At December 31, 2014, aviation gasoline and jet fuel were sold through dealers and independent marketers at approximately 900 Phillips 66-branded locations in the United States.

Marketing—International

We have marketing operations in five European countries. Our European marketing strategy is to sell primarily through owned, leased or joint venture retail sites using a low-cost, high-volume approach. We use the JET brand name to market retail and wholesale products in Austria, Germany and the United Kingdom. In addition, a joint venture in which we have an equity interest markets products in Switzerland under the Coop brand name.

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We also market aviation fuels, LPG, heating oils, transportation fuels, marine bunker fuels, bitumen and fuel coke specialty products to commercial customers and into the bulk or spot markets in the above countries and Ireland.

As of December 31, 2014, we had approximately 1,235 marketing outlets in our European operations, of which approximately 940 were company owned and 295 were dealer owned. In addition, through our joint venture operations in Switzerland, we have interests in 285 additional sites.

Specialties

We manufacture and sell a variety of specialty products, including petroleum coke products, waxes, solvents, and polypropylene. Certain manufacturing operations are included in the Refining segment, while the marketing function for these products is included in the Specialties business.

Premium Coke & Polypropylene

We market high-quality graphite and anode-grade petroleum cokes in the United States and Europe for use in the global steel and aluminum industries. We also market polypropylene in North America under the COPYLENE brand name.

Excel Paralubes

We own a 50 percent interest in Excel Paralubes, a joint venture which owns a hydrocracked lubricant base oil manufacturing plant located adjacent to the Lake Charles Refinery. The facility produces approximately 22,000 barrels per day of high-quality, clear hydrocracked base oils.

Lubricants

We manufacture and sell automotive, commercial and industrial lubricants which are marketed worldwide under the Phillips 66, Conoco, 76 and Kendall brands, as well as other private label brands. We also market Group II Pure Performance base oils globally as well as import and market Group III Ultra-S base oils through an agreement with Korea’s S-Oil corporation. In July 2014, we acquired Spectrum Corporation, a private label and specialty lubricants business headquartered in Memphis, Tennessee.

Other

Power Generation

In 2014, we acquired our co-venturer’s interest in Sweeny Cogeneration, L.P., which owns 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.

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DISCONTINUED OPERATIONS

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 M&S segment, for shares of Phillips 66 common stock owned by the other party. On February 25, 2014, we completed the PSPI share exchange. See Note 7—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information on this transaction.

TECHNOLOGY DEVELOPMENT

Our Technology organization focuses in three areas: 1) advanced engineering optimization for our existing businesses, 2) sustainability technologies for a changing regulatory environment, and 3) future growth opportunities. Technology creates value through evaluation of advantaged crudes, models for increasing clean product yield, and research to increase safety and reliability. Research allows Phillips 66 to be well positioned to address issues like corrosion, water consumption, and changing climate regulations, as well as to reduce risk and generate novel solutions for our growing Midstream operations.

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 the 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 generally ranked within the top 10 producers of many of its major product lines, based on average 2014 production capacity, as published by industry sources. 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. Based on the statistics published in the December 1, 2014, issue of the Oil & Gas Journal, we are one of the largest refiners of petroleum products in the United States. Worldwide, our refining capacity ranked in the top 10 among non-government-controlled companies. Elements of competition for both our Chemicals and Refining segments include product improvement, new product development, low-cost structures, and efficient manufacturing and distribution systems. In the marketing portion of the business, competitive factors include product properties and processibility, reliability of supply, customer service, price and credit terms, advertising and sales promotion, and development of customer loyalty to branded products.

GENERAL

At December 31, 2014, we held a total of 523 active patents in 50 countries worldwide, including 252 active U.S. patents. During 2014, we received 41 patents in the United States and 13 foreign patents. Included in these amounts are patents associated with our flow improver business, which is presented as discontinued operations at year-end 2013. Our products and processes generated licensing revenues of $8 million in 2014. The overall profitability of any business segment is not dependent on any single patent, trademark, license or franchise.

Company-sponsored research and development activities charged against earnings were $62 million, $69 million and $70 million in 2014, 2013 and 2012, respectively.

In support of our goal to attain zero incidents, we have implemented a comprehensive Health, Safety and Environmental (HSE) management system to support our business units in achieving 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

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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 2014 and those expected for 2015 and 2016.

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 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 adversely affect 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, petrochemical and plastics 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, NGLs, and other refinery and petrochemicals feedstocks) and the margin relative to those expenses at which we are able to sell refined and Chemicals segment products. During the last half of 2014 and other periods in recent years, the prices of feedstocks and our products have fluctuated 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 NGLs and refined, petrochemical and plastics products.


•	Availability of feedstocks and refined products and the infrastructure to transport feedstocks and refined products.


•	Local factors, including market conditions, the level of operations of other facilities in our markets, and the volume of products imported and exported.


•	Threatened or actual terrorist incidents, acts of war and other global political conditions.


•	Government regulations.


•	Weather conditions, hurricanes or other natural disasters.

The price of crude oil influences prices for refined products. We do not produce crude oil and must purchase all of the crude oil we process. Many crude oils available on the world market will not meet the quality restrictions for use in our refineries. Others are not economical to use due to excessive transportation costs or for other reasons. The prices for crude oil and refined products can fluctuate differently based on global, regional and local market conditions. In addition, the timing of the relative movement of the prices (both among different classes of refined products and among various global markets for similar refined products), as well as the overall change in refined product prices, can reduce refining margins and could have a significant impact on our refining, wholesale marketing and retail operations, revenues, operating income and cash flows. Also, crude oil supply contracts generally have market-responsive pricing provisions. We normally purchase our refinery feedstocks weeks before manufacturing and selling the refined products. Price level changes during the period between purchasing feedstocks and selling the refined products from these feedstocks could have a significant effect on our financial results. We also purchase refined products produced by others for sale to our customers. Price level changes during the periods between purchasing and selling these refined products also could have a material adverse effect on our business, financial condition and results of operations.

The price of feedstocks also influences prices for petrochemical and plastics products. Although our Chemicals segment gathers, 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 our 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 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 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 S&P and Moody’s lower our credit ratings below investment grade and the credit rating from either rating agency remains below investment grade for 365 days thereafter, with fair market value determined by agreement or by nationally recognized investment banks. As a result of these factors, a downgrade of our 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 clean up of hazardous materials and hazardous and nonhazardous wastes.


•	The dismantlement, abandonment and restoration of our properties and facilities 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 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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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 protect or repair these facilities.

Domestic and worldwide political and economic developments could damage our operations and materially reduce our profitability and cash flows.

Actions of the U.S., state, local and international governments through tax and other legislation, executive order and commercial restrictions could reduce our operating profitability both in the United States and abroad. The U.S. government can prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments could limit our ability to operate in, or gain access to, opportunities in various countries, as well as limit our ability to obtain the optimum slate of crude oil and other refinery feedstocks. Our foreign operations and those of our joint ventures are further subject to risks of loss of revenue, equipment and property as a result of expropriation, acts of terrorism, war, civil unrest and other political risks; unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities; and difficulties enforcing rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations. Our foreign operations and those of our joint ventures are also subject to fluctuations in currency exchange rates. Actions by both the United States and host governments may affect our operations significantly in the future.

Renewable fuels, alternative energy mandates and energy conservation efforts could reduce demand for refined products. Tax incentives and other subsidies can make renewable fuels and alternative energy more competitive with refined products than they otherwise might be, which may reduce refined product margins and hinder the ability of refined products to compete with renewable fuels.

Large capital projects can take many years to complete, and market conditions could deteriorate significantly between the project approval date and the project startup date, negatively impacting project returns.

To approve a large-scale capital project, the project must meet an acceptable level of return on the capital invested in the project. 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.

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 those of the joint venture or us, or our joint venture participants may be unable to meet their economic or other obligations, and we may be required to fulfill those obligations alone. Failure by us, or an entity in which we have a joint-venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.

Activities in our Chemicals and Midstream segments involve numerous risks that may result in accidents or otherwise affect the ability of our equity affiliates to make distributions to us.

There are a variety of hazards and operating risks inherent in the manufacturing of petrochemicals and the gathering, processing, transmission, storage, and distribution of natural gas and NGL, such as spills, leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in significant injury, loss of human life, damage to property, environmental pollution and impairment of operations, any of which could

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result in substantial losses. For assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. Should any of these risks materialize, it could have a material adverse effect on the business and financial condition of CPChem, DCP Midstream or REX and negatively impact their ability to make future distributions to us.

Our operations present hazards and risks, which may not be fully covered by insurance, if insured. If a significant accident or event occurs for which we are not adequately insured, our operations and financial results could be adversely affected.

The scope and nature of our operations present a variety of operational hazards and risks, including explosions, fires, toxic emissions, maritime hazards and natural catastrophes, that must be managed through continual oversight and control. For example, the operation of refineries, power plants, fractionators, pipelines, terminals and vessels is inherently subject to the risks of spills, discharges or other inadvertent releases of petroleum or hazardous substances. If any of these events had previously occurred or occurs in the future in connection with any of our refineries, pipelines or refined products terminals, or in connection with any facilities that receive our wastes or by-products for treatment or disposal, other than events for which we are indemnified, we could be liable for all costs and penalties associated with their remediation under federal, state, local and international environmental laws or common law, and could be liable for property damage to third parties caused by contamination from releases and spills. These and other risks are present throughout our operations. As protection against these hazards and risks, we maintain insurance against many, but not all, potential losses or liabilities arising from such operating risks. As such, our insurance coverage may not be sufficient to fully cover us against potential losses arising from such risks. Uninsured losses and liabilities arising from operating risks could reduce the funds available to us for capital and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

We often utilize the services of third parties to transport crude oil, NGL and refined products to and from our facilities. In addition to our own operational risks discussed above, we could experience interruptions of supply or increases in costs to deliver refined products to market if the ability of the pipelines or vessels to transport crude oil or refined products is disrupted because of weather events, accidents, governmental regulations or third-party actions. A prolonged disruption of the ability of a pipeline or vessel to transport crude oil, NGL or refined product 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 developed from unconventional sources, such as deep oil and gas shales. These reservoirs require hydraulic fracturing completion processes to release the hydrocarbons from the rock so they can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate hydrocarbon production. The U.S. Environmental Protection Agency, 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 fracking 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 and lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through DCP Midstream’s gathering systems and could reduce supplies and increase costs of NGL feedstocks to CPChem ethylene facilities. This could materially adversely affect our results of operations and the ability of DCP Midstream and CPChem to make cash distributions to us.

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Because of the natural decline in production from existing wells in DCP Midstream’s areas of operation, its 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, from which production will naturally decline 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, pricing of and the demand for natural gas and crude oil, producers’ desire and ability to obtain necessary permits in an efficient manner, natural gas field characteristics and production performance, surface access and infrastructure issues, and its ability to compete for volumes from successful new wells. If DCP Midstream is not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells or because of competition, throughput on its pipelines and the utilization rates of its treating and processing facilities would decline. This could have a material adverse effect on its business, results of operations, financial position and cash flows, and its ability to make cash distributions to us.

Competitors that produce their own supply of feedstocks, have more extensive retail outlets, or have greater financial resources may have a competitive advantage.

The refining and marketing industry is highly competitive with respect to both feedstock supply and refined product markets. We compete with many companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. We do not produce any of our crude oil feedstocks. Some of our competitors, however, obtain a portion of their feedstocks from their own production and some have more extensive retail outlets than we have. Competitors that have their own production or extensive retail outlets (and greater brand-name recognition) are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.

Some of our competitors also have materially greater financial and other resources than we have. Such competitors have a greater ability to bear the economic risks inherent in all phases of our business. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual customers.

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

We currently use commodity derivative instruments, and we expect to continue their use 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. If any of our counterparties were to default on its obligations to us under the hedging contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes. 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 LP, 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 LP, 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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A significant interruption in one or more of our facilities could adversely affect our business.

Our operations could be subject to significant interruption if one or more of our facilities were to experience a major accident, mechanical failure, or power outage, encounter work stoppages relating to organized labor issues, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any facility were to experience an interruption in operations, earnings from the facility could be materially adversely affected (to the extent not recoverable through insurance, if insured) because of lost production and repair costs. A significant interruption in one or more of our facilities could also lead to increased volatility in prices for feedstocks and refined products, and could increase instability in the financial and insurance markets, making it more difficult for us to access capital and to obtain insurance coverage that we consider adequate.

Our performance depends on the uninterrupted operation of our facilities, which are becoming increasingly dependent on our information technology systems.

Our performance depends on the efficient and uninterrupted operation of the manufacturing equipment in our production facilities. The inability to operate one or more of our facilities due to a natural disaster; power outage; labor dispute; or failure of one or more of our information technology, telecommunications, or other systems could significantly impair our ability to manufacture our products. Our manufacturing equipment is becoming increasingly dependent on our information technology systems. A disruption in our information technology systems due to a catastrophic event or security breach could interrupt or damage our operations.

Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of our business, we collect sensitive data, including personally identifiable information of our customers using credit cards at our branded retail outlets. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Although we have experienced occasional, actual or attempted breaches of our cybersecurity, none of these breaches has had a material effect on our business, operations or reputation (or compromised any customer data). Any such breaches could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of customer information, disrupt the services we provide to customers, and damage our reputation, any of which could adversely affect our business.

The level of returns on pension and postretirement plan assets and the actuarial assumptions used for valuation purposes could affect our earnings and cash flows in future periods.

Assumptions used in determining projected benefit obligations and the expected return on plan assets for our pension plan and other postretirement benefit plans are evaluated by us 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.

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In connection with the Separation, ConocoPhillips has agreed to indemnify 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 divert cash to meet those obligations and our financial results could be negatively impacted. The ConocoPhillips indemnity may not be sufficient to insure us against the full amount of liabilities for which it has been allocated responsibility, and ConocoPhillips may not be able to satisfy its indemnification obligations in the future.

Pursuant to the Indemnification and Release Agreement and certain other agreements with ConocoPhillips entered into in connection with the Separation, ConocoPhillips agreed to indemnify us for certain liabilities, and we agreed to indemnify ConocoPhillips for certain liabilities. Indemnities that we may be required to provide ConocoPhillips are not subject to any cap, may be significant and could negatively impact our business, particularly indemnities relating to our actions that could impact the tax-free nature of the distribution of Phillips 66 stock. Third parties could also seek to hold us responsible for any of the liabilities that ConocoPhillips has agreed to retain. Further, the indemnity from ConocoPhillips may not be sufficient to protect us against the full amount of such liabilities, and ConocoPhillips may not be able to fully satisfy its indemnification obligations. Moreover, even if we ultimately succeed in recovering from ConocoPhillips any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves. Each of these risks could negatively affect our business, results of operations and financial condition.

We are subject to continuing contingent liabilities of ConocoPhillips following the Separation.

Notwithstanding the Separation, there are several significant areas where the liabilities of ConocoPhillips may become our obligations. For example, under the Internal Revenue Code and the related rules and regulations, each corporation that was a member of the ConocoPhillips consolidated U.S. federal income tax reporting group during any taxable period or portion of any taxable period ending on or before the effective time of the Separation is jointly and severally liable for the U.S. federal income tax liability of the entire ConocoPhillips consolidated tax reporting group for that taxable period. In connection with the Separation, we entered into the Tax Sharing Agreement with ConocoPhillips that allocates the responsibility for prior period taxes of the ConocoPhillips consolidated tax reporting group between us and ConocoPhillips. ConocoPhillips may be unable to pay any prior period taxes for which it is responsible, and we could be required to pay the entire amount of such taxes. Other provisions of federal law establish similar liability for other matters, including laws governing tax-qualified pension plans as well as other contingent liabilities.

If the distribution in connection with the Separation, together with certain related transactions, does not qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, our stockholders and ConocoPhillips could be subject to significant tax liability and, in certain circumstances, we could be required to indemnify ConocoPhillips for material taxes pursuant to indemnification obligations under the Tax Sharing Agreement.

ConocoPhillips received a private letter ruling from the Internal Revenue Service (IRS) substantially to the effect that, among other things, the distribution, together with certain related transactions, qualified as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. The private letter ruling and the tax opinion that ConocoPhillips received relied on certain representations, assumptions and undertakings, including those relating to the past and future conduct of our business, and neither the private letter ruling nor the opinion would be valid if such representations, assumptions and undertakings were incorrect. Moreover, the private letter ruling does not address all the issues that are relevant to determining whether the distribution qualified for tax-free treatment. Notwithstanding the private letter ruling and the tax opinion, the IRS could determine the distribution should be treated as a taxable transaction for U.S. federal income tax purposes if it determines any of the representations, assumptions or 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) an acquisition of all or a portion of our stock or assets, whether by merger or otherwise, (ii) other actions or failures to act by us, or (iii) any of our representations or

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undertakings being incorrect or violated. Our indemnification obligations to ConocoPhillips and its subsidiaries, officers and directors are not limited by any maximum amount. If we are required to indemnify ConocoPhillips or such other persons under the circumstances set forth in the Tax Sharing Agreement, we may be subject to substantial liabilities.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 3. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings, including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were decided adversely to Phillips 66, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to 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), six 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

On January 5, 2015, the Bay Area Air Quality Management District (Bay Area AQMD) in California made a $262,000 demand to settle five Notices of Violation (NOVs) issued in 2012 with respect to an incident involving the release of material from a sour water tank at the Rodeo facility on June 15, 2012. We are working with the Bay Area AQMD to resolve this matter.

Matters Previously Reported

In October 2007, we received a Complaint from the EPA alleging violations of the Clean Water Act related to a 2006 oil spill at the Bayway Refinery and proposing a penalty of $156,000. We are working with the EPA and the U.S. Coast Guard to resolve this matter.

In May 2010, we received a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (LDEQ) alleging various violations of applicable air emission regulations at the Lake Charles Refinery, as well as certain provisions of the consent decree in Civil Action No. H-01-4430. In July 2014, we resolved the consent decree issues and are working with the LDEQ to resolve the remaining allegations.

In October 2011, we were notified by the Attorney General of the State of California that it was conducting an investigation into possible violations of the regulations relating to the operation of underground storage tanks at gas stations in California. On January 3, 2013, we were served with a lawsuit filed by the California Attorney General that alleges such violations. We are contesting these allegations.

In May 2012, the Illinois Attorney General’s office filed and notified us of a complaint with respect to operations at the WRB 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 yet-to-be specified amounts for fines and penalties. We are working with the Illinois Environmental Protection Agency and Attorney General’s office to resolve these allegations.

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In October 2012, the Bay Area AQMD issued a $313,000 demand to settle 13 NOVs issued in 2010 and 2011 with respect to alleged violations of regulatory and/or permit requirements at the Rodeo Refinery. We are working with the Bay Area AQMD to resolve this matter.

In July 2014, Phillips 66 received a NOV from the EPA alleging various flaring-related violations between 2009 and 2013 at the Wood River Refinery. We are working with the EPA to resolve these allegations.

In July 2014, the Bay Area AQMD issued a $175,000 demand to settle 18 NOVs issued in 2010 with respect to alleged violations of regulatory and/or permit requirements at the Rodeo Refinery. We are working with the Bay Area AQMD to resolve this matter.

In July 2014, the Bay Area AQMD issued a $259,000 demand to settle 20 NOVs issued in 2011 with respect to alleged violations of regulatory and/or permit requirements at the Rodeo Refinery. We are working with the Bay Area AQMD to resolve this matter.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

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EXECUTIVE OFFICERS OF THE REGISTRANT



Name	Position Held	Age*

Greg C. Garland	Chairman and Chief Executive Officer	57
Tim G. Taylor	President	61
Robert A. Herman	Executive Vice President, Midstream	55
Paula A. Johnson	Executive Vice President, Legal, General Counsel and Corporate Secretary	51
Greg G. Maxwell	Executive Vice President, Finance and Chief Financial Officer	58
Lawrence M. Ziemba	Executive Vice President, Refining	59
Chukwuemeka A. Oyolu	Vice President and Controller	45
*On February 13, 2015.

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 after serving as Chairman, President and Chief Executive Officer from April 2012 to June 2014. Mr. Garland was appointed Senior Vice President, Exploration and Production—Americas for ConocoPhillips in October 2010, having previously served as President and Chief Executive Officer of CPChem since 2008.

Tim G. Taylor is the President of Phillips 66 after serving as Executive Vice President, Commercial, Marketing, Transportation and Business Development from April 2012 to June 2014. Mr. Taylor retired as Chief Operating Officer of CPChem in 2011. Prior to this, Mr. Taylor served at CPChem as Executive Vice President, Olefins and Polyolefins from 2008 to 2011.

Robert A. Herman is Executive Vice President, Midstream for Phillips 66, a position he has held since June 2014. Previously, Mr. Herman served Phillips 66 as 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. Mr. Herman worked for ConocoPhillips as Vice President, Health, Safety, and Environment, from 2010 to 2012; and President, Refining, Marketing and Transportation - Europe, from 2008 to 2010.

Paula A. Johnson is Executive Vice President, Legal, General Counsel and Corporate Secretary of Phillips 66, a position she has held since May 2013. Previously, Ms. Johnson served as Senior Vice President, Legal, General Counsel and Corporate Secretary of Phillips 66 since April 2012. Ms. Johnson served as Deputy General Counsel, Corporate, and Chief Compliance Officer of ConocoPhillips since 2010. Prior to this, she served as Deputy General Counsel, Corporate from 2009 to 2010.

Greg G. Maxwell is Executive Vice President, Finance and Chief Financial Officer of Phillips 66, a position he has held since April 2012. Mr. Maxwell retired as CPChem’s Senior Vice President, Chief Financial Officer and Controller in 2012, a position held since 2003.

Lawrence M. Ziemba is Executive Vice President, Refining of Phillips 66, a position he has held since February 2014. Prior to this, Mr. Ziemba served Phillips 66 as Executive Vice President, Refining, Projects and Procurement since April 2012. Mr. Ziemba served as President, Global Refining, at ConocoPhillips since 2010, and as President, U.S. Refining, from 2003 to 2010.

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 until February 2014 when he became General Manager, Planning and Optimization. Prior to this Mr. Oyolu worked for ConocoPhillips as Manager, Downstream Finance, from 2009 until April 2012.

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PART II


Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Quarterly Common Stock Prices and Cash Dividends Per Share

Phillips 66’s common stock is traded on the New York Stock Exchange (NYSE) under the symbol “PSX.” The following table reflects intraday high and low sales prices of, and dividends declared on, our common stock for each quarter presented:



	Stock Price
	High		Low	Dividends
2014
First Quarter	$	80.39	68.78	.3900
Second Quarter	87.05		76.18	.5000
Third Quarter	87.98		78.53	.5000
Fourth Quarter	82.00		64.02	.5000

2013
First Quarter	$	70.52	50.12	.3125
Second Quarter	70.20		56.13	.3125
Third Quarter	61.97		54.80	.3125
Fourth Quarter	77.29		56.50	.3900

Issuer Purchases of Equity Securities



					Millions of Dollars
Period	Total Number of Shares Purchased*	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs**	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs

October 1-31, 2014	2,439,453	$	75.86	2,439,453	$	2,463
November 1-30, 2014	1,988,000	74.97		1,988,000	2,314
December 1-31, 2014	2,795,241	70.81		2,795,241	2,116
Total	7,222,694	$	73.66	7,222,694

*Includes repurchase of shares of common stock from company employees in connection with the company’s broad-based employee incentive plans, when applicable.

**During 2012 and 2013, our Board of Directors authorized the repurchase of up to $5 billion of our outstanding common stock. We began purchases under this authorization, which has no expiration date, in the third quarter of 2012. In July 2014, our Board of Directors approved the repurchase of an additional $2 billion of our outstanding common stock. The share repurchases are expected to be funded primarily through available cash. The shares under these authorizations 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.

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Item 6. SELECTED FINANCIAL DATA

For periods prior to the Separation, the following selected financial data consisted of the combined operations of the downstream businesses of ConocoPhillips. All financial information presented for periods after the Separation represents the consolidated results of operations, financial position and cash flows of Phillips 66. Accordingly:

•

The selected income statement data for the years ended December 31, 2014 and 2013, consist entirely of the consolidated results of Phillips 66. The selected income statement data for the year ended December 31, 2012, consists of the consolidated results of Phillips 66 for the eight months ended December 31, 2012, and of the combined results of the downstream businesses for the four months ended April 30, 2012. The selected income statement data for the years ended December 31, 2011, and 2010, consist entirely of the combined results of the downstream businesses.


•	The selected balance sheet data at December 31, 2014, 2013 and 2012, consist of the consolidated balances of Phillips 66, while the selected balance sheet data at December 31, 2011 and 2010, consist of the combined balances of the downstream businesses.



	Millions of Dollars Except Per Share Amounts
	2014		2013	2012	2011	2010

Sales and other operating revenues	$	161,212	171,596	179,290	195,931	146,433
Income from continuing operations	4,091		3,682	4,083	4,737	710
Income from continuing operations attributable to Phillips 66	4,056		3,665	4,076	4,732	705
Per common share
Basic	7.15		5.97	6.47	7.54	1.13
Diluted	7.10		5.92	6.40	7.45	1.12
Net income	4,797		3,743	4,131	4,780	740
Net income attributable to Phillips 66	4,762		3,726	4,124	4,775	735
Per common share*
Basic	8.40		6.07	6.55	7.61	1.17
Diluted	8.33		6.02	6.48	7.52	1.16
Total assets	48,741		49,798	48,073	43,211	44,955
Long-term debt	7,842		6,131	6,961	361	388
Cash dividends declared per common share	1.8900		1.3275	0.4500	—	—

*See Note 13—Earnings Per Share, in the Notes to Consolidated Financial Statements.

Prior period amounts have been recast to reflect discontinued operations.

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.

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis is the company’s analysis of its financial performance, financial condition, and significant trends that may affect future performance. It should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 64.

The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss) attributable to Phillips 66.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

Phillips 66 is an energy manufacturing and logistics company with midstream, chemicals, refining, and marketing and specialties businesses. At December 31, 2014, we had total assets of $48.7 billion.

The Separation

On April 4, 2012, the ConocoPhillips Board of Directors approved the separation of its downstream businesses into an independent, publicly traded company named Phillips 66. In accordance with the Separation and Distribution Agreement, the two companies were separated by ConocoPhillips distributing to its stockholders all 625,272,302 shares of common stock of Phillips 66 after the market closed on April 30, 2012 (the Separation). Each ConocoPhillips stockholder received one share of Phillips 66 stock for every two shares of ConocoPhillips stock. Following the Separation, ConocoPhillips retained no ownership interest in Phillips 66, and each company has separate public ownership, boards of directors and management.

Executive Overview

In 2014, we reported earnings of $4.8 billion, generated $3.5 billion in cash from operating activities, and received $1.2 billion from asset dispositions, primarily reflecting the sale of our interest in the Malaysian Refining Company Sdn. Bdh. (MRC) and a special distribution from WRB Refining. We used available cash primarily to fund capital expenditures and investments of $3.8 billion, pay dividends of $1.1 billion, repurchase $2.3 billion of our common stock and finance $450 million of the Phillips Specialty Products Inc. (PSPI) share exchange. We issued $2.5 billion of debt, and ended 2014 with $5.2 billion of cash and cash equivalents and approximately $4.9 billion of total capacity under our available liquidity facilities.

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We continue to focus on the following strategic priorities:

•

Maintain strong operating excellence. Safety and reliability are our first priority, and 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. We actively monitor these costs using various methodologies that are reported to senior management. 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 2014, our worldwide refining crude oil capacity utilization rate was 94 percent, compared with 93 percent in 2013.

•

Deliver profitable growth. We have budgeted $4.6 billion in capital expenditures and investments in 2015. Including our share of expected capital spending by joint ventures DCP Midstream, LLC (DCP Midstream), Chevron Phillips Chemical Company (CPChem) and WRB, our total 2015 capital program is expected to be $6.7 billion. This program is designed primarily to grow our Midstream and Chemicals segments, which have planned expansions for manufacturing and logistics capacity. The need for additional new gathering and processing, pipeline, storage and distribution infrastructure–driven by domestic unconventional crude oil, natural gas liquids (NGL) and natural gas production–is creating capital investment opportunities in our Midstream business. Over the next few years, CPChem plans significant reinvestment of its earnings to build additional processing capacity benefiting from lower-cost NGL feedstocks. We continue to focus on funding the most attractive growth opportunities across our portfolio.

In 2013, we formed Phillips 66 Partners, a master limited partnership, to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum product and NGL pipelines and terminals, as well as other transportation and midstream assets. Its assets consist of crude oil and refined petroleum product pipeline, terminal and storage systems in the Central and Gulf Coast regions of the United States, as well as two crude oil rail-unloading facilities located at or adjacent to our Bayway and Ferndale refineries.

•

Enhance returns. We plan to improve refining returns through greater use of advantaged feedstocks, disciplined capital allocation and portfolio optimization. We expect to drive higher returns in Marketing and Specialties (M&S) by selling finished products to higher-margin export markets. A disciplined capital allocation process ensures that we focus investments in projects that generate competitive returns throughout the business cycle. During 2014, 94 percent of the company's U.S. crude slate was advantaged, compared with 74 percent in 2013.

•

Grow shareholder distributions. We believe shareholder value is enhanced through, among other things, consistent and ongoing growth of regular dividends, supplemented by share repurchases. We increased our dividend rate by 28 percent during 2014, and it has more than doubled since the Separation. Regular dividends demonstrate the confidence our management has in our capital structure and its capability to generate free cash flow throughout the business cycle. Cumulatively through December 31, 2014, we have repurchased $4.9 billion, or approximately 73.2 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.

•

Build on a high-performing organization. We strive to attract, train, develop and retain individuals with the knowledge and skills to implement our business strategy and who support our values and ethics. 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 of thought, and creating a great place to work. We foster an environment of learning and development through structured programs focused on building functional and technical skills where employees are engaged in our business and committed to their own, as well as the company’s, success.

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Business Environment

The Midstream segment includes our 50 percent equity investment in DCP Midstream. Earnings of DCP Midstream are closely linked to NGL prices, natural gas prices and crude oil prices. Industry NGL annual average prices decreased from 2012 to 2013 and again from 2013 to 2014, due to relatively higher inventories driven by growing NGL production from liquids-rich shale plays with limited corresponding domestic demand increase from the petrochemical industry and constrained export capacity. Natural gas prices increased from 2012 to 2013, and continued to increase from 2013 to 2014. The increase in both periods reflected concerns over increasingly lower industry inventory levels, due to steep inventory draws in 2013 and 2014, as well as domestic pipeline constraints.

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 market factors. The chemicals and plastics industry continued to experience higher ethylene margins in regions of the world where production is based upon NGL versus crude-derived feedstocks. In particular, companies with North American ethane-based crackers benefited from the lower-priced feedstocks and improved ethylene margins, as well as improved margins for polyethylene and other ethylene derivatives.

Results for our Refining segment depend largely on refining margins, cost control, refinery throughput, and product yields. The crack spread is a measure of the difference between market prices for refined petroleum products and crude oil, and it is used within our industry as an indicator for refining margins. The U.S. 3:2:1 crack spread (three barrels of crude oil producing two barrels of gasoline and one barrel of diesel) decreased from 2012 to 2013. However, for the first three quarters of 2014, the U.S. crack spread improved over 2013, primarily resulting from increased access to advantaged crude runs and a decrease in imports. Midcontinent refiners were especially strong, which was attributed to the region’s crude feedstock advantage. The decrease in U.S. crack spreads during the fourth quarter of 2014 was significant enough to drive the annual domestic industry average for 2014 lower than 2013. This decrease was largely due to gasoline prices falling faster than crude prices, resulting in a tighter margin.

U.S. crude production continues to increase and nationwide growth is benefiting from slower decline rates in legacy production areas, as well as improved drilling efficiency. Limited infrastructure for takeaway options resulted in favorable feedstock prices for U.S. refiners with access to advantaged crudes. Midcontinent refiners were especially advantaged. Sustained pressure on inventories and lack of local gathering infrastructure in the Midcontinent caused West Texas Intermediate (WTI) crude to continue trading at a discount relative to crudes such as Light Louisiana Sweet (LLS) and Brent during 2014. Refineries capable of processing WTI crude and crude oils that price relative to WTI, primarily the Midcontinent and Gulf Coast refineries, benefited from these lower regional feedstock prices. The spread between WTI and Brent narrowed considerably over the year, stemming from increased pipeline outlets from Cushing to the Gulf Coast, as well as the gradual over supply of light crude in the Atlantic basin.

The Northwest Europe benchmark crack spread decreased from 2012 to 2013. In 2014, the crack spread increased in the first three quarters of the year and then declined in the fourth quarter, resulting in an average decrease in 2014 compared to 2013. The decline in benchmark crack spread was due to lower European domestic and export product demand on weak refinery economics while large volumes of imported diesel from the United States, India, Asia Pacific and Russia kept prices under pressure. Weak domestic European demand and reduced export markets for gasoline compounded the declining product crack spreads.

Results for our M&S segment depend largely on marketing fuel margins, lubricant margins and other specialty product margins. These margins are primarily based on market factors, largely determined by the relationship between demand and supply. Marketing fuel margins are primarily determined by the trend of the spot prices for refined products. Generally, 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. Crude oil prices declined significantly during 2014, which resulted in the expected benefit to marketing margins.

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RESULTS OF OPERATIONS

Basis of Presentation

See Note 1—Separation and Basis of Presentation, in the Notes to Consolidated Financial Statements, for information on the basis of presentation of our financial information that affects the comparability of financial information for periods before and after the Separation.


•	We moved two of our equity investments, Excel Paralubes and Jupiter Sulphur, LLC, as well as the commission revenues related to needle and anode coke, polypropylene and solvents, from the Refining segment to the M&S segment.


•	We moved several refining logistics projects from the Refining segment to the Midstream Segment.

The new segment alignment is presented for the periods ending December 31, 2014, with prior periods recast for comparability.

Consolidated Results

A summary of the company’s earnings follows:



	Millions of Dollars
	Year Ended December 31
	2014			2013		2012

Midstream	$	507		469		52
Chemicals	1,137			986		823
Refining	1,771			1,747		3,091
Marketing and Specialties	1,034			894		544
Corporate and Other	(393		)	(431	)	(434	)
Discontinued Operations	706			61		48
Net income attributable to Phillips 66	$	4,762		3,726		4,124

2014 vs. 2013

Our earnings increased $1,036 million, or 28 percent, in 2014, primarily resulting from:


•	Recognition of a noncash $696 million after-tax gain related to the PSPI share exchange.


•	A gain on disposition and related deferred tax adjustment associated with the sale of MRC, together totaling $369 million after-tax.


•	Improved ethylene and polyethylene margins in our Chemicals segment.


•	Improved worldwide marketing margins.


•	Recognition in 2014 of $126 million, after-tax, of the previously deferred gain related to the sale in 2013 of the Immingham Combined Heat and Power Plant (ICHP).


•	Improved secondary products margins in our Refining segment.

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These increases were partially offset by:


•	A $131 million after-tax impairment related to the Whitegate Refinery in Cork, Ireland.


•	Lower realized gasoline and distillate margins as a result of decreased market crack spreads and lower feedstock advantage.


•	Lower equity earnings from DCP Midstream, reflecting the sharp drop in NGL and crude oil prices in the second half of 2014.

2013 vs. 2012

Our earnings decreased $398 million, or 10 percent, in 2013, primarily resulting from a 26 percent decrease in realized refining margins as a result of decreased market crack spreads and impacts related to lower feedstock advantage.

This decrease was partially offset by:


•	Lower impairment expense in 2013. We recorded impairments related to our equity investments in MRC, a refining company in Melaka, Malaysia, and Rockies Express Pipeline LLC (REX), a natural gas transmission system, in 2012.


•	Improved worldwide marketing margins.


•	Lower CPChem interest expense and costs resulting from its early debt retirements in 2012.

See the “Segment Results” section for additional information on our segment results.

Income Statement Analysis

2014 vs. 2013

Sales and other operating revenues decreased 6 percent in 2014, while purchased crude oil and products decreased 8 percent. The decreases were primarily due to lower average prices for crude oil and petroleum products.

Equity in earnings of affiliates decreased 20 percent in 2014, primarily resulting from decreased earnings from WRB and DCP Midstream, partially offset by increased equity earnings from CPChem.


•	Equity in earnings of WRB decreased 69 percent, mainly due to lower refining margins in the Central Corridor as a result of lower market crack spreads and a lower feedstock advantage, as well as lower interest income received from equity affiliates.


•	Equity in earnings of DCP Midstream decreased 36 percent, primarily due to a decrease in most commodity prices, as well as increased costs associated with planned asset growth.


•	Equity in earnings of CPChem increased 20 percent, primarily driven by improved ethylene and polyethylene realized margins related to increased sales prices.

Net gain on dispositions in 2014 were $295 million, compared with $55 million in 2013, primarily resulting from net gains associated with the sale of our interest in MRC in the amount of $145 million, as well as the partial recognition of the previously deferred gain related to the sale of ICHP in the amount of $126 million. In 2013, net gain on dispositions primarily resulted from a $48 million gain on the sale of our E-Gas^TMTechnology business. For additional information, see Note 7—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Selling, general and administrative expenses increased 13 percent in 2014, primarily due to additional fees under marketing consignment fuels agreements, as well as costs associated with acquisitions.

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Impairments in 2014 were $150 million, compared with $29 million in 2013. In 2014, we recorded a $131 million impairment of the Whitegate Refinery. For additional information, see Note 11—Impairments, in the Notes to Consolidated Financial Statements.

See Note 22—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rates.

Income from discontinued operations increased $645 million in 2014, compared to 2013, due to the completion of the PSPI share exchange in 2014. See Note 7—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information on this transaction.

2013 vs. 2012

Sales and other operating revenues and purchased crude oil and products both decreased 4 percent in 2013. The decreases were primarily due to lower average prices for crude oil and petroleum products.

Equity in earnings of affiliates decreased 2 percent in 2013, primarily resulting from decreased earnings from WRB, partially offset by increased equity earnings from CPChem.


•	Equity in earnings of WRB decreased 21 percent, mainly due to lower refining margins in the Central Corridor as a result of lower market crack spreads.

•

Equity in earnings of CPChem increased 14 percent, primarily driven by the absence of costs and interest associated with CPChem's early retirement of debt in 2012, improved realized margins, higher equity earnings from CPChem's equity affiliates and the absence of 2012 fixed asset impairments. These increases were partially offset by lower olefins and polyolefins sales volumes related to ethylene outages. In addition, increased turnaround and maintenance activity resulted in lower volumes and higher costs.

Net gain on dispositions decreased 72 percent in 2013, primarily resulting from a net gain associated with the sale of the Trainer Refinery and associated terminal and pipeline assets in 2012, compared with a gain resulting from the sale of our E-Gas^TM Technology business in 2013. For additional information, see Note 7—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Selling, general and administrative expenses decreased 13 percent in 2013, primarily due to costs associated with the Separation and costs relating to a prior retail disposition program in 2012.

Impairments in 2013 were $29 million, compared with $1,158 million in 2012. Impairments in 2012 included our investments in MRC and REX; a marine terminal and associated assets; and equipment formerly associated with the canceled Wilhelmshaven Refinery (WRG) upgrade project. For additional information, see Note 11—Impairments, in the Notes to Consolidated Financial Statements.

See Note 22—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rates.

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Segment Results

Midstream



	Year Ended December 31
	2014		2013	2012
	Millions of Dollars
Net Income (Loss) Attributable to Phillips 66
Transportation	$	233	199	(210	)
DCP Midstream	135		210	179
NGL	139		60	83
Total Midstream	$	507	469	52

	Dollars Per Unit
Weighted Average NGL Price*
DCP Midstream (per barrel)	$	37.43	37.84	34.24
DCP Midstream (per gallon)	0.89		0.90	0.82

*Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by NGL component and location mix.



	Thousands of Barrels Daily
Transportation Volumes
Pipelines*	3,206	3,144	2,880
Terminals	1,683	1,274	1,169
Operating Statistics
NGL extracted**	454	426	402
NGL fractionated***	109	115	105

*Pipelines represent the sum of volumes transported through each separately tariffed pipeline segment, including our share of equity volumes from Yellowstone Pipe Line Company and Lake Charles Pipe Line Company.

**Includes 100 percent of DCP Midstream’s volumes.

***Excludes DCP Midstream.

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract NGL from the raw gas stream. The remaining “residue” gas is marketed to electric utilities, industrial users and gas marketing companies. Most of the NGLs are fractionated—separated into individual components such as ethane, propane and butane—and marketed as chemical feedstock, fuel or blendstock. In addition, the Midstream segment includes U.S. transportation, pipeline, terminaling, and refining logistics services associated with the movement of crude oil, refined and specialty products, natural gas and NGL, as well as NGL fractionation, trading, and marketing businesses in the United States. The Midstream segment includes our 50 percent equity investment in DCP Midstream and the consolidated results of Phillips 66 Partners LP.

2014 vs. 2013

Earnings from the Midstream segment increased $38 million in 2014, compared with 2013. The improvement was primarily driven by higher earnings from our Transportation and NGL businesses, partially offset by lower earnings from DCP Midstream.

Transportation earnings increased $34 million in 2014, compared with 2013. This increase primarily resulted from increased throughput fees, as well as higher earnings associated with railcar activity in 2014. These increases were partially offset by higher earnings attributable to noncontrolling interests, reflecting the contribution of previously wholly owned assets to Phillips 66 Partners.

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The $75 million decrease in earnings of DCP Midstream in 2014 primarily resulted from a decrease in NGL and crude prices in the latter part of 2014. NGL and crude prices have continued to decline in the early part of 2015. In addition, earnings decreased as costs associated with asset growth and maintenance increased in 2014, compared with 2013. Earnings further declined due to DCP Midstream’s contribution of assets to its publicly traded master limited partnership, DCP Partners. Following the contribution, a percentage of the earnings from these assets are attributable to public unitholders, thus decreasing income attributable to DCP Midstream and, thereby, Phillips 66. See the “Business Environment and Executive Overview” section for additional information on market factors impacting DCP Midstream’s results.

DCP Partners issues, from time to time, limited partner units to the public. These issuances benefited our equity in earnings from DCP Midstream, on an after-tax basis, by approximately $45 million in 2014, compared with approximately $62 million in 2013.

The NGL business had an increase in earnings of $79 million, compared with 2013. The increase was primarily due to improved margins driven by strong propane prices in early 2014. Additionally, 2014 earnings benefited from gains related to seasonal propane and butane storage activity. Also, earnings improved due to higher equity earnings from the DCP Sand Hills and DCP Southern Hills pipeline entities. These increases were partially offset by an increase in costs associated with growth projects.

2013 vs. 2012

Earnings from the Midstream segment increased $417 million in 2013, compared with 2012. The improvement was primarily driven by higher earnings from our Transportation business and DCP Midstream, partially offset by lower earnings from NGL.

Transportation earnings increased $409 million in 2013, compared with 2012. These increases primarily resulted from lower impairments in 2013, as well as increased throughput fees. In 2012, we recorded impairments totaling $303 million after-tax on our equity investment in REX, primarily reflecting a diminished view of fair value of west-to-east natural gas transmission, due to the impact of shale gas production in the northeast. For additional information on the REX impairment, see Note 11—Impairments, in the Notes to Consolidated Financial Statements. Throughput fees were higher in 2013, primarily due to the implementation of market-based intersegment transfer prices for transportation and terminaling services during 2013.

The $31 million increase in earnings of DCP Midstream in 2013 primarily resulted from an increase in gains associated with unit issuances by DCP Partners, as described below. In addition, higher natural gas and crude oil prices benefitted earnings. These increases were partially offset by lower NGL prices and higher interest expense.

DCP Partners unit issuances benefited our equity in earnings from DCP Midstream, on an after-tax basis, by approximately $62 million in 2013, compared with approximately $24 million in 2012.

NGL decreased $23 million in 2013, compared with 2012. The decrease was primarily due to inventory impacts, reflecting inventory reductions in 2012 in anticipation of the Separation, which caused liquidations of LIFO inventory values.

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Chemicals



	Year Ended December 31
	2014			2013	2012
	Millions of Dollars

Net Income Attributable to Phillips 66	$	1,137		986	823

	Millions of Pounds
CPChem Externally Marketed Sales Volumes*
Olefins and Polyolefins	16,815			16,071	14,967
Specialties, Aromatics and Styrenics	6,294			6,230	6,719
	23,109			22,301	21,686
*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)	88		%	88	93

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. CPChem’s business is structured around two primary operating segments: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P segment produces and markets ethylene and other olefin products; ethylene produced is primarily consumed within CPChem for the production of polyethylene, normal alpha olefins and polyethylene pipe. The SA&S segment manufactures and markets aromatics products, such as benzene, styrene, paraxylene and cyclohexane, as well as polystyrene and styrene-butadiene copolymers. 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.

2014 vs. 2013

Earnings from the Chemicals segment increased $151 million, or 15 percent, in 2014, compared with 2013. The increase in earnings was primarily driven by improved ethylene and polyethylene realized margins due to higher sales prices. Additionally, Chemicals benefited from higher equity earnings from CPChem’s O&P equity affiliates.

These increases were partially offset by lower ethylene and polyethylene sales volumes and increased costs related to the Port Arthur facility fire. In addition, impairments of $69 million after-tax in 2014 further offset a portion of the increase to earnings. See the “Business Environment and Executive Overview” section for information on market factors impacting CPChem’s results.

In July 2014, a localized fire occurred in the olefins unit at CPChem’s Port Arthur, Texas facility, shutting down ethylene production. The Port Arthur ethylene unit restarted in November. CPChem incurred, on a 100 percent basis, $85 million of associated repair and rebuild costs. Because the Port Arthur ethylene unit was down due to the fire, CPChem experienced a significant reduction in production and sales in several of its product lines stemming from the lack of the Port Arthur ethylene supply. CPChem’s property damage and business interruption insurance coverage limited the potential extent of the financial impact. In the fourth quarter of 2014, CPChem reached an agreement with insurers and recognized into income $120 million related to advanced payments against its business interruption insurance claim.

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2013 vs. 2012

CPChem continued to benefit from price-advantaged NGL feedstocks in 2013 due to the location of its manufacturing facilities in the U.S. Gulf Coast and Middle East. Earnings from the Chemicals segment increased $163 million, or 20 percent, in 2013, compared with 2012. The increase in earnings was primarily driven by:


•	Lower costs and interest associated with CPChem’s 2012 early retirement of $1 billion of debt.


•	Improved polyethylene realized margins.


•	Higher equity earnings from CPChem’s equity affiliates, reflecting increased volumes and margins.


•	Lower asset impairments.

These increases were partially offset by lower olefins sales volumes related to ethylene outages. In addition, increased turnaround and maintenance activity resulted in lower volumes and higher costs.

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Refining



	Year Ended December 31
	2014			2013	2012
	Millions of Dollars
Net Income (Loss) Attributable to Phillips 66
Atlantic Basin/Europe	$	203		27	545
Gulf Coast	250			59	491
Central Corridor	942			1,481	2,257
Western/Pacific	306			44	(385	)
Other Refining	70			136	183
Worldwide	$	1,771		1,747	3,091

	Dollars Per Barrel
Refining Margins
Atlantic Basin/Europe	$	8.65		6.87	9.28
Gulf Coast	7.50			6.04	8.29
Central Corridor	15.26			18.62	26.37
Western/Pacific	8.22			8.20	11.04
Worldwide	9.93			9.90	13.35

	Thousands of Barrels Daily
Operating Statistics
Refining operations*
Atlantic Basin/Europe
Crude oil capacity	588			588	588
Crude oil processed	554			546	555
Capacity utilization (percent)	94		%	93	94
Refinery production	605			578	599
Gulf Coast
Crude oil capacity	733			733	733
Crude oil processed	676			651	657
Capacity utilization (percent)	92		%	89	90
Refinery production	771			736	743
Central Corridor
Crude oil capacity	485			477	470
Crude oil processed	475			472	454
Capacity utilization (percent)	98		%	99	97
Refinery production	494			489	471
Western/Pacific
Crude oil capacity	440			440	439
Crude oil processed	403			410	398
Capacity utilization (percent)	92		%	93	91
Refinery production	435			445	419
Worldwide
Crude oil capacity	2,246			2,238	2,230
Crude oil processed	2,108			2,079	2,064
Capacity utilization (percent)	94		%	93	93
Refinery production	2,305			2,248	2,232
*Includes our share of equity affiliates.

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The Refining segment buys, sells and refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels) at 14 refineries, mainly in the United States and Europe.

2014 vs. 2013

Earnings for the Refining segment were $1,771 million in 2014, an increase of $24 million, or 1 percent, compared with 2013. The slight increase in earnings in 2014 was primarily due to higher realized refining margins related to secondary products, as well as increased volumes. In addition, earnings were impacted by a gain on disposition and a related deferred tax adjustment associated with the sale of MRC, together totaling $369 million after-tax.

These increases were mostly offset by:


•	Lower earnings from decreased gasoline and distillate margins.


•	Negative impacts due to inventory draws in a declining price environment.


•	Impairment of the Whitegate Refinery of $131 million after-tax.


•	Lower interest income received from equity affiliates.

See the “Business Environment and Executive Overview” 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 94 percent in 2014, compared to 93 percent in 2013. The increase reflects lower unplanned downtime related to power outages that were experienced in the Gulf Coast region in 2013.

2013 vs. 2012

Earnings for the Refining segment were $1,747 million in 2013, a decrease of $1,344 million, or 43 percent, compared with 2012. The decrease in earnings in 2013 was primarily due to lower realized refining margins as a result of a 16 percent reduction in market cracks and impacts related to lower feedstock advantage. In addition to margins, refining results were also impacted by a $104 million after-tax gain from the sale of the Trainer Refinery and associated terminal and pipeline assets in 2012. These decreases were partially offset by reduced impairments recorded in 2012, primarily related to MRC and WRG.

Our worldwide refining crude oil capacity utilization rate was 93 percent in both 2013 and 2012, as the lack of weather disruptions were offset by higher turnaround activities.

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Marketing and Specialties



	Year Ended December 31
	2014		2013	2012
	Millions of Dollars
Net Income Attributable to Phillips 66
Marketing and Other	$	836	688	275
Specialties	198		206	269
Total Marketing and Specialties	$	1,034	894	544

	Dollars Per Barrel
Realized Marketing Fuel Margin*
U.S.	$	1.51	1.21	0.87
International	5.22		4.36	4.17
*On third-party petroleum products sales.

	Dollars Per Gallon
U.S. Average Wholesale Prices*
Gasoline	$	2.72	2.88	3.00
Distillates	2.95		3.10	3.19
*Excludes excise taxes.

	Thousands of Barrels Daily
Marketing Petroleum Products Sales
Gasoline	1,195		1,174	1,101
Distillates	979		967	985
Other	17		17	17
	2,191		2,158	2,103

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.

2014 vs. 2013

Earnings from the M&S segment increased $140 million, or 16 percent, in 2014, compared with 2013. See the “Business Environment and Executive Overview” section for information on marketing fuel margins and other market factors impacting this year’s results.

Both U.S. and international marketing margins benefited from the timing effect of falling gasoline prices experienced in the second half of 2014. U.S. marketing also benefited from a full year of consignment agreements entered into in 2013, while international marketing margins also benefited from foreign exchange gains in 2014.

In July 2013, we completed the sale of ICHP, and deferred the gain from the sale due to an indemnity provided to the buyer. In 2014, we recognized $126 million after-tax of the previously deferred gain, increasing earnings. These increases were partially offset by the lack of ICHP earnings in 2014, compared with earnings of $53 million in 2013.

Looking forward, absent claims under the ICHP indemnity, we expect the remaining deferred gain at December 31, 2014, of $243 million to be recognized in M&S’s earnings in the first and second quarters of 2015. In addition, if the spot prices of gasoline stabilize or begin to increase in 2015, we would expect a reduction in M&S’s margins in 2015, relative to 2014.

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2013 vs. 2012

Earnings from the M&S segment increased $350 million, or 64 percent, in 2013, compared with 2012.

During 2013, U.S. marketing margins benefited from higher Renewable Identification Numbers (RINs) values associated with renewable fuels blending activities, particularly during the first three quarters. RIN prices decreased during the fourth quarter, as concerns over their availability eased somewhat based on anticipated actions by the U.S. Environmental Protection Agency. The increased RIN prices offset weaker underlying components of our U.S. marketing margins during 2013.

M&S earnings benefited from higher international marketing margins in 2013, as well as an after-tax gain of $23 million from the sale of our E-Gas^TMTechnology business. Earnings in 2012 were lowered by income taxes associated with foreign dividends, and 2012 included a full year of earnings from our U.K. power generation business, which was sold in July 2013.

Corporate and Other



	Millions of Dollars
	Year Ended December 31
	2014			2013		2012
Net Loss Attributable to Phillips 66
Net interest expense	$	(160	)	(166	)	(148	)
Corporate general and administrative expenses	(156		)	(145	)	(116	)
Technology	(58		)	(50	)	(49	)
Repositioning costs	—			—		(55	)
Other	(19		)	(70	)	(66	)
Total Corporate and Other	$	(393	)	(431	)	(434	)

2014 vs. 2013

Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense decreased $6 million in 2014, compared with 2013, primarily due to increased capitalized interest. This decrease in expense was partially offset due to an increase in average debt outstanding in 2014, reflecting the issuance of debt in late 2014. For additional information, see Note 14—Debt, in the Notes to Consolidated Financial Statements.

Corporate general and administrative expenses increased $11 million in 2014, compared with 2013. The increase was primarily due to increased employee benefit costs and charitable contributions.

The category “Other” includes certain income tax expenses, environmental costs associated with sites no longer in operation, foreign currency transaction gains and losses and other costs not directly associated with an operating segment. The decrease in costs was primarily due to increased utilization of foreign tax credit carryforwards. In addition, our results in 2013 were negatively impacted by higher environmental costs.

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2013 vs. 2012

Net interest expense increased $18 million in 2013, compared with 2012, primarily due to increased average debt outstanding in 2013, reflecting the issuance of debt in early 2012 in connection with the Separation. For additional information, see Note 14—Debt, in the Notes to Consolidated Financial Statements.

Corporate general and administrative expenses increased $29 million in 2013, compared with 2012. The increase was primarily due to incremental costs and expenses associated with operating as a stand-alone company. Repositioning costs decreased $55 million in 2013, compared with 2012.

Discontinued Operations



	Millions of Dollars
	Year Ended December 31
	2014		2013	2012
Net Income Attributable to Phillips 66
Discontinued operations	$	706	61	48

In December 2013, we entered into an agreement to exchange the stock of PSPI, a flow improver business, which was included in our M&S segment, for shares of Phillips 66 common stock owned by the other party to the transaction. On February 25, 2014, we completed the PSPI share exchange, resulting in the receipt of approximately 17.4 million shares of Phillips 66 common stock and the recognition of a before-tax noncash gain of $696 million. See Note 7—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information on this transaction.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators



	Millions of Dollars Except as Indicated
	2014			2013	2012

Net cash provided by operating activities	$	3,529		6,027	4,296
Short-term debt	842			24	13
Total debt	8,684			6,155	6,974
Total equity	22,037			22,392	20,806
Percent of total debt to capital*	28		%	22	25
Percent of floating-rate debt to total debt	1		%	1	15
*Capital includes total debt and total equity.

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. During 2014, we generated $3.5 billion in cash from operations and received $1.2 billion from asset dispositions, including return of investments in equity affiliates, and $2.5 billion in proceeds from the issuance of debt. Available cash was primarily used for capital expenditures and investments ($3.8 billion), repurchases of our common stock ($2.3 billion), the PSPI share exchange ($0.5 billion) and dividend payments on our common stock ($1.1 billion). During 2014, cash and cash equivalents decreased by $0.2 billion to $5.2 billion.

In addition to cash flows from operating activities, we rely on our commercial paper and credit facility programs, asset sales and our ability to issue securities using our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash and cash equivalents and cash generated by operations, together with access to external sources of funds as described below under “Significant Sources of Capital,” will be sufficient to meet our funding requirements in the near and long term, including our capital spending, dividend payments, defined benefit plan contributions, debt repayment and share repurchases.

Significant Sources of Capital

Operating Activities

Although net income was higher in 2014 than in 2013, there were large noncash items benefiting 2014 earnings, including the gain on the PSPI exchange, gains from asset dispositions and the deferred tax effects of certain asset dispositions. After consideration of these items, underlying earnings in 2014 were similar to 2013. However, working capital negatively impacted 2014 operating cash flow by $1,020 million, compared with a positive impact of $880 million in 2013. Working capital impacts in 2014 reflected the negative impact of lower commodity prices on accounts payable, with a lesser positive impact on accounts receivable as we generally carry higher payables on our balance sheet than receivables. See the following paragraph for a discussion of 2013 working capital effects. Benefiting 2014 operating cash flow, compared with 2013, was the receipt of a special distribution from WRB, of which $760 million was considered an operating cash flow, partially offset by lower distributions from CPChem.

During 2013, cash of $6,027 million was provided by operating activities, a 40 percent increase from cash from operations of $4,296 million in 2012. The increase in 2013 primarily reflected positive working capital impacts. Accounts payable activity increased cash from operations by $360 million in 2013, reflecting both higher volumes and commodity prices. By comparison, lower commodity prices and volumes reduced accounts payable by $985 million in 2012. Our distributions from CPChem increased over $500 million in 2013, compared with 2012, reflecting the completion of CPChem’s debt repayments in 2012, which allowed increased dividends to us and our co-venturer. Partially offsetting the positive impact of working capital changes in 2013 were lower refining margins during 2013, reflecting less favorable market conditions and tightening crude differentials.

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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.

The level and quality of output from our refineries also impacts our cash flows. The output at our refineries is impacted by such factors as operating efficiency, maintenance turnarounds, market conditions, feedstock availability and weather conditions. We actively manage the operations of our refineries and, typically, any variability in their operations has not been as significant to cash flows as that caused by margins and prices. Our worldwide refining crude oil capacity utilization was 94 percent in 2014, compared with 93 percent in 2013. We are forecasting 2015 utilization to remain in the low 90-percent range.

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, 2014, we received distributions of $654 million from DCP Midstream, $1,948 million from CPChem and $4,220 million from WRB. We cannot control the amount or timing of future distributions from equity affiliates; therefore, future distributions by these and other equity affiliates are not assured. We and our co-venturer in DCP Midstream have agreed to forgo distributions from DCP Midstream during the current low-commodity-price environment.

WRB

WRB is a 50-percent-owned business venture with Cenovus Energy Inc. (Cenovus). Cenovus was obligated to contribute $7.5 billion, plus accrued interest, to WRB over a 10-year period that began in 2007. In 2014, Cenovus prepaid its remaining balance under this obligation. As a result, WRB declared a special dividend, which was distributed to the co-venturers in 2014. Of the $1,232 million that we received, $760 million was considered a return on our investment in WRB (an operating cash inflow), and $472 million was considered a return of our investment in WRB (an investing cash inflow). The return-of-investment portion of the dividend was included in the “Proceeds from asset dispositions” line in our consolidated statement of cash flows. A further $129 million of distributions from WRB during 2014 was considered a return of investment.

Asset Sales

Proceeds from asset sales in 2014 were $1,244 million, compared with $1,214 million in 2013 and $286 million in 2012. The 2014 proceeds included a portion of the WRB special dividend as discussed above, as well as the sale of our interest in MRC. The 2013 proceeds included the sale of a power plant in the United Kingdom, as well as our gasification technology. The 2012 proceeds included the sale of a refinery and associated terminal and pipeline assets located in Trainer, Pennsylvania, as well as the sale of our Riverhead Terminal located in Riverhead, New York.

Phillips 66 Partners LP

Initial Public Offering

In 2013, we formed Phillips 66 Partners LP, a master limited partnership, to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum product and NGL pipelines and terminals, as well as other transportation and midstream assets. On July 26, 2013, Phillips 66 Partners completed its initial public offering (IPO) of 18,888,750 common units at a price of $23.00 per unit, which included a 2,463,750 common unit over-allotment option that was fully exercised by the underwriters. Phillips 66 Partners received $404 million in net proceeds from the sale of the units, after deducting underwriting discounts, commissions, structuring fees and offering expenses. Headquartered in Houston, Texas, Phillips 66 Partners’ assets currently consist of crude oil and refined petroleum product pipeline, terminal, and storage systems in the Central and Gulf Coast regions of the United States, as well as two crude oil rail-unloading facilities, all of which are integral to a connected Phillips 66-operated refinery.

Contributions to Phillips 66 Partners LP

Effective March 1, 2014, we contributed to Phillips 66 Partners certain transportation, terminaling and storage assets for total consideration of $700 million. These assets consisted of the Gold Line products system and the Medford spheres, two recently constructed refinery-grade propylene storage spheres. Phillips 66 Partners financed the acquisition with cash on hand of $400 million (primarily reflecting its IPO proceeds), the issuance to us of 3,530,595 and 72,053 additional common and general partner units, respectively, valued at $140 million, and a five-year, $160 million note payable to a subsidiary of Phillips 66.

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Effective December 1, 2014, we contributed to Phillips 66 Partners certain logistics assets for total consideration of $340 million. These assets consisted of two recently constructed crude oil rail-unloading facilities located at or adjacent to our Bayway and Ferndale refineries, and the Cross Channel Connector pipeline assets located near the partnership’s Pasadena terminal. Phillips 66 Partners financed the acquisition with the borrowing of $28 million under its revolving credit facility, the assumption of a five-year, $244 million note payable to a subsidiary of Phillips 66, and the issuance to Phillips 66 of 1,066,412 common and 21,764 general partner units valued at $68 million.

In addition to these two transactions, we made smaller contributions to Phillips 66 Partners of projects under development in the fourth quarter, for consideration in the aggregate of approximately $55 million.

Ownership

At December 31, 2014, we owned a 73 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while its public unitholders owned a 25 percent limited partner interest. We consolidate Phillips 66 Partners as a variable interest entity for financial reporting purposes. See Note 4—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements, for additional information on why we consolidate the partnership. As a result of this consolidation, the public unitholders’ ownership interest in Phillips 66 Partners is reflected as a noncontrolling interest in our financial statements, including $415 million in the equity section of our consolidated balance sheet at December 31, 2014. Generally, contributions of assets by us to Phillips 66 Partners will eliminate in consolidation, other than third-party debt or equity offerings made by Phillips 66 Partners to finance such transactions. For the 2014 contributions discussed above, the first did not impact our consolidated financial statements, while the second increased consolidated cash and debt by $28 million at the time of the transaction.

Recent Transactions

On February 13, 2015, we entered into a contribution agreement with Phillips 66 Partners under which Phillips 66 Partners will acquire our equity interest in Explorer Pipeline Company (19.46 percent), DCP Sand Hills Pipeline, LLC (33.33 percent), and DCP Southern Hills Pipeline, LLC (33.33 percent). We account for each of these investments under the equity method of accounting. The total consideration for the transaction is expected to be $1,010 million, which will consist of approximately $880 million in cash and the issuance of common units and general partner units to us with an aggregate fair value of $130 million. The transaction is expected to close in early March 2015, subject to standard closing conditions.

During February 2015, Phillips 66 Partners initiated two registered public offerings of securities:


•	5,250,000 common units representing limited partner interests, at a public offering price of $75.50 per unit. The net proceeds at closing are expected to be $384 million, not including an over-allotment option exercisable by the underwriters to purchase up to an additional 787,500 common units.


•	$1.1 billion aggregate principal amount of senior notes, which include $300 million of 2.646% Senior Notes due 2020, $500 million of 3.605% Senior Notes due 2025, and $300 million of 4.680% Senior Notes due 2045.

Closings of both public offerings are expected to occur in late February 2015. Phillips 66 Partners expects to use the net proceeds of both offerings to fund the acquisition transaction discussed above, repay existing borrowings from a subsidiary of Phillips 66, fund capital expenditures and for general partnership purposes.

Credit Facilities and Commercial Paper

During the fourth quarter of 2014, we amended our Phillips 66 revolving credit facility, primarily to increase its borrowing capacity from $4.5 billion to $5 billion and to extend the term from June 2018 to December 2019. The Phillips 66 facility may be used for direct bank borrowings, as support for issuances of letters of credit, or as support for our commercial paper program. The facility is with a broad syndicate of financial institutions and contains covenants that we consider usual and customary for an agreement of this type for comparable commercial borrowers, including a maximum consolidated net debt-to-capitalization ratio of 60 percent. The agreement has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violation of covenants; cross-payment default and cross-acceleration (in each case, to indebtedness in excess of a threshold amount); and a change of control. Borrowings under the facility will incur interest at the London Interbank Offered Rate (LIBOR) plus a margin based on the credit rating of our senior unsecured long-term debt as determined from time to time by Standard & Poor’s

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Ratings Services (S&P) and Moody’s Investors Service (Moody’s). The facility also provides for customary fees, including administrative agent fees and commitment fees. As of December 31, 2014, no amount had been directly drawn under this facility and $51 million in letters of credit had been issued that were supported by the facility. As a result, we ended 2014 with $4.9 billion of capacity under this facility.

We have a $5 billion commercial paper program for short-term working capital needs. Commercial paper maturities are generally limited to 90 days. As of December 31, 2014, we had no borrowings under our commercial paper program.

During the fourth quarter of 2014, Phillips 66 Partners also amended its revolving credit facility, primarily to increase its borrowing capacity from $250 million to $500 million and to extend the term from June 2018 to November 2019. The Phillips 66 Partners facility is with a broad syndicate of financial institutions. As of December 31, 2014, $18 million had been drawn under the facility, leaving $482 million of available capacity.

Trade Receivables Securitization Facility

In 2014, we terminated our $696 million trade receivables securitization facility. No amounts were drawn on this facility throughout its duration, and at the time of termination no letters of credit were outstanding thereunder.

Debt Financing

In November 2014, we issued $2.5 billion of debt consisting of:


•	$1.0 billion aggregate principal amount of 4.650% Senior Notes due 2034.


•	$1.5 billion aggregate principal amount of 4.875% Senior Notes due 2044.

The notes are guaranteed by Phillips 66 Company, a 100-percent-owned subsidiary. Net proceeds received from these offerings will be used to repay $800 million in aggregate principal amount of our outstanding 1.950% Senior Notes due 2015, for capital expenditures, and for general corporate purposes.

Our $8.3 billion of outstanding Senior Notes were issued by Phillips 66 and are guaranteed by Phillips 66 Company. 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.

Shelf Registration

We have a universal shelf registration statement on file with the SEC under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

Other Financing

During 2014, we recorded capital lease obligations related to equipment and transportation assets. These leases mature within the next fifteen years. During 2013, we entered into a capital lease obligation for use of an oil terminal in the United Kingdom which matures in 2033. The present value of our minimum capital lease payments for these obligations as of December 31, 2014, was $205 million.

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations, we enter into agreements with other parties to pursue business opportunities, with costs and risks apportioned among the parties as provided by the agreements. In April 2012, in connection with the Separation, we entered into an agreement to guarantee 100 percent of certain outstanding debt obligations of Merey Sweeny, L.P. (MSLP). At December 31, 2014, the aggregate principal amount of MSLP debt guaranteed by us was $189 million.

For additional information about guarantees, see Note 15—Guarantees, in the Notes to Consolidated Financial Statements.

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Capital Requirements

For information about our capital expenditures and investments, see “Capital Spending” below.

Our debt balance at December 31, 2014, was $8.7 billion and our debt-to-capital ratio was 28 percent, within our target range of 20-to-30 percent.

On February 4, 2015, our Board of Directors declared a quarterly cash dividend of $0.50 per common share, payable March 2, 2015, to holders of record at the close of business on February 17, 2015. We are forecasting annual double-digit percentage increases in our dividend rate in 2015 and 2016.

During the second half of 2013, we entered into a construction agency agreement and an operating lease agreement with a financial institution for the construction of our new headquarters facility to be located in Houston, Texas. Under the construction agency agreement, we act as construction agent for the financial institution over a construction period of up to three years and eight months, during which time we request cash draws from the financial institution to fund construction costs. Through December 31, 2014, approximately $225 million had been drawn, of which approximately $205 million is recourse to us should certain events of default occur. The operating lease becomes effective after construction is substantially complete and we are able to occupy the facility. The operating lease has a term of five years and provides us the option, at the end of the lease term, to request to renew the lease, purchase the facility, or assist the financial institution in marketing it for resale.

During 2012 and 2013, our Board of Directors authorized repurchases totaling up to $5 billion of our outstanding common stock. In July 2014, our Board of Directors authorized additional share repurchases totaling up to $2 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 the company’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements and the Tax Sharing Agreement entered into in connection with the Separation. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Since the inception of our share repurchases in 2012, we have repurchased a total of 73,227,369 shares at a cost of $4.9 billion through December 31, 2014. Shares of stock repurchased are held as treasury shares.

On October 15, 2014, we signed agreements to form two joint ventures to develop the Dakota Access Pipeline (DAPL) and Energy Transfer Crude Oil Pipeline (ETCOP) projects. We own a 25 percent interest in each joint venture, with our co-venturer holding the remaining 75 percent interest and acting as operator of both the DAPL and ETCOP systems. Our share of construction cost is estimated to be approximately $1.2 billion, which will be reflected as investments in equity-method affiliates. We expect the majority of this capital spending commitment to be incurred in 2015 and 2016, and anticipate it to be funded as part of our overall capital program.

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Contractual Obligations

The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2014.



	Millions of Dollars
	Payments Due by Period
	Total		Up to 1 Year	Years 2-3	Years 4-5	After 5 Years

Debt obligations (a)	$	8,474	823	1,556	81	6,014
Capital lease obligations	210		19	19	17	155
Total debt	8,684		842	1,575	98	6,169
Interest on debt	6,373		363	682	606	4,722
Operating lease obligations	2,008		489	685	378	456
Purchase obligations (b)	83,381		27,161	17,023	6,735	32,462
Other long-term liabilities (c)
Asset retirement obligations	279		8	10	10	251
Accrued environmental costs	496		84	113	80	219
Unrecognized tax benefits (d)	8		8	(d)	(d)	(d)
Total	$	101,229	28,955	20,088	7,907	44,279


(a)	For additional information, see Note 14—Debt, in the Notes to Consolidated Financial Statements.

(b)

Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. We expect these purchase obligations will be fulfilled by operating cash flows in the applicable maturity period. The majority of the purchase obligations are market-based contracts, including exchanges and futures, for the purchase of products such as crude oil and unfractionated NGL. The products are mostly used to supply our refineries and fractionators, optimize the supply chain, and resell to customers. Product purchase commitments with third parties totaled $39,822 million. In addition, $22,117 million are product purchases from CPChem, mostly for natural gas and NGL over the remaining contractual term of 85 years, and $8,575 million from Excel Paralubes, for base oil over the remaining contractual term of 10 years.

Purchase obligations of $6,385 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. For the 2015 through 2019 time period, we expect to contribute an average of $138 million per year to our qualified and nonqualified pension and other postretirement benefit plans in the United States and an average of $56 million per year to our non-U.S. plans, which are expected to be in excess of required minimums in many cases. The U.S. five-year average consists of $30 million for 2015 and then approximately $165 million per year for the remaining four years. Our minimum funding in 2015 is expected to be $30 million in the United States and $70 million outside the United States.

(d)

Excludes unrecognized tax benefits of $134 million because the ultimate disposition and timing of any payments to be made with regard to such amounts are not reasonably estimable or the amounts relate to potential refunds. Also excludes interest and penalties of $16 million. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity.

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Capital Spending



	Millions of Dollars
	2015 Budget		2014	2013	2012
Capital Expenditures and Investments
Midstream*	$	3,163	2,173	597	707
Chemicals	—		—	—	—
Refining**	1,112		1,038	820	735
Marketing and Specialties	170		439	226	119
Corporate and Other**	155		123	136	140
Total consolidated from continuing operations	$	4,600	3,773	1,779	1,701

Discontinued operations	$	—	—	27	20

Selected Equity Affiliates***
DCP Midstream*	$	400	776	971	1,324
CPChem	1,453		897	613	371
WRB	203		140	109	136
	$	2,056	1,813	1,693	1,831

*2012 consolidated amount includes acquisition of a one-third interest in the Sand Hills and Southern Hills pipeline projects from DCP Midstream for $459 million. This amount was also included in DCP Midstream’s capital spending, primarily in 2012.

**2015 budget includes non-cash capitalized leases of $11 million in Refining and $21 million in Corporate and Other.

***Our share of capital spending, which has been self-funded by the equity affiliate and is expected to be in 2015.

Midstream

During the three-year period ended December 31, 2014, DCP Midstream had a self-funded capital program, and thus required no new capital infusions from us or our co-venturer, Spectra Energy Corp. During this three-year period, on a 100 percent basis, DCP Midstream’s capital expenditures and investments were $6.1 billion. In 2012, we invested approximately $0.5 billion in total to acquire a one-third direct interest in DCP Sand Hills Pipeline, LLC (DCP Sand Hills) and DCP Southern Hills Pipeline, LLC (DCP Southern Hills). Phillips 66, Spectra Energy Partners and DCP Midstream Partners each own a one-third interest in each of the two pipeline entities, and both pipelines are operated by DCP Midstream. In 2013 and 2014, we made additional investments in both DCP Sand Hills and DCP Southern Hills, increasing our total direct investment to $0.8 billion.

Other capital spending in our Midstream segment not related to DCP Midstream or the Sand Hills and Southern Hills pipelines over the three-year period included construction activities in 2014 related to our Sweeny Fractionator One and Freeport LPG Export Terminal projects, our acquisition in 2014 of a 7.1 million-barrel-storage-capacity crude oil and petroleum products terminal located near Beaumont, Texas, the purchase in 2014 of an additional 5.7 percent interest in the refined products Explorer Pipeline, and spending associated with return, reliability and maintenance projects. In addition to our Sweeny Fractionator One and Freeport LPG Export Terminal projects, our major capital activities in 2013 and 2014 included the construction of rail racks to accept advantaged crude deliveries at our Bayway and Ferndale refineries.

Chemicals

During the three-year period ended December 31, 2014, CPChem had a self-funded capital program, and thus required no new capital infusions from us or our co-venturer, Chevron U.S.A. Inc. (Chevron), an indirect wholly-owned subsidiary of Chevron Corporation. During the three-year period, on a 100 percent basis, CPChem’s capital expenditures and investments were $3.8 billion. In addition, CPChem’s advances to equity affiliates, primarily used for project construction and start-up activities, were $0.5 billion and its repayments received from equity affiliates were $0.4 billion.

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Refining

Capital spending for the Refining segment during the three-year period ended December 31, 2014, was $2.6 billion, primarily for air emission reduction and clean fuels projects to meet new environmental standards, refinery upgrade projects to increase accessibility of advantaged crudes and improve product yields, improvements to the operating integrity of key processing units, and safety-related projects.

Key projects completed during the three-year period included:


•	Installation of facilities to reduce nitrous oxide emissions from the crude furnace and installation of a new high-efficiency vacuum furnace at Bayway Refinery.


•	Completion of gasoline benzene reduction projects at the Alliance, Bayway, and Ponca City refineries.


•	Installation of new coke drums at the Billings and Ponca City refineries.


•	Installation of a new waste heat boiler at the Bayway Refinery to reduce carbon monoxide emissions while providing steam production.

Major construction activities in progress include:


•	Installation of facilities to reduce nitrous oxide emissions from the fluid catalytic cracker at the Alliance Refinery.


•	Installation of a tail gas treating unit at the Humber Refinery to reduce emissions from the sulfur recovery units.

Generally, our equity affiliates in the Refining segment are intended to have self-funding capital programs. During this three-year period, on a 100 percent basis, WRB’s capital expenditures and investments were $0.8 billion. We expect WRB’s 2015 capital program to be self-funding.

Marketing and Specialties

Capital spending for the M&S segment during the three-year period ended December 31, 2014, was primarily for the acquisition of, and investments in, a limited number of retail sites in the Western and Midwestern portions of the United States; the acquisition of Spectrum Corporation, a private label specialty lubricants business headquartered in Memphis, Tennessee, as well as the remaining interest that we did not already own in an entity that operates a power and steam generation plant; reliability and maintenance projects; and projects targeted at growing our international marketing business.

Corporate and Other

Capital spending for Corporate and Other during the three-year period ended December 31, 2014, was primarily for projects related to information technology and facilities.

2015 Budget

Our 2015 capital budget is $4.6 billion. This excludes our portion of planned capital spending by joint ventures DCP Midstream, CPChem and WRB totaling $2.1 billion, all of which are expected to be self-funded. We continually evaluate our capital budget in light of market conditions. As part of our disciplined approach to capital allocation, we retain the flexibility to adjust the capital budget as the year progresses.

In Midstream, we plan to invest $3.2 billion in our NGL and Transportation business lines. Midstream capital includes approximately $0.2 billion expected to be spent by Phillips 66 Partners to support organic growth projects. In NGL, construction of the 100,000 barrel-per-day Sweeny Fractionator One and the 4.4 million-barrel-per-month Freeport LPG Export Terminal on the U.S. Gulf Coast continues. In Transportation, we are investing in pipeline and rail infrastructure projects to move crude oil from the Bakken/Three Forks production area of North Dakota to market centers throughout the United States. In addition, expansion of the Beaumont Terminal and related infrastructure opportunities are being pursued.

We plan to spend $1.1 billion of capital in Refining, approximately 75 percent of which will be sustaining capital. These investments are related to reliability and maintenance, safety and environmental projects, including compliance with the

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new EPA Tier 3 gasoline specifications. Discretionary Refining capital investments are expected to be directed toward small, high-return, quick pay-out projects, primarily to enhance the use of advantaged crudes and improve product yields.

In Marketing and Specialties, we plan to invest approximately $0.2 billion for growth and sustaining capital. The growth investment reflects our continued plans to expand and enhance our fuel marketing business.

In Corporate and Other, we plan to fund approximately $0.2 billion in projects primarily related to information technology and facilities.

Contingencies

A number of lawsuits involving a variety of claims have been brought against us in connection with matters that arise in the ordinary course of business. 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 accounting 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 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. This process also enables us to track 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, are required. See Note 22—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information about income-tax-related contingencies.

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. The most significant of these environmental laws and regulations include, among others, the:


•	U.S. Federal Clean Air Act, which governs air emissions.


•	U.S. Federal Clean Water Act, which governs discharges to 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.

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•	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 Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells.


•	U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and 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 Emissions Trading Scheme, which uses a market-based mechanism to incentivize the reduction of greenhouse gas emissions.

These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.

Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.

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 in the fuels area is the Energy Policy Act of 2005, which imposed obligations to provide increasing volumes of renewable fuels in transportation motor fuels through 2012. These obligations were changed with the enactment of the Energy Independence and Security Act of 2007 (EISA). EISA 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. Also, we may experience a decrease in demand for refined petroleum products due to the regulatory program as currently promulgated. For the 2014 compliance year, the U.S. Environmental Protection Agency (EPA) proposed to reduce the statutory volumes of advanced and total renewable fuel using authority granted to it under EISA. We do not know whether this reduction will be finalized as proposed or whether the EPA will utilize its authority to reduce statutory volumes in future compliance years.

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 past and present 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 (MTBE) 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.

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We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging 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, 2013, we reported we had been notified of potential liability under CERCLA and comparable state laws at 35 sites around the United States. During 2014, there were no new sites for which we received notification of potential liability and one site was deemed resolved and closed, leaving 34 unresolved sites with potential liability at December 31, 2014.

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 $630 million in 2014 and are expected to be approximately $680 million in each of 2015 and 2016. Capitalized environmental costs were $411 million in 2014 and are expected to be approximately $320 million in each of 2015 and 2016. This amount does not include capital expenditures made for another purpose that have an indirect benefit on environmental compliance.

Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase 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.

At December 31, 2014, our balance sheet included total accrued environmental costs of $496 million, compared with $492 million at December 31, 2013, and $530 million at December 31, 2012. We expect to incur a substantial amount of these expenditures within the next 30 years.

Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in 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 upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.

The EPA’s Renewable Fuel Standard (RFS) program was implemented in accordance with the Energy Policy Act of 2005 and EISA. The RFS program sets annual quotas for the percentage of biofuels (such as ethanol) that must be blended into motor fuels consumed in the United States. A Renewable Identification Number (RIN) represents a serial number assigned to each gallon of biofuel produced or imported into the United States. As a producer of petroleum-based motor fuels, we are obligated to blend biofuels into the products we produce at a rate that is at least equal 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. The market for RINs has been the subject of fraudulent activity, and we have identified that we have unknowingly

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purchased RINs in the past that were invalid due to fraudulent activity of third parties. Although costs to replace fraudulently marketed RINs that have been determined to be invalid have not been material through December 31, 2014, it is reasonably possible that some additional RINs that we have previously purchased may also be determined to be invalid. Should that occur, we could incur additional replacement charges. Although the cost for replacing any additional fraudulently marketed RINs is not reasonably estimable at this time, we could have a possible exposure of approximately $150 million before tax. It could take several years for this possible exposure to reach ultimate resolution; therefore, we would not expect to incur the full financial impact of additional fraudulent RINs replacement costs in any single interim or annual period.

Climate Change

There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field 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, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation or precursors for possible regulation that do or could affect our operations include:


•	European Union Emissions Trading Scheme (EU ETS), which is part of the European Union’s policy to combat climate change and is a key tool for reducing industrial greenhouse gas emissions. EU ETS impacts factories, power stations and other installations across all EU member states.


•	California’s Global Warming Solutions Act, which requires the California Air Resources Board to develop regulations and market mechanisms that will target reduction of California’s GHG emissions by 25 percent by 2020.


•	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.


•	Carbon taxes in certain jurisdictions.


•	GHG emission cap and trade programs in certain jurisdictions.

In the EU, the first phase of the EU ETS completed at the end of 2007 and Phase II was undertaken from 2008 through to 2012. The current phase (Phase III) runs from 2013 through to 2020, with the main changes being reduced allocation of free allowances and increased auctioning of new allowances. Phillips 66 has assets that are subject to the EU ETS, and the company is actively engaged in minimizing any financial impact from the EU ETS.

In the United States, some additional form of regulation may be forthcoming in the future at the federal or state 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 or GHG reduction requirements 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 has been limited to certain stationary sources, which include our refineries in California, but beginning in January 2015 expanded to include emissions from transportation fuels distributed in California. We expect inclusion of transportation fuels in California’s cap and trade program as currently promulgated will increase 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:

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•	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 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.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 2—Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussion of critical accounting estimates, along with the discussion of contingencies in this report, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

Impairments

Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, including applicable liabilities, the carrying value of the long-lived assets included in the asset group is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets (for example, at a refinery complex level). Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined using one or more of the following methods: the present 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. 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 reviewed for impairment when there is evidence of a loss in value. Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of sustained earnings capacity which would justify the current investment amount, or a current fair value less than the investment’s carrying amount. When it is determined such a loss in value is other than temporary, an impairment 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 will be sufficient to allow for any anticipated recovery in the market value of the investment. When quoted market prices are not available, the fair value is usually based on the present value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants and a market analysis of comparable assets, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period.

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Asset Retirement Obligations

Under various contracts, permits and regulations, we have legal obligations to remove tangible equipment and restore the land at the end of operations at certain operational sites. Our largest asset removal obligations involve asbestos abatement at refineries. Estimating the timing and amount of payments for future asset removal costs is difficult. Most of these removal obligations are many years, or decades, in the future, and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.

Environmental Costs

In addition to asset retirement obligations discussed above, under the above or similar contracts, permits and regulations, 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, 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 responsible parties.

Intangible Assets and Goodwill

At December 31, 2014, we had $756 million of intangible assets determined to have indefinite useful lives, and thus they are not amortized. This judgmental assessment of an indefinite useful life must be continuously evaluated in the future. If, due to changes in facts and circumstances, management determines these intangible assets have finite useful lives, amortization will commence at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to annual impairment tests that require management’s judgment of the estimated fair value of these intangible assets.

At December 31, 2014, we had $3.3 billion of goodwill recorded in conjunction with past business combinations. Goodwill is not amortized. Instead, goodwill is subject to at least annual reviews for impairment at a reporting unit level. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed. A reporting unit is an operating segment or a component that is one level below an operating segment.

Effective January 1, 2014, we reallocated $52 million of goodwill from the Refining segment to the M&S segment based upon the realignment of certain assets between the reporting units. Goodwill was reassigned to the reporting units using a relative fair value approach. Goodwill impairment testing was completed and no impairment recognition was required. See Note 27—Segment Disclosures and Related Information, for additional information on this segment realignment. Sales or dispositions of significant assets within a reporting unit are allocated a portion of that reporting unit’s goodwill, based on relative fair values, which adjusts the amount of gain or loss on the sale or disposition.

Because quoted market prices for our reporting units were not available, management applied judgment in determining the estimated fair values of the reporting units for purposes of performing the goodwill impairment test. Management used all available information to make this fair value determination, including observed market earnings multiples of comparable companies, our common stock price and associated total company market capitalization and the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets.

We completed our annual impairment test, as of October 1, 2014, and concluded that the fair value of our reporting units exceeded their recorded net book values (including goodwill). Our Refining reporting unit had a percentage excess of fair value over recorded net book value of approximately 60 percent. Our Transportation and M&S reporting unit’s fair values exceeded their recorded net book values by over 100 percent. However, a decline in the estimated fair value of one or more of our reporting units in the future could result in an impairment. For example, a prolonged or significant decline in our stock price or a significant decline in actual or forecasted earnings could provide evidence of a significant decline in fair value and a need to record a material impairment of goodwill for one or more of our reporting units.

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Tax Assets and Liabilities

Our operations are subject to various taxes, including federal, state and foreign income taxes and transactional taxes such as excise, sales/use, property 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 provision, 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 tax liabilities that cannot be predicted at this time.

Projected Benefit Obligations

Determination of the projected benefit obligations for our defined benefit pension and postretirement plans are important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A 1 percent decrease in the discount rate assumption would increase annual benefit expense by an estimated $80 million, while a 1 percent 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 2014 and 2013, the company used an expected long-term rate of return of 7 percent for the U.S. pension plan assets, which account for 75 percent of the company’s pension plan assets. The actual asset returns for 2014 and 2013 were 9 percent and 16 percent, respectively. For the eight years prior to the Separation, actual asset returns averaged 7 percent for the U.S. pension plan assets. The 2013 asset returns of 16 percent were associated with a broad recovery in the financial markets during the year.

NEW ACCOUNTING STANDARDS

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The new standard converged guidance on recognizing revenues in contracts with customers under accounting principles generally accepted in the United States and International Financial Reporting Standards. This ASU is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets. ASU 2014-09 is effective for annual and quarterly reporting periods of public entities beginning after December 15, 2016. Early application for public entities is not permitted. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations.

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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 the Value at Risk (VaR) limits for us, and compliance with these limits is monitored daily. Our Chief Financial Officer monitors risks resulting from foreign currency exchange rates and interest rates. Our President monitors commodity price risk. The Commercial organization manages our commercial marketing, optimizes our commodity flows and positions, and monitors related risks of our businesses.

Commodity Price Risk

We sell into or receive supply from the worldwide crude oil, refined products, natural gas, NGL, and electric power markets and are exposed to fluctuations in the prices for these commodities.

These fluctuations can affect our revenues and purchases, as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities.

Our Commercial organization uses futures, forwards, swaps and options in various markets to optimize the value of our supply chain, which may move our risk profile away from market average prices to accomplish the following objectives:


•	Balance physical systems. In addition to cash settlement prior to contract expiration, exchange-traded futures contracts also may be settled by physical delivery of the commodity, providing another source of supply to meet our refinery requirements or marketing demand.


•	Meet customer needs. Consistent with our policy to generally remain exposed to market prices, we use swap contracts to convert fixed-price sales contracts, which are often requested by refined product consumers, to a floating-market price.


•	Manage the risk to our cash flows from price exposures on specific crude oil, refined product, natural gas, 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, 2014, as derivative instruments. Using 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, 2014 and 2013, was immaterial to our cash flows and net income.

The VaR for instruments held for purposes other than trading at December 31, 2014 and 2013, was also immaterial to our cash flows and net income.

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Index to Financial Statements

Interest Rate Risk

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 quoted market prices.



	Millions of Dollars Except as Indicated
Expected Maturity Date	Fixed Rate Maturity		Average Interest Rate		Floating Rate Maturity		Average Interest Rate
Year-End 2014
2015	$	825	2.11	%	$	—	—	%
2016		27	7.24			—	—
2017		1,529	3.03			—	—
2018		26	7.19			12	0.03
2019		24	7.12			18	1.33
Remaining years		6,020	4.90			38	0.03
Total	$	8,451			$	68
Fair value	$	8,806			$	68



	Millions of Dollars Except as Indicated
Expected Maturity Date	Fixed Rate Maturity		Average Interest Rate		Floating Rate Maturity		Average Interest Rate
Year-End 2013
2014	$	13	7.00	%	$	—	—	%
2015		815	2.04			—	—
2016		15	7.00			—	—
2017		1,516	2.99			—	—
2018		17	7.00			13	0.05
Remaining years		3,535	5.00			37	0.05
Total	$	5,911			$	50
Fair value	$	6,168			$	50

For additional information about our use of derivative instruments, see Note 17—Derivatives and Financial Instruments, in the Notes to Consolidated Financial Statements.

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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 and natural gas prices and petrochemical and refining margins.


•	Failure of new products and services to achieve market acceptance.


•	Unexpected changes in costs or technical requirements for constructing, modifying or operating our facilities or transporting our products.


•	Unexpected technological or commercial difficulties in manufacturing, refining or transporting our products, including chemicals products.


•	Lack of, or disruptions in, adequate and reliable transportation for our NGL, crude oil, natural gas and refined products.


•	The level and success of drilling and quality of production volumes around DCP Midstream’s assets and its ability to connect supplies to its gathering and processing systems, residue gas and NGL infrastructure.


•	Inability to timely obtain or maintain permits, including those necessary for capital projects; comply with government regulations; or make capital expenditures required to maintain compliance.


•	Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future capital projects.


•	Potential disruption or interruption of our operations due to accidents, weather events, civil unrest, political events, terrorism or cyber attacks.


•	International monetary conditions and exchange controls.


•	Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations.


•	Liability resulting from litigation or for remedial actions, including removal and reclamation obligations under environmental regulations.


•	General domestic and international economic and political developments including: armed hostilities; expropriation of assets; changes in governmental policies relating to NGL, crude oil, natural gas or refined product pricing, regulation or taxation; and other political, economic or diplomatic developments.


•	Changes in tax, environmental and other laws and regulations (including alternative energy mandates) applicable to our business.


•	Limited access to capital or significantly higher cost of capital related to changes to our credit profile or illiquidity or uncertainty in the domestic or international financial markets.


•	The operation, financing and distribution decisions of our joint ventures.


•	Domestic and foreign supplies of crude oil and other feedstocks.


•	Domestic and foreign supplies of petrochemicals and refined products, such as gasoline, diesel, jet fuel and home heating oil.


•	Governmental policies relating to exports of crude oil and natural gas.


•	Overcapacity or undercapacity in the midstream, chemicals and refining industries.


•	Fluctuations in consumer demand for refined products.


•	The factors generally described in Item 1A.—Risk Factors in this report.

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Index to Financial Statements

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PHILLIPS 66

INDEX TO FINANCIAL STATEMENTS



	Page

Report of Management	66

Report of Independent Registered Public Accounting Firm	67

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	68

Consolidated Financial Statements of Phillips 66:

Consolidated Statement of Income for the years ended December 31, 2014, 2013 and 2012	69

Consolidated Statement of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012	70

Consolidated Balance Sheet at December 31, 2014 and 2013	71

Consolidated Statement of Cash Flows for the years ended December 31, 2014, 2013 and 2012	72

Consolidated Statement of Changes in Equity for the years ended December 31, 2014, 2013 and 2012	73

Notes to Consolidated Financial Statements	75

Supplementary Information

Selected Quarterly Financial Data (Unaudited)	134

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Index to Financial Statements

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 accounting principles generally accepted 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 also 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, 2014. 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), adopted by the Company on December 15, 2014. Based on this assessment, management concluded the company’s internal control over financial reporting was effective as of December 31, 2014.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2014, and their report is included herein.




/s/ Greg C. Garland		/s/ Greg G. Maxwell

Greg C. Garland		Greg G. Maxwell
Chairman and		Executive Vice President, Finance
Chief Executive Officer		and Chief Financial Officer



February 20, 2015

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Index to Financial Statements

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Phillips 66

We have audited the accompanying consolidated balance sheet of Phillips 66 as of December 31, 2014 and 2013, and 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, 2014. Our audits also included the financial statement schedule included in Item 15(a)2. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Phillips 66 at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Phillips 66’s internal control over financial reporting as of December 31, 2014, 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 20, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 20, 2015

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Index to Financial Statements

Report of Independent Registered Public Accounting Firm on

Internal Control Over Financial Reporting

The Board of Directors and Stockholders

Phillips 66

We have audited Phillips 66’s internal control over financial reporting as of December 31, 2014, 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). Phillips 66’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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.

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.

In our opinion, Phillips 66 maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2014 consolidated financial statements of Phillips 66 and our report dated February 20, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 20, 2015

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Index to Financial Statements



Consolidated Statement of Income	Phillips 66



	Millions of Dollars
Years Ended December 31	2014		2013		2012
Revenues and Other Income
Sales and other operating revenues*	$	161,212	171,596		179,290
Equity in earnings of affiliates	2,466		3,073		3,134
Net gain on dispositions	295		55		193
Other income	120		85		135
Total Revenues and Other Income	164,093		174,809		182,752

Costs and Expenses
Purchased crude oil and products	135,748		148,245		154,413
Operating expenses	4,435		4,206		4,033
Selling, general and administrative expenses	1,663		1,478		1,703
Depreciation and amortization	995		947		906
Impairments	150		29		1,158
Taxes other than income taxes*	15,040		14,119		13,740
Accretion on discounted liabilities	24		24		25
Interest and debt expense	267		275		246
Foreign currency transaction (gains) losses	26		(40	)	(28	)
Total Costs and Expenses	158,348		169,283		176,196
Income from continuing operations before income taxes	5,745		5,526		6,556
Provision for income taxes	1,654		1,844		2,473
Income from Continuing Operations	4,091		3,682		4,083
Income from discontinued operations**	706		61		48
Net income	4,797		3,743		4,131
Less: net income attributable to noncontrolling interests	35		17		7
Net Income Attributable to Phillips 66	$	4,762	3,726		4,124

Amounts Attributable to Phillips 66 Common Stockholders:
Income from continuing operations	$	4,056	3,665		4,076
Income from discontinued operations	706		61		48
Net Income Attributable to Phillips 66	$	4,762	3,726		4,124

Net Income Attributable to Phillips 66 Per Share of Common Stock (dollars)
Basic
Continuing operations	$	7.15	5.97		6.47
Discontinued operations	1.25		0.10		0.08
Net Income Attributable to Phillips 66 Per Share of Common Stock	$	8.40	6.07		6.55
Diluted
Continuing operations	$	7.10	5.92		6.40
Discontinued operations	1.23		0.10		0.08
Net Income Attributable to Phillips 66 Per Share of Common Stock	$	8.33	6.02		6.48

Dividends Paid Per Share of Common Stock (dollars)	$	1.8900	1.3275		0.4500

Average Common Shares Outstanding (in thousands)
Basic	565,902		612,918		628,835
Diluted	571,504		618,989		636,764
*Includes excise taxes on petroleum product sales:	$	14,698	13,866		13,371
**Net of provision for income taxes on discontinued operations:	$	5	34		27
See Notes to Consolidated Financial Statements.

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Index to Financial Statements



Consolidated Statement of Comprehensive Income	Phillips 66

	Millions of Dollars
Years Ended December 31	2014			2013		2012

Net Income	$	4,797		3,743		4,131
Other comprehensive income (loss)
Defined benefit plans
Prior service cost/credit:
Prior service credit arising during the period	—			—		18
Amortization to net income of prior service cost	—			—		1
Actuarial gain/loss:
Actuarial gain (loss) arising during the period	(451		)	401		(152	)
Amortization to net income of net actuarial loss	56			96		55
Plans sponsored by equity affiliates	(66		)	88		(33	)
Income taxes on defined benefit plans	169			(211	)	18
Defined benefit plans, net of tax	(292		)	374		(93	)
Foreign currency translation adjustments	(294		)	(21	)	148
Income taxes on foreign currency translation adjustments	18			(2	)	48
Foreign currency translation adjustments, net of tax	(276		)	(23	)	196
Hedging activities by equity affiliates	—			1		1
Income taxes on hedging activities by equity affiliates	—			(1	)	—
Hedging activities by equity affiliates, net of tax	—			—		1
Other Comprehensive Income (Loss), Net of Tax	(568		)	351		104
Comprehensive Income	4,229			4,094		4,235
Less: comprehensive income attributable to noncontrolling interests	35			17		7
Comprehensive Income Attributable to Phillips 66	$	4,194		4,077		4,228
See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet	Phillips 66

	Millions of Dollars
At December 31	2014			2013
Assets
Cash and cash equivalents	$	5,207		5,400
Accounts and notes receivable (net of allowances of $71 million in 2014 and $47 million in 2013)	6,306			7,900
Accounts and notes receivable—related parties	949			1,732
Inventories	3,397			3,354
Prepaid expenses and other current assets	837			851
Total Current Assets	16,696			19,237
Investments and long-term receivables	10,189			11,220
Net properties, plants and equipment	17,346			15,398
Goodwill	3,274			3,096
Intangibles	900			698
Other assets	336			149
Total Assets	$	48,741		49,798

Liabilities
Accounts payable	$	7,488		9,948
Accounts payable—related parties	576			1,142
Short-term debt	842			24
Accrued income and other taxes	878			872
Employee benefit obligations	462			476
Other accruals	848			469
Total Current Liabilities	11,094			12,931
Long-term debt	7,842			6,131
Asset retirement obligations and accrued environmental costs	683			700
Deferred income taxes	5,491			6,125
Employee benefit obligations	1,305			921
Other liabilities and deferred credits	289			598
Total Liabilities	26,704			27,406

Equity
Common stock (2,500,000,000 shares authorized at $.01 par value) Issued (2014—637,031,760 shares; 2013—634,285,955 shares)
Par value	6			6
Capital in excess of par	19,040			18,887
Treasury stock (at cost: 2014—90,649,984 shares; 2013—44,106,380 shares)	(6,234		)	(2,602	)
Retained earnings	9,309			5,622
Accumulated other comprehensive income (loss)	(531		)	37
Total Stockholders’ Equity	21,590			21,950
Noncontrolling interests	447			442
Total Equity	22,037			22,392
Total Liabilities and Equity	$	48,741		49,798
See Notes to Consolidated Financial Statements.

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Index to Financial Statements



Consolidated Statement of Cash Flows	Phillips 66

	Millions of Dollars
Years Ended December 31	2014			2013		2012
Cash Flows From Operating Activities
Net income	$	4,797		3,743		4,131
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	995			947		906
Impairments	150			29		1,158
Accretion on discounted liabilities	24			24		25
Deferred taxes	(488		)	594		221
Undistributed equity earnings	197			(354	)	(872	)
Net gain on dispositions	(295		)	(55	)	(193	)
Income from discontinued operations	(706		)	(61	)	(48	)
Other	(127		)	195		71
Working capital adjustments
Decrease (increase) in accounts and notes receivable	2,226			481		(132	)
Decrease (increase) in inventories	(85		)	38		60
Decrease (increase) in prepaid expenses and other current assets	(316		)	20		(48	)
Increase (decrease) in accounts payable	(3,323		)	360		(985	)
Increase (decrease) in taxes and other accruals	478			(19	)	(35	)
Net cash provided by continuing operating activities	3,527			5,942		4,259
Net cash provided by discontinued operations	2			85		37
Net Cash Provided by Operating Activities	3,529			6,027		4,296

Cash Flows From Investing Activities
Capital expenditures and investments	(3,773		)	(1,779	)	(1,701	)
Proceeds from asset dispositions	1,244			1,214		286
Advances/loans—related parties	(3		)	(65	)	(100	)
Collection of advances/loans—related parties	—			165		—
Other	238			48		—
Net cash used in continuing investing activities	(2,294		)	(417	)	(1,515	)
Net cash used in discontinued operations	(2		)	(27	)	(20	)
Net Cash Used in Investing Activities	(2,296		)	(444	)	(1,535	)

Cash Flows From Financing Activities
Distributions to ConocoPhillips	—			—		(5,255	)
Issuance of debt	2,487			—		7,794
Repayment of debt	(49		)	(1,020	)	(1,210	)
Issuance of common stock	1			6		47
Repurchase of common stock	(2,282		)	(2,246	)	(356	)
Share exchange—PSPI transaction	(450		)	—		—
Dividends paid on common stock	(1,062		)	(807	)	(282	)
Distributions to noncontrolling interests	(30		)	(10	)	(5	)
Net proceeds from issuance of Phillips 66 Partners LP common units	—			404		—
Other	23			(6	)	(34	)
Net cash provided by (used in) continuing financing activities	(1,362		)	(3,679	)	699
Net cash provided by (used in) discontinued operations	—			—		—
Net Cash Provided by (Used in) Financing Activities	(1,362		)	(3,679	)	699

Effect of Exchange Rate Changes on Cash and Cash Equivalents	(64		)	22		14

Net Change in Cash and Cash Equivalents	(193		)	1,926		3,474
Cash and cash equivalents at beginning of year	5,400			3,474		—
Cash and Cash Equivalents at End of Year	$	5,207		5,400		3,474
See Notes to Consolidated Financial Statements.

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Index to Financial Statements



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		Net Parent Company Investment		Accum. Other Comprehensive Income (Loss)		Noncontrolling Interests		Total

December 31, 2011	$	—	—		—		—		23,142		122		29		23,293
Net income	—		—		—		2,999		1,125		—		7		4,131
Net transfers to ConocoPhillips	—		—		—		—		(5,707	)	(540	)	—		(6,247	)
Other comprehensive income	—		—		—		—		—		104		—		104
Reclassification of net parent company investment to capital in excess of par	—		18,560		—		—		(18,560	)	—		—		—
Issuance of common stock at the Separation	6		(6	)	—		—		—		—		—		—
Cash dividends paid on common stock	—		—		—		(282	)	—		—		—		(282	)
Repurchase of common stock	—		—		(356	)	—		—		—		—		(356	)
Benefit plan activity	—		172		—		(4	)	—		—		—		168
Distributions to noncontrolling interests and other	—		—		—		—		—		—		(5	)	(5	)
December 31, 2012	6		18,726		(356	)	2,713		—		(314	)	31		20,806
Net income	—		—		—		3,726		—		—		17		3,743
Other comprehensive income	—		—		—		—		—		351		—		351
Cash dividends paid on common stock	—		—		—		(807	)	—		—		—		(807	)
Repurchase of common stock	—		—		(2,246	)	—		—		—		—		(2,246	)
Benefit plan activity	—		164		—		(10	)	—		—		—		154
Issuance of Phillips 66 Partners LP common units	—		—		—		—		—		—		404		404
Distributions to noncontrolling interests and other	—		(3	)	—		—		—		—		(10	)	(13	)
December 31, 2013	6		18,887		(2,602	)	5,622		—		37		442		22,392
Net income	—		—		—		4,762		—		—		35		4,797
Other comprehensive loss	—		—		—		—		—		(568	)	—		(568	)
Cash dividends paid on common stock	—		—		—		(1,062	)	—		—		—		(1,062	)
Repurchase of common stock	—		—		(2,282	)	—		—		—		—		(2,282	)
Share exchange—PSPI transaction	—		—		(1,350	)	—		—		—		—		(1,350	)
Benefit plan activity	—		153		—		(13	)	—		—		—		140
Distributions to noncontrolling interests and other	—		—		—		—		—		—		(30	)	(30	)
December 31, 2014	$	6	19,040		(6,234	)	9,309		—		(531	)	447		22,037

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Index to Financial Statements



	Shares in Thousands
	Common Stock Issued	Treasury Stock
December 31, 2011	—	—
Issuance of common stock at the Separation	625,272	—
Repurchase of common stock	—	7,604
Shares issued—share-based compensation	5,878	—
December 31, 2012	631,150	7,604
Repurchase of common stock	—	36,502
Shares issued—share-based compensation	3,136	—
December 31, 2013	634,286	44,106
Repurchase of common stock	—	29,121
Share exchange—PSPI transaction	—	17,423
Shares issued—share-based compensation	2,746	—
December 31, 2014	637,032	90,650
See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements	Phillips 66

Note 1—Separation and Basis of Presentation

The Separation

On April 4, 2012, the ConocoPhillips Board of Directors approved the separation of its downstream businesses (as defined below) into an independent, publicly traded company named Phillips 66. In accordance with the Separation and Distribution Agreement, the two companies were separated by ConocoPhillips distributing to its stockholders all 625,272,302 shares of common stock of Phillips 66 after the market closed on April 30, 2012 (the Separation). Each ConocoPhillips stockholder received one share of Phillips 66 stock for every two shares of ConocoPhillips stock held at the close of business on the record date of April 16, 2012. Following the Separation, ConocoPhillips retained no ownership interest in Phillips 66, and each company has separate public ownership, boards of directors and management.

Basis of Presentation

Prior to the Separation, our results of operations, financial position and cash flows consisted of ConocoPhillips’ refining, marketing and transportation operations; its natural gas gathering, processing, transmission and marketing operations, primarily conducted through its equity investment in DCP Midstream, LLC (DCP Midstream); its petrochemical operations, conducted through its equity investment in Chevron Phillips Chemical Company LLC (CPChem); its power generation operations; and an allocable portion of its corporate costs (together, the “downstream businesses”). These financial statements have been presented as if the downstream businesses had been combined for all periods presented prior to the Separation. All intercompany transactions and accounts within the downstream businesses were eliminated. The statement of income for the periods prior to the Separation includes expense allocations for certain corporate functions historically performed by ConocoPhillips and not allocated to its operating segments, including allocations of general corporate expenses related to executive oversight, accounting, treasury, tax, legal, procurement and information technology. These allocations were based primarily on specific identification of time and/or activities associated with the downstream businesses, employee headcount or capital expenditures, and our management believes the assumptions underlying the allocations were reasonable. The combined financial statements may not necessarily reflect all of the actual expenses that would have been incurred had we been a stand-alone company during the periods presented prior to the Separation. All financial information presented after the Separation represents the consolidated results of operations, financial position and cash flows of Phillips 66. Accordingly:

•

Our consolidated statements of income, comprehensive income, cash flows and changes in equity for the years ended December 31, 2013 and 2014, consist entirely of the consolidated results of Phillips 66. Our consolidated statements of income, comprehensive income, cash flows and changes in equity for the year ended December 31, 2012, consist of the consolidated results of Phillips 66 for the eight months ended December 31, 2012, and of the combined results of the downstream businesses for the four months ended April 30, 2012.


•	Our consolidated balance sheet at December 31, 2014 and 2013, consists of the consolidated balances of Phillips 66.

Note 2—Accounting Policies

▪

Consolidation Principles and Investments—Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies. When we do not have the ability to exert significant influence, the investment is either classified as available-for-sale if fair value is readily determinable, or the cost method is used if fair value is not readily determinable. Undivided interests in pipelines, natural gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are generally carried at cost.


▪	Recasted Financial Information—Certain prior period financial information has been recasted to reflect the current year’s presentation, including realignment of our operating segments.

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▪	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 in stockholders’ equity.

Foreign currency transaction gains and losses result from remeasuring monetary assets and liabilities denominated in a foreign currency into the functional currency of our subsidiary holding the asset or liability; we include these transaction gains and losses in current earnings. Most of our foreign operations use their local currency as the functional currency.


▪	Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.


▪	Revenue Recognition—Revenues associated with sales of crude oil, natural gas liquids (NGL), petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.

Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into in contemplation of one another, are combined and reported net (i.e., on the same income statement line) in the “Purchased crude oil and products” line of our consolidated statement of income.


▪	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 at cost plus accrued interest, which approximates fair value.


▪	Shipping and Handling Costs—We record shipping and handling costs in purchased crude oil and products. Freight costs billed to customers are recorded as a component of revenue.

▪

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, but not unusual/nonrecurring costs or research and development costs. 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 observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants.


▪	Derivative Instruments—Derivative instruments are recorded on the balance sheet at fair value. We have elected to net derivative assets and liabilities with the same counterparty on the balance sheet if the right of offset exists and certain other criteria are met. We also net collateral payables or receivables against derivative assets and derivative liabilities, respectively.

Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives not designated as cash-flow hedges are recognized immediately in earnings. For derivative instruments that are designated and qualify as a fair value hedge, the gains or losses from adjusting the derivative to its fair value will

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be immediately recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item. Gains or losses from derivative instruments that are designated and qualify as a cash flow hedge or hedge of a net investment in a foreign entity are recognized in other comprehensive income and appear on the balance sheet in accumulated other comprehensive income until the hedged transaction is recognized in earnings; however, to the extent the change in the value of the derivative exceeds the change in the anticipated cash flows of the hedged transaction, the excess gains or losses will be recognized immediately in earnings.


▪	Capitalized Interest—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 underlying asset’s properties, plants and equipment and is amortized over the useful life of the assets.

▪

Intangible Assets Other Than Goodwill—Intangible assets with finite useful lives are amortized by the straight-line method over their useful lives. Intangible assets with indefinite useful lives are not amortized but are tested at least annually for impairment. Each reporting period, we evaluate the remaining useful lives of intangible assets not being amortized to determine whether events and circumstances continue to support indefinite useful lives. These indefinite-lived intangibles are considered impaired if the fair value of the intangible asset is lower than 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, fair value of intangible assets is determined based upon the present values of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable.

▪

Goodwill—Goodwill resulting from a business combination is not amortized but is tested at least annually for impairment. If the fair value of a reporting unit is less than the recorded book value of the reporting unit’s assets (including goodwill), less liabilities, then a hypothetical purchase price allocation is performed on the reporting unit’s assets and liabilities using the fair value of the reporting unit as the purchase price in the calculation. If the amount of goodwill resulting from this hypothetical purchase price allocation is less than the recorded amount of goodwill, the recorded goodwill is written down to the new amount. For purposes of testing goodwill for impairment, we have three reporting units with goodwill balances, Transportation, Refining and Marketing and Specialties (M&S).


▪	Depreciation and Amortization—Depreciation and amortization of properties, plants and equipment are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units).

▪

Impairment of Properties, Plants and Equipment—Properties, plants and equipment (PP&E) used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If indicators of potential impairment exist, an undiscounted cash flow test is performed. If the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, including applicable liabilities, the carrying value of the PP&E included in the asset group is written down to estimated fair value through additional amortization or depreciation provisions and reported in the “Impairment” line of our consolidated statement of income in the period in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets (for example, at a refinery complex level). Because there 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 values of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants; a market multiple of earnings for similar assets; or historical market transactions of similar assets, adjusted using principal market participant assumptions when necessary. Long-lived assets held for sale are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described.

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The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future volumes, prices, costs, margins, and capital project decisions, considering all available evidence at the date of review.

▪

Impairment of Investments in Nonconsolidated Entities—Investments in nonconsolidated entities are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. When indicators exist, the fair value is estimated and compared to the investment carrying value. If any impairment is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. The fair value of the impaired investment is based on quoted market prices, if available, or upon the present value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants and a market analysis of comparable assets, if appropriate.


▪	Maintenance and Repairs—Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Major refinery maintenance turnarounds are expensed as incurred.

▪

Property Dispositions—When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the “Net gain on dispositions” line of our consolidated statement of income. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.

▪

Asset Retirement Obligations and Environmental Costs—Fair value of legal obligations to retire and remove long-lived assets are recorded in the period in which the obligation is incurred. 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. Our estimate may change after initial recognition in which case we record an adjustment to the liability and properties, plant, and equipment.

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 purchase 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—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 is essentially 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 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.

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Stock-Based Compensation—We recognize stock-based compensation expense over the shorter of: (1) the service period (i.e., the 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, which is the minimum time required for an award to not be subject to forfeiture. We have elected to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.


▪	Income Taxes—For periods prior to the Separation, our taxable income was included in the U.S. federal income tax returns and in a number of state income tax returns of ConocoPhillips. In the accompanying consolidated

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financial statements for periods prior to the Separation, our provision for income taxes is computed as if we were a stand-alone tax-paying entity.

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 and loss and tax credit carryforwards. 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 tax benefits is reflected in interest expense, and penalties in operating expenses.


▪	Taxes Collected from Customers and Remitted to Governmental Authorities—Excise taxes are reported gross within sales and other operating revenues and taxes other than income taxes, while other sales and value-added taxes are recorded net in taxes other than income taxes.


▪	Treasury Stock—We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in stockholders’ equity in the consolidated balance sheet.

Note 3—Changes in Accounting Principles

Effective July 1, 2014, we early adopted the Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” This ASU amends the definition of discontinued operations so that only disposals of components of an entity representing major strategic shifts that have a major effect on an entity’s operations and financial results will qualify for discontinued operations reporting. The ASU also requires additional disclosures about discontinued operations and individually material disposals that do not meet the definition of a discontinued operation. The adoption of this ASU did not have an effect on our consolidated financial statements.

Note 4—Variable Interest Entities (VIEs)

We hold significant variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on these VIEs follows:

Merey Sweeny, L.P. (MSLP) is a limited partnership that owns a delayed coker and related facilities at the Sweeny Refinery. As discussed more fully in Note 8—Investments, Loans and Long-Term Receivables, in August 2009, a call right was exercised to acquire the 50 percent ownership interest in MSLP of the co-venturer, Petróleos de Venezuela S.A. (PDVSA). That exercise was challenged, and the dispute has been arbitrated. In April 2014, the arbitral tribunal upheld the exercise of the call right and the acquisition of the 50 percent ownership interest. In July 2014, PDVSA filed a petition to vacate the tribunal’s award. Until this matter is resolved, we will continue to use the equity method of accounting for MSLP, and the VIE analysis below is based on the ownership and governance structure in place prior to the exercise of the call right. MSLP is a VIE because, in securing lender consents in connection with the Separation, we provided a 100 percent debt guarantee to the lender of the 8.85% senior notes issued by MSLP. PDVSA did not participate in the debt guarantee. In our VIE assessment, this disproportionate debt guarantee, plus other liquidity support provided jointly by us and PDVSA independently of equity ownership, results in MSLP not being exposed to all potential losses. We have determined we are not the primary beneficiary while our call exercise award is subject to

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vacatur because under the partnership agreement the co-venturers jointly direct the activities of MSLP that most significantly impact economic performance. At December 31, 2014, our maximum exposure to loss represented the outstanding debt principal balance of $189 million, and our investment of $128 million.

We have a 50 percent ownership interest with a 50 percent governance interest in Excel Paralubes (Excel). Excel is a VIE because, in securing lender consents in connection with the Separation, ConocoPhillips provided a 50 percent debt guarantee to the lender of the 7.43% senior secured bonds issued by Excel. We provided a full indemnity to ConocoPhillips for this debt guarantee. Our co-venturer did not participate in the debt guarantee. In our assessment of the VIE, this debt guarantee, plus other liquidity support up to $60 million provided jointly by us and our co-venturer independently of equity ownership, results in Excel not being exposed to all potential losses. We have determined we are not the primary beneficiary because we and our co-venturer jointly direct the activities of Excel that most significantly impact economic performance. We use the equity method of accounting for this investment. At December 31, 2014, our maximum exposure to loss represented 50 percent of the outstanding debt principal balance of $58 million, or $29 million, plus half of the $60 million liquidity support, or $30 million. The book value of our investment in Excel at December 31, 2014, was $113 million.

In 2013, we entered into a multi-year consignment fuels agreement with a marketer who we supported with debt guarantees. Pursuant to the consignment fuels agreement, we own the fuels inventory, control the fuel marketing at each site, and pay a fixed monthly fee to the marketer. In November 2014, the marketer refinanced its debt which allowed us to remove the debt guarantees in exchange for an extended term on the consignment fuels agreement. We determined the consignment fuels agreement creates a variable interest in the marketer, with the marketer not being exposed to all potential losses as the consignment fuels agreement provides liquidity to the marketer for its debt service costs. We determined we are not the primary beneficiary because we do not have an ownership interest in the marketer or have the power to direct the activities that most significantly impact the economic performance of the marketer.

Note 5—Inventories

Inventories at December 31 consisted of the following:



	Millions of Dollars
	2014		2013

Crude oil and petroleum products	$	3,141	3,093
Materials and supplies	256		261
	$	3,397	3,354

Inventories valued on the LIFO basis totaled $3,004 million and $2,945 million at December 31, 2014 and 2013, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $3,000 million and $7,600 million at December 31, 2014 and 2013, respectively.

During each of the three years ending December 31, 2014, certain reductions in inventory caused liquidations of LIFO inventory values. These liquidations decreased net income by approximately $8 million in 2014, and increased net income by approximately $109 million and $162 million in 2013 and 2012, respectively.

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Note 6—Business Combinations

We completed the following acquisitions in 2014:


•	In August 2014, we acquired a 7.1 million-barrel-storage-capacity crude oil and petroleum products terminal located near Beaumont, Texas, to promote growth plans in our Midstream segment.


•	In July 2014, we acquired Spectrum Corporation, a private label and specialty lubricants business headquartered in Memphis, Tennessee. The acquisition supports our plans to selectively grow stable-return businesses in our M&S segment.


•	In March 2014, we acquired our co-venturer’s interest in an entity that operates a power and steam generation plant located in Texas that is included in our M&S segment. This acquisition provided us with full operational control over a key facility providing utilities and other services to one of our refineries.

We funded each of these acquisitions with cash on hand. Total cash consideration paid was $741 million, net of cash acquired, and this amount is included in the “Capital expenditures and investments” line of our consolidated statement of cash flows. In the aggregate, as of December 31, 2014, we provisionally recorded $471 million of PP&E, $232 million of goodwill, $196 million of intangible assets, $70 million of net working capital and $109 million of long-term liabilities for these acquisitions. Our acquisition accounting for the transactions completed in March and August of 2014 is substantially complete. The completion of our acquisition accounting for the transaction completed in July of 2014 is subject to finalizing the valuation of the assets acquired and liabilities assumed.

Note 7—Assets Held for Sale or Sold

Assets Sold or Exchanged

In December 2014, we completed the sale of our ownership interests in the Malaysia Refining Company Sdn. Bdh. (MRC), which was included in our Refining segment. At the time of the disposition, the total carrying value of our investment in MRC was $334 million, including $76 million of allocated goodwill and currency translation adjustments. A before-tax gain of $145 million was recognized from this disposition.

In December 2013, we entered into an agreement to exchange the stock of PSPI, a flow improver business, which was included in our M&S segment, for shares of Phillips 66 common stock owned by the other party. Accordingly, as of December 31, 2013, the net assets of PSPI were classified as held for sale and the results of operations of PSPI were reported as discontinued operations.

In February 2014, we completed the PSPI share exchange, resulting in the receipt of approximately 17.4 million shares of Phillips 66 common stock, which are held as treasury shares, and the recognition of a before-tax gain of $696 million. At the time of the disposition, PSPI had a net carrying value of $685 million, which primarily included $481 million of cash and cash equivalents, $60 million of net PP&E and $117 million of allocated goodwill. Cash and cash equivalents of $450 million included in PSPI’s net carrying value is reflected as a financing cash outflow in the “Share exchange—PSPI transaction” line of our consolidated statement of cash flows.

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The carrying amounts of the major classes of assets and liabilities of PSPI, excluding allocated goodwill of $117 million, at December 31, 2013, are below. The 2013 amounts were reclassified to the “Prepaid expenses and other current assets” and “Other accruals” lines of our consolidated balance sheet.



	Millions of Dollars
	2013
Assets
Accounts and notes receivable	$	24
Inventories	18
Total current assets of discontinued operations	42
Net properties, plants and equipment	58
Intangibles	6
Total assets of discontinued operations	$	106

Liabilities
Accounts payable and other current liabilities	$	18
Total current liabilities of discontinued operations	18
Deferred income taxes	12
Total liabilities of discontinued operations	$	30

Sales and other operating revenues and income from discontinued operations related to PSPI were as follows:



	Millions of Dollars
	2014		2013	2012

Sales and other operating revenues from discontinued operations	$	39	232	180

Income from discontinued operations before-tax	$	711	95	75
Income tax expense	5		34	27
Income from discontinued operations	$	706	61	48

In July 2013, we completed the sale of the Immingham Combined Heat and Power Plant (ICHP), which was included in our M&S segment. At the time of the disposition, ICHP had a net carrying value of $762 million, which primarily included $724 million of net PP&E, $110 million of allocated goodwill, and $111 million of deferred tax liabilities. A gain was deferred due to an indemnity provided to the buyer. A portion of the deferred gain is denominated in a foreign currency; accordingly, the amount of the deferred gain translated into U.S. dollars is subject to change based on currency fluctuations. Absent claims under the indemnity, the deferred gain is recognized into earnings as our exposure under this indemnity declines. As of December 31, 2013, the deferred gain was $375 million. In 2014, we recognized $126 million of the gain and as of December 31, 2014, the remaining deferred gain was $243 million.

In May 2013, we sold our E-Gas™ Technology business. The business was included in our M&S segment and at the time of the disposition had a net carrying value of approximately $13 million, including a goodwill allocation. A $48 million before-tax gain was recognized from this disposition.

In November 2012, we sold the Riverhead Terminal located in Riverhead, New York, for $36 million. The terminal and associated assets were included in our Midstream segment and had a net carrying value of $34 million at the time of the

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disposition, which included $33 million of net PP&E and $1 million of inventory. A $2 million before-tax gain was recognized from this disposition.

In June 2012, we sold our refinery located on the Delaware River in Trainer, Pennsylvania, for $229 million. The refinery and associated terminal and pipeline assets were primarily included in our Refining segment and at the time of the disposition had a net carrying value of $38 million, which included $37 million of net PP&E, $25 million of allocated goodwill and a $53 million asset retirement obligation. A $189 million before-tax gain was recognized from this disposition.

Gains and losses recognized from asset sales, including sales of investments in unconsolidated entities and controlled assets that meet the definition of a business, are included in the “Net gain on dispositions” line in the consolidated statement of income, unless noted otherwise above.

Assets Held for Sale

In July 2014, we entered into an agreement to sell the Bantry Bay terminal in Ireland, which is included in our Refining segment. The transaction closed in the first quarter of 2015. The classification of the terminal as held for sale resulted in a before-tax impairment of $12 million from reducing the carrying value of the long-lived assets to estimated fair value less costs to sell. As of December 31, 2014, we reclassified long-lived assets of $77 million to the “Prepaid expenses and other current assets” line of our consolidated balance sheet. The long-term liabilities reclassified to the “Other accruals” line of our consolidated balance sheet were not material.

Note 8—Investments, Loans and Long-Term Receivables

Components of investments, loans and long-term receivables at December 31 were:



	Millions of Dollars
	2014		2013

Equity investments	$	10,035	11,080
Long-term receivables	76		74
Other investments	78		66
	$	10,189	11,220

Equity Investments

Affiliated companies in which we had a significant equity investment at December 31, 2014, included:


•	WRB Refining LP—50 percent owned business venture with Cenovus Energy Inc. (Cenovus)—owns the Wood River and Borger refineries.


•	DCP Midstream—50 percent owned joint venture with Spectra Energy Corp—owns and operates gas plants, gathering systems, storage facilities and fractionation plants.


•	CPChem—50 percent owned joint venture with Chevron U.S.A. Inc., an indirect wholly-owned subsidiary of Chevron Corporation—manufactures and markets petrochemicals and plastics.


•	Rockies Express Pipeline LLC (REX)—25 percent owned joint venture with Tallgrass Energy Partners L.P. and Sempra Energy Corp.—owns and operates a natural gas pipeline system from Meeker, Colorado to Clarington, Ohio.


•	DCP Sand Hills Pipeline, LLC—33 percent owned joint venture with DCP Midstream and Spectra Energy Partners—owns and operates NGL pipeline systems from the Permian and Eagle Ford basins to Mont Belvieu, Texas.


•	DCP Southern Hills Pipeline, LLC—33 percent owned joint venture with DCP Midstream and Spectra Energy Partners—owns and operates NGL pipeline systems from the Midcontinent region to Mont Belvieu, Texas.

As discussed more fully in Note 7—Assets Held for Sale or Sold, in December 2014 we sold our 47 percent interest in MRC.

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Summarized 100 percent financial information for all equity method investments in affiliated companies, combined, was as follows:



	Millions of Dollars
	2014		2013	2012

Revenues	$	57,979	59,500	55,401
Income before income taxes	4,791		5,975	6,265
Net income	4,700		5,838	6,122
Current assets	7,402		9,865	9,646
Noncurrent assets	41,271		40,188	37,269
Current liabilities	6,854		7,971	8,319
Noncurrent liabilities	9,736		9,959	9,251

Our share of income taxes incurred directly by the equity companies is included in equity in earnings of affiliates, and as such is not included in the provision for income taxes in our consolidated financial statements.

At December 31, 2014, retained earnings included $1,488 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $3,305 million, $2,752 million, and $2,304 million in 2014, 2013 and 2012, respectively.

WRB

WRB’s operating assets consist of the Wood River and Borger refineries, located in Roxana, Illinois, and Borger, Texas, respectively, and we are the operator and managing partner. As a result of our contribution of these two assets to WRB, a basis difference was created because the fair value of the contributed assets recorded by WRB exceeded their historical book value. The difference is primarily amortized and recognized as a benefit evenly over a period of 26 years, which was the estimated remaining useful life of the refineries’ PP&E at the closing date. In the third quarter of 2013, we increased our ownership interest in WRB to 50 percent by purchasing ConocoPhillips’ 0.4 percent interest. At December 31, 2014, the book value of our investment in WRB was $1,809 million, and the basis difference was $3,373 million. Equity earnings in 2014, 2013 and 2012 were increased by $184 million, $185 million, and $180 million, respectively, due to amortization of the basis difference. Cenovus was obligated to contribute $7.5 billion, plus accrued interest, to WRB over a 10-year period that began in 2007. In the first quarter of 2014, Cenovus prepaid its remaining balance under this obligation. As a result, WRB declared a special dividend, which was distributed to the co-venturers in March 2014. Of the $1,232 million that we received, $760 million was considered a return on our investment in WRB (an operating cash inflow), and $472 million was considered a return of our investment in WRB (an investing cash inflow). The return of investment portion of the dividend was included in the “Proceeds from asset dispositions” line in our consolidated statement of cash flows.

DCP Midstream

DCP Midstream owns and operates gas plants, gathering systems, storage facilities and fractionation plants. DCP Midstream markets a portion of its NGL to us and CPChem under a supply agreement that continues at the current volume commitment of which the primary term ended December 31, 2014. The agreement provides for a wind-down period which expires in January 2019, if not renegotiated or renewed. This purchase commitment is on an “if-produced, will-purchase” basis. NGL is purchased under this agreement at various published market index prices, less transportation and fractionation fees.

In 2011, we sold our interest in the Seaway Products Pipeline Company to DCP Midstream and deferred $156 million representing one-half of the total gain. In 2012, DCP Midstream sold a one-third interest in the entity then owning the pipeline (DCP Southern Hills Pipeline, LLC) to us and a one-third interest to our co-venturer. The pipeline was completed in the second quarter of 2013 with service from the Midcontinent region to Mont Belvieu, Texas. The portion of the deferred gain assigned to DCP’s investment began amortizing in 2013 following the commencement of operations. At December 31, 2014, the book value of our investment in DCP Midstream was $1,259 million, and the basis difference was $54 million. The basis difference amortization was not material.

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CPChem

CPChem manufactures and markets petrochemicals and plastics. At December 31, 2014, the book value of our equity method investment in CPChem was $5,183 million. We have multiple supply and purchase agreements in place with CPChem, ranging in initial terms from one to 99 years, with extension options. These agreements cover sales and purchases of refined products, solvents, and petrochemical and NGL feedstocks, as well as fuel oils and gases. Delivery quantities vary by product, and are generally on an “if-produced, will-purchase” basis. All products are purchased and sold under specified pricing formulas based on various published pricing indices.

REX

REX owns a natural gas pipeline that runs from Meeker, Colorado to Clarington, Ohio, which became fully operational in November 2009. Long-term, binding firm commitments have been secured for virtually all of the pipeline’s capacity through 2019. At December 31, 2014, the book value of our equity method investment in REX was $267 million. During 2012, we recorded before-tax impairments totaling $480 million on this investment. See Note 11—Impairments, for additional information.

Sand Hills Pipeline

In 2012, we acquired from DCP Midstream a one-third ownership in DCP Sand Hills Pipeline, LLC. The Sand Hills pipeline extends from Eagle Ford and the Permian Basin to Mont Belvieu, Texas. At December 31, 2014, the book value of our equity investment in DCP Sand Hills Pipeline was $404 million.

Southern Hills Pipeline

In 2012, we acquired from DCP Midstream a one-third ownership in DCP Southern Hills Pipeline, LLC. A portion of the deferred gain assigned to DCP Southern Hill’s investment began amortizing in 2013 following the commencing of operations of the Southern Hills pipeline. At December 31, 2014, the book value of our investment in DCP Southern Hills was $226 million, and the basis difference was $97 million. Equity earnings in 2014 were increased by $3 million due to amortization of the basis difference.

Other

MSLP owns a delayed coker and related facilities at the Sweeny Refinery. MSLP processes long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50 by ConocoPhillips and PDVSA. Under the agreements that govern the relationships between the partners, certain defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery triggered the right to acquire PDVSA’s 50 percent ownership interest in MSLP, which was exercised on August 28, 2009. PDVSA initiated arbitration with the International Chamber of Commerce challenging the exercise of the call right and claiming it was invalid. The arbitral tribunal held hearings on the merits of the dispute in December 2012, and post-hearing briefs were exchanged in March 2013. The arbitral tribunal issued its ruling in April 2014, which upheld the exercise of the call right and the acquisition of the 50 percent ownership interest. In July 2014, PDVSA filed a petition in U.S. district court to vacate the tribunal’s ruling. Following the Separation, Phillips 66 generally indemnifies ConocoPhillips for liabilities, if any, arising out of the exercise of the call right or otherwise with respect to the joint venture or the refinery. Until this matter is settled, we will continue to use the equity method of accounting for our investment in MSLP.

Loans and Long-term Receivables

We enter into agreements with other parties to pursue business opportunities. Included in such activity are loans and long-term receivables 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.

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Note 9—Properties, Plants and Equipment

Our investment in PP&E is recorded at cost. Investments in refining manufacturing facilities are generally depreciated on a straight-line basis over a 25-year life, and pipeline assets over a 45-year life. The company’s investment in PP&E, with the associated accumulated depreciation and amortization (Accum. D&A), at December 31 was:



	Millions of Dollars
	2014				2013
	Gross PP&E		Accum. D&A	Net PP&E	Gross PP&E	Accum. D&A	Net PP&E

Midstream	$	4,726	1,185	3,541	2,865	1,104	1,761
Chemicals	—		—	—	—	—	—
Refining	19,951		7,424	12,527	19,191	6,718	12,473
Marketing and Specialties	1,490		738	752	1,395	749	646
Corporate and Other	978		452	526	975	457	518
	$	27,145	9,799	17,346	24,426	9,028	15,398

Note 10—Goodwill and Intangibles

Goodwill

Effective January 1, 2014, we reallocated $52 million of goodwill from the Refining segment to the M&S segment based upon the realignment of certain assets between the reporting units. Goodwill was reassigned to the reporting units using a relative fair value approach. Goodwill impairment testing was completed and no impairment recognition was required. See Note 27—Segment Disclosures and Related Information, for additional information on this segment realignment. See Note 6—Business Combinations and Note 7—Assets Held for Sale or Sold for information on goodwill assigned to business acquisitions and dispositions, respectively.

The carrying amount of goodwill was as follows:



	Millions of Dollars
	Midstream		Refining		Marketing and Specialties		Total

Balance at January 1, 2013	$	518	1,934		892		3,344
Tax and other adjustments	—		(15	)	—		(15	)
Goodwill allocated to assets held-for-sale or sold	—		—		(233	)	(233	)
Balance at December 31, 2013	518		1,919		659		3,096
Tax and other adjustments	—		(49	)	52		3
Goodwill assigned to asset acquisitions	105		—		127		232
Goodwill allocated to assets held-for-sale or sold	—		(57	)	—		(57	)
Balance at December 31, 2014	$	623	1,813		838		3,274

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Intangible Assets

Information at December 31 on the carrying value of intangible assets follows:



	Millions of Dollars
	Gross Carrying Amount
	2014		2013
Indefinite-Lived Intangible Assets
Trade names and trademarks	$	503	494
Refinery air and operating permits	239		200
Other	14		—
	$	756	694

At year-end 2014, our net amortized intangible asset balance was $144 million, which included accumulated amortization of $132 million, compared with $4 million and $127 million, respectively, at year-end 2013. The increase is primarily related to customer relationships and commercial contracts acquired in business acquisitions. These intangibles have a weighted-average amortization of 14 years. See Note 6—Business Combinations for more information on intangible assets acquired in business acquisitions. Amortization expense was not material for 2014 and 2013, and is not expected to be material in future years.

Note 11—Impairments

During 2014, 2013 and 2012, we recognized the following before-tax impairment charges:



	Millions of Dollars
	2014		2013	2012

Midstream	$	—	1	524
Refining	147		3	608
Marketing and Specialties	3		16	1
Corporate and Other	—		9	25
	$	150	29	1,158

2014

We recorded a $131 million held-for-use impairment in our Refining segment related to the Whitegate Refinery in Cork, Ireland, due to the current and forecasted negative market conditions in this region.

In addition, we also recorded a $12 million held-for-sale impairment in our Refining segment related to the Bantry Bay terminal. See Note 7—Assets Held for Sale or Sold for additional information.

2013

We recorded impairments of $16 million in our M&S segment, primarily related to PP&E associated with our planned exit from the composite graphite business.

2012

We had a 47 percent interest in MRC, which was included in our Refining segment. Due to significantly lower estimated future refining margins in this region, driven primarily by assumed increases in future crude oil pricing over the long term, we determined that the fair value of our investment in MRC was lower than our carrying value, and that this loss in value was other than temporary. Accordingly, we recorded a $564 million impairment of our investment in MRC.

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We have a 25 percent interest in REX, which is included in our Midstream segment. During 2012, marketing activities by a co-venturer that resulted in them recording an impairment charge and then subsequently selling their interest at an amount below our adjusted carrying value were determined to be indicators of impairment. After identifying these impairment indicators, we performed our own assessment of the fair value of our investment in REX. Based on these assessments, we concluded our investment in REX was impaired, and the decline in fair value was other than temporary. Accordingly, we recorded impairment charges totaling $480 million to write down the carrying amount of our investment in REX to fair value.

We recorded an impairment of $43 million on the Riverhead Terminal in our Midstream segment and a held-for-sale impairment of $42 million in our Refining segment related to equipment formerly associated with the canceled Wilhelmshaven Refinery upgrade project. See Note 7—Assets Held for Sale or Sold, for additional information. In addition, we recorded an impairment of $25 million on a corporate property.

Note 12—Asset Retirement Obligations and Accrued Environmental Costs

Asset retirement obligations and accrued environmental costs at December 31 were:



	Millions of Dollars
	2014			2013

Asset retirement obligations	$	279		309
Accrued environmental costs	496			492
Total asset retirement obligations and accrued environmental costs	775			801
Asset retirement obligations and accrued environmental costs due within one year*	(92		)	(101	)
Long-term asset retirement obligations and accrued environmental costs	$	683		700

*Classified as a current liability on the balance sheet, under the caption “Other accruals.”

Asset Retirement Obligations

We have asset removal 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 will be funded from general company resources at the time of removal. Our largest individual obligations involve asbestos abatement at refineries.

During 2014 and 2013, our overall asset retirement obligation changed as follows:



	Millions of Dollars
	2014			2013

Balance at January 1	$	309		314
Accretion of discount	11			11
New obligations	2			3
Changes in estimates of existing obligations	(16		)	12
Spending on existing obligations	(17		)	(13	)
Property dispositions	(1		)	(20	)
Foreign currency translation	(9		)	2
Balance at December 31	$	279		309

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Accrued Environmental Costs

Total accrued environmental costs at December 31, 2014 and 2013, were $496 million and $492 million, respectively. The 2014 increase in total accrued environmental costs is due to new accruals, accrual adjustments and accretion exceeding payments and settlements during the year.

We had accrued environmental costs at December 31, 2014 and 2013, of $268 million and $255 million, respectively, primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations; $178 million and $184 million, respectively, associated with nonoperator sites; and $50 million and $53 million, respectively, where the company has been named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state laws. Accrued environmental liabilities are expected to be paid over periods extending up to 30 years. Because a large portion of the accrued environmental costs were acquired in various business combinations, the obligations are recorded at a discount. Expected expenditures for acquired environmental obligations are discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired environmental liabilities of $259 million at December 31, 2014. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $26 million in 2015, $30 million in 2016, $33 million in 2017, $24 million in 2018, $26 million in 2019, and $177 million for all future years after 2019.

Note 13—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.

On April 30, 2012, 625.3 million shares of our common stock were distributed to ConocoPhillips stockholders in conjunction with the Separation. For comparative purposes, and to provide a more meaningful calculation of weighted-average shares outstanding, we have assumed this amount to be outstanding as of the beginning of each period prior to the Separation presented in the calculation of weighted-average shares. In addition, we have assumed the fully vested stock and unit awards outstanding at April 30, 2012, were also outstanding for each of the periods presented prior to the Separation; and we have assumed the dilutive securities outstanding at April 30, 2012, were also outstanding for each period prior to the Separation.

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	2014				2013			2012
	Basic			Diluted	Basic		Diluted	Basic		Diluted
Amounts Attributed to Phillips 66 Common Stockholders (millions):
Income from continuing operations attributable to Phillips 66	$	4,056		4,056	3,665		3,665	4,076		4,076
Income allocated to participating securities	(7		)	—	(5	)	—	(2	)	—
Income from continuing operations available to common stockholders	4,049			4,056	3,660		3,665	4,074		4,076
Discontinued operations	706			706	61		61	48		48
Net income available to common stockholders	$	4,755		4,762	3,721		3,726	4,122		4,124

Weighted-average common shares outstanding (thousands):	561,859			565,902	608,983		612,918	625,519		628,835
Effect of stock-based compensation	4,043			5,602	3,935		6,071	3,316		7,929
Weighted-average common shares outstanding—EPS	565,902			571,504	612,918		618,989	628,835		636,764

Earnings Per Share of Common Stock (dollars):
Income from continuing operations attributable to Phillips 66	$	7.15		7.10	5.97		5.92	6.47		6.40
Discontinued operations	1.25			1.23	0.10		0.10	0.08		0.08
Earnings Per Share	$	8.40		8.33	6.07		6.02	6.55		6.48

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Note 14—Debt

Long-term debt at December 31 was:



	Millions of Dollars
	2014			2013

1.95% Senior Notes due 2015	$	800		800
2.95% Senior Notes due 2017	1,500			1,500
4.30% Senior Notes due 2022	2,000			2,000
4.65% Senior Notes due 2034	1,000			—
4.875% Senior Notes due 2044	1,500			—
5.875% Senior Notes due 2042	1,500			1,500
Industrial Development Bonds due 2018 through 2021 at 0.02%-0.05% at year-end 2014 and 0.05%-0.07% at year-end 2013	50			50
Sweeny Cogeneration, L.P. notes due 2020 at 7.54%	53			—
Note payable to Merey Sweeny, L.P. due 2020 at 7% (related party)	97			110
Phillips 66 Partners revolving credit facility due 2019 at 1.33% at year-end 2014	18			—
Other	1			1
Debt at face value	8,519			5,961
Capitalized leases	210			199
Net unamortized premiums and discounts	(45		)	(5	)
Total debt	8,684			6,155
Short-term debt	(842		)	(24	)
Long-term debt	$	7,842		6,131

Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2015 through 2019 are: $842 million, $36 million, $1,539 million, $47 million and $51 million, respectively.

In November 2014, we issued $2.5 billion of Senior Notes comprised of $1 billion of 4.65% Senior Notes due 2034 and $1.5 billion of 4.875% Senior Notes due 2044. The notes are guaranteed by Phillips 66 Company, a wholly owned subsidiary. A portion of the net proceeds will be used to repay $800 million in aggregate principal amount of our outstanding 1.95% Senior Notes due 2015.

Credit Facilities and Commercial Paper

During the fourth quarter of 2014, we amended our Phillips 66 revolving credit facility, primarily to increase its borrowing capacity from $4.5 billion to $5 billion and to extend the term from June 2018 to December 2019. The Phillips 66 facility may be used for direct bank borrowings, as support for issuances of letters of credit, or as support for our commercial paper program. The facility is with a broad syndicate of financial institutions and contains covenants that we consider usual and customary for an agreement of this type for comparable commercial borrowers, including a maximum consolidated net debt-to-capitalization ratio of 60 percent. The agreement has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violation of covenants; cross-payment default and cross-acceleration (in each case, to indebtedness in excess of a threshold amount); and 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 Ratings Services (S&P) and Moody’s Investors Service (Moody’s). The facility also provides for customary fees, including administrative agent fees and commitment fees. As of December 31, 2014, no amount had been directly drawn under this facility and $51 million in letters of credit had been issued that were supported by the facility. As a result, we ended 2014 with $4.9 billion of capacity under this facility.

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Trade Receivables Securitization Facility

Effective September 30, 2014, we terminated our $696 million trade receivables securitization facility. No amounts were drawn against this facility throughout its duration, and at the time of termination no letters of credit were outstanding thereunder.

Note 15—Guarantees

At December 31, 2014, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.

Guarantees of Joint Venture Debt

In 2012, in connection with the Separation, we issued a guarantee for 100 percent of the 8.85% Senior Notes issued by MSLP in July 1999. At December 31, 2014, the maximum potential amount of future payments to third parties under the guarantee was estimated to be $189 million, which could become payable if MSLP fails to meet its obligations under the senior notes agreement. The senior notes mature in 2019.

Other Guarantees

We have residual value guarantees associated with leases with maximum future potential payments totaling $384 million. We have other guarantees with maximum future potential payment amounts totaling $112 million, which consist primarily of guarantees to fund the short-term cash liquidity deficits of certain joint ventures, guarantees of third parties related to prior asset dispositions, and guarantees of the lease payment obligations of a joint venture. These guarantees generally extend up to 10 years or the life of the venture.

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 qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, litigation, environmental liabilities, permits and licenses, supply arrangements, and employee claims; and real estate indemnity against tenant defaults. The provisions of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite, and the maximum amount of future payments is generally unlimited. The carrying amount recorded for indemnifications at December 31, 2014, was $220 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is 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

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estimate of the maximum potential amount of future payments. Included in the recorded carrying amount were $102 million of environmental accruals for known contamination that were included in asset retirement obligations and accrued environmental costs at December 31, 2014. For additional information about environmental liabilities, see Note 16—Contingencies and Commitments.

Indemnification and Release Agreement

In 2012, we entered into the Indemnification and Release Agreement with ConocoPhillips. This agreement governs the treatment between ConocoPhillips and us of matters relating to indemnification, insurance, litigation responsibility and management, and litigation document sharing and cooperation arising in connection with the Separation. Generally, the agreement provides for cross-indemnities principally designed to place financial responsibility for the obligations and liabilities of our business with us and financial responsibility for the obligations and liabilities of ConocoPhillips’ business with ConocoPhillips. The agreement also establishes procedures for handling claims subject to indemnification and related matters.

Note 16—Contingencies and Commitments

A number of lawsuits involving a variety of claims have been brought against us in connection with matters that arise in the ordinary course of business. 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 accounting 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 record 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 22—Income Taxes, for additional information about income-tax-related contingencies.

Environmental

We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring 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 of those potentially responsible 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 cited 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

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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 and 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 acquired in a purchase 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 12—Asset Retirement Obligations and Accrued Environmental Costs, for a summary of our accrued environmental liabilities.

Legal Proceedings

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, 2014, we had performance obligations secured by letters of credit and bank guarantees of $490 million (of which $51 million was issued under the provisions of our revolving credit facility, and the remainder was issued as direct bank letters of credit and bank guarantees) 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 financing arrangements. The agreements typically provide for crude oil transportation to be used in the ordinary course of our business. The aggregate amounts of estimated payments under these various agreements are $333 million each year for years 2015 through 2019 and $3,700 million in the aggregate for years 2020 and thereafter. Total payments under the agreements were $328 million in 2014, $342 million in 2013 and $343 million in 2012.

Note 17—Derivatives and Financial Instruments

Derivative Instruments

We use financial and commodity-based derivative contracts to manage exposures to fluctuations in foreign currency exchange rates and commodity prices or to capture market opportunities. Since we are not currently using cash-flow hedge accounting, all gains and losses, realized or unrealized, from commodity derivative contracts have been recognized in the consolidated statement of income. Gains and losses from derivative contracts held for trading not directly related to our physical business, whether realized or unrealized, have been reported net in “Other income” on our consolidated statement of income. Cash flows from all our derivative activity for the periods presented appear in the operating section of the consolidated statement of cash flows.

Purchase and sales contracts with fixed minimum notional volumes for commodities that are readily convertible to cash (e.g., crude oil and gasoline) are recorded on the balance sheet as derivatives unless the contracts are eligible for, and we

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elect, the normal purchases and normal sales exception (i.e., contracts to purchase or sell quantities we expect to use or sell over a reasonable period in the normal course of business). We generally apply this normal purchases and normal sales exception to eligible crude oil, refined product, NGL, natural gas and power commodity purchase and sales contracts; however, we may elect not to apply this exception (e.g., when another derivative instrument will be used to mitigate the risk of the purchase or sales contract but hedge accounting will not be applied, in which case both the purchase or sales contract and the derivative contract mitigating the resulting risk will be recorded on the balance sheet at fair value). Our derivative instruments are held at fair value on our consolidated balance sheet. For further information on the fair value of derivatives, see Note 18—Fair Value Measurements.

Commodity Derivative Contracts—We operate in the worldwide crude oil, refined products, NGL, natural gas and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities; however, we use futures, forwards, swaps and options in various markets to balance physical systems, meet customer needs, manage price exposures on specific transactions, and do a limited, immaterial amount of trading not directly related to our physical business. 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. Derivatives may be used to optimize these activities, which may move our risk profile away from market average prices.

The following table indicates the balance sheet line items that include the fair values of commodity derivative assets and liabilities presented net (i.e., commodity derivative assets and liabilities with the same counterparty are netted where the right of setoff exists); however, the balances in the following table are presented gross. For information on the impact of counterparty netting and collateral netting, see Note 18—Fair Value Measurements.



	Millions of Dollars
	2014			2013
Assets
Accounts and notes receivable	$	(1	)	2
Prepaid expenses and other current assets	3,839			592
Other assets	29			2
Liabilities
Other accruals	3,472			633
Other liabilities and deferred credits	1			1

Hedge accounting has not been used for any item in the table.

The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated statement of income, were:



	Millions of Dollars
	2014		2013		2012

Sales and other operating revenues	$	658	17		3
Equity in earnings of affiliates	66		(19	)	6
Other income	20		3		39
Purchased crude oil and products	136		95		32

Hedge accounting has not been used for any item in the table.

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The following table summarizes our material net exposures resulting from outstanding commodity derivative contracts. These financial and physical derivative contracts are primarily used to manage price exposure on our underlying operations. The underlying exposures may be from non-derivative positions such as inventory volumes. Financial derivative contracts may also offset physical derivative contracts, such as forward sales contracts. The percentage of our derivative contract volumes expiring within the next 12 months was approximately 99 percent at both December 31, 2014 and 2013.



	Open Position Long / (Short)
	2014		2013
Commodity
Crude oil, refined products and NGL (millions of barrels)	(11	)	(9	)

Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of over-the-counter (OTC) derivative contracts and trade receivables.

The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.

Our trade receivables result primarily from the sale of products from, or related to, our refinery operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less. We continually monitor this exposure and the creditworthiness of the counterparties and recognize bad debt expense based on historical write-off experience or specific counterparty collectability. Generally, we do not require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments, and 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 us.

Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if our credit ratings fall below investment grade. Cash is the primary collateral in all contracts; however, many contracts also permit us to post letters of credit as collateral.

The aggregate fair values of all derivative instruments with such credit-risk-related contingent features that were in a liability position were not material at December 31, 2014 or 2013.

Note 18—Fair Value Measurements

Fair Values of Financial Instruments

We used the following methods and assumptions to estimate the fair value of financial instruments:


•	Cash and cash equivalents: The carrying amount reported on the consolidated balance sheet approximates fair value.

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•	Accounts and notes receivable: The carrying amount reported on the consolidated balance sheet approximates fair value.


•	Debt: The carrying amount of our floating-rate debt approximates fair value. The fair value of our fixed-rate debt is estimated based on quoted market prices.


•	Commodity swaps: Fair value is estimated based on forward market prices and approximates the exit price at period end. 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.


•	Futures: Fair values are based on quoted market prices obtained from the New York Mercantile Exchange, the InterContinentalExchange, or other traded exchanges.


•	Forward-exchange contracts: Fair value is estimated by comparing the contract rate to the forward rate in effect at the end of the reporting period, which approximates the exit price at that date.

We carry certain assets and liabilities at fair value, which we measure at the reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability), and disclose the quality of these fair values based on the valuation inputs used in these measurements under the following hierarchy:


•	Level 1: Fair value measured with unadjusted quoted prices from an active market for identical assets or liabilities.


•	Level 2: Fair value measured with: 1) adjusted quoted prices from an active market for similar assets; 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 lowest level of input significant to its 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. We made no material transfers in or out of Level 1 during the twelve-month periods ended December 31, 2014 and 2013.

Recurring Fair Value Measurements

Financial assets and liabilities recorded at fair value on a recurring basis consist primarily of investments to support nonqualified deferred compensation plans and derivative instruments. The deferred compensation investments are measured at fair value using unadjusted prices available from national securities exchanges; therefore, these assets are categorized as Level 1 in the fair value hierarchy. We value our exchange-traded commodity derivatives using closing prices provided by the exchange as of the balance sheet date, and these are also classified as Level 1 in the fair value hierarchy. When exchange-cleared contracts lack sufficient liquidity or are valued using either adjusted exchange-provided prices or non-exchange quotes, we classify those contracts as Level 2. OTC financial swaps and physical commodity forward purchase and sales contracts are generally valued using quotations 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. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC swaps and physical commodity purchase and sales contracts are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. We classify these contracts as Level 3. Financial OTC and physical commodity options are valued using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines whether the options are classified as Level 2 or 3. We use a mid-market pricing convention (the mid-point between bid and ask prices). When appropriate, valuations are adjusted to reflect credit considerations, generally based on available market evidence.

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The following tables display the fair value hierarchy for our material financial assets and liabilities either accounted for or disclosed at fair value on a recurring basis. These values are determined by treating each contract as the fundamental unit of account; therefore, derivative assets and liabilities with the same counterparty are shown gross (i.e., without the effect of netting where the legal right of setoff exists) in the hierarchy sections of these tables. These tables also show that our Level 3 activity was not material.

We have master netting arrangements for all of our exchange-cleared derivative instruments, the majority of our OTC derivative instruments, and certain physical commodity forward contracts (primarily pipeline crude oil deliveries). The following tables show the fair values of these contracts on a net basis in the column “Effect of Counterparty Netting,” which is how these also appear on the consolidated balance sheet.

The carrying values and fair values by hierarchy of our material financial instruments and physical commodity forward contracts, either carried or disclosed at fair value, including any effects of netting derivative assets with liabilities and netting collateral due to right of setoff or master netting agreements were:



	Millions of Dollars
	December 31, 2014
	Fair Value Hierarchy				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	Cash Collateral Received or Paid, Not Offset on Balance Sheet
	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	$	2,058	1,525	—	3,583	(3,255	)	(225	)	—		103	—
OTC instruments	—		24	—	24	(14	)	—		—		10	—
Physical forward contracts*	—		253	7	260	(38	)	—		—		222	—
Rabbi trust assets	76		—	—	76	N/A		N/A		—		76	N/A
	$	2,134	1,802	7	3,943	(3,307	)	(225	)	—		411

Commodity Derivative Liabilities
Exchange-cleared instruments	$	1,833	1,422	—	3,255	(3,255	)	—		—		—	—
OTC instruments	—		29	—	29	(14	)	—		—		15	—
Physical forward contracts*	—		189	—	189	(38	)	—		—		151	—
Floating-rate debt	68		—	—	68	N/A		N/A		—		68	N/A
Fixed-rate debt, excluding capital leases**	—		8,806	—	8,806	N/A		N/A		(400	)	8,406	N/A
	$	1,901	10,446	—	12,347	(3,307	)	—		(400	)	8,640

*Physical forward contracts may have a larger value on the balance sheet than disclosed in the fair value hierarchy when the remaining contract term at the reporting date is greater than 12 months and the short-term portion is an asset while the long-term portion is a liability, or vice versa.

**We carry fixed-rate debt on the balance sheet at amortized cost.

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	Millions of Dollars
	December 31, 2013
	Fair Value Hierarchy				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	Cash Collateral Received or Paid, Not Offset on Balance Sheet
	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	$	227	332	—	559	(538	)	—		—		21	—
OTC instruments	—		10	—	10	(8	)	—		—		2	—
Physical forward contracts*	—		25	2	27	—		—		—		27	—
Rabbi trust assets	64		—	—	64	N/A		N/A		—		64	N/A
	$	291	367	2	660	(546	)	—		—		114

Commodity Derivative Liabilities
Exchange-cleared instruments	$	253	326	—	579	(538	)	(41	)	—		—	—
OTC instruments	—		11	—	11	(8	)	—		—		3	—
Physical forward contracts*	—		43	1	44	—		—		—		44	—
Floating-rate debt	50		—	—	50	N/A		N/A		—		50	N/A
Fixed-rate debt, excluding capital leases**	—		6,168	—	6,168	N/A		N/A		(262	)	5,906	N/A
	$	303	6,548	1	6,852	(546	)	(41	)	(262	)	6,003

**We carry fixed-rate debt on the balance sheet at amortized cost.

The values presented in the preceding tables appear on our balance sheet as follows: for commodity derivative assets and liabilities, see the first table in Note 17—Derivatives and Financial Instruments; rabbi trust assets appear in the “Investments and long-term receivables” line; and floating-rate and fixed-rate debt appear in the “Short-term debt” and “Long-term debt” lines.

Nonrecurring Fair Value Remeasurements

The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition during the years ended December 31, 2014 and 2013:



	Millions of Dollars
			Fair Value Measurements Using
	Fair Value*		Level 1 Inputs	Level 3 Inputs	Before- Tax Loss
Year Ended December 31, 2014
Net properties, plants and equipment (held for use)	$	20	—	20	131
Net asset disposal group (held for sale)	72		72	—	12

Year Ended December 31, 2013
Net properties, plants and equipment (held for use)	$	22	22	—	27

*Represents the classification and fair value at the time of the impairment.

During 2014, net PP&E held for use related to our Whitegate Refinery in Ireland included in our Refining segment, with a carrying amount of $151 million, was written down to its fair value of $20 million, resulting in a before-tax loss of $131 million. The fair value was determined based on the highest and best use of these assets to a principal market participant using market transactions of similar assets with adjustments to reflect the condition of the assets. In addition,

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net assets held for sale related to the Bantry Bay terminal in our Refining segment, with a carrying amount of $84 million, primarily consisting of net PP&E, were written down to fair value less costs to sell, resulting in a before-tax loss of $12 million. This impairment was attributed to the long-lived assets in the disposal group. The fair value was determined by a negotiated selling price with a third party. See Note 7—Assets Held for Sale or Sold, for additional information.

During 2013, net PP&E held for use related to the composite graphite business in our M&S segment, with a carrying amount of $18 million, was written down to its fair value, resulting in a before-tax loss of $18 million. The fair value was based on an internal assessment of expected discounted future cash flows. During this same period, corporate net PP&E held for use, with a carrying amount of $31 million, was written down to its fair value of $22 million, resulting in a before-tax loss of $9 million. The fair value was primarily determined by a third-party valuation.

Note 19—Equity

Preferred Stock

We have 500 million shares of preferred stock authorized, with a par value of $0.01 per share. No shares of preferred stock were outstanding as of December 31, 2014 or 2013.

Treasury Stock

During 2012 and 2013, our Board of Directors authorized repurchases totaling up to $5 billion of our outstanding common stock. In 2014, our Board of Directors authorized additional share repurchases totaling up to $2 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 the company’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements and the Tax Sharing Agreement entered into in connection with the Separation. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Since the inception of our share repurchases in 2012, through December 31, 2014, we have repurchased a total of 73,227,369 shares at a cost of $4.9 billion. Shares of stock repurchased are held as treasury shares.

Common Stock Dividends

On February 4, 2015, our Board of Directors declared a quarterly cash dividend of $0.50 per common share, payable March 2, 2015, to holders of record at the close of business on February 17, 2015.

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Note 20—Leases

We lease ocean transport vessels, tugboats, barges, pipelines, railcars, service station sites, computers, office buildings, corporate aircraft, land and other facilities and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices, as well as renewal options and/or options to purchase the leased property. There are no significant restrictions imposed on us by the leasing agreements with regard to dividends, asset dispositions or borrowing ability. Our capital lease obligations relate primarily to the lease of an oil terminal in the United Kingdom. The lease obligation is subject to foreign currency translation adjustments each reporting period. The total net PP&E recorded for capital leases was $203 million and $206 million at December 31, 2014 and 2013, respectively.

Future minimum lease payments as of December 31, 2014, for capital lease obligations and operating lease obligations having initial or remaining payments due under noncancelable leases were:



	Millions of Dollars
	Capital Lease Obligations		Operating Lease Obligations

2015	$	26	489
2016	16		387
2017	17		298
2018	15		218
2019	15		160
Remaining years	191		456
Total	280		2,008
Less: income from subleases	—		96
Net minimum lease payments	$	280	1,912
Less: amount representing interest	70
Capital lease obligations	$	210

Operating lease rental expense for the years ended December 31 was:



	Millions of Dollars
	2014		2013	2012

Minimum rentals	$	570	572	554
Contingent rentals	8		7	8
Less: sublease rental income	135		133	93
	$	443	446	469

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Note 21—Employee Benefit Plans

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:



	Millions of Dollars
	Pension Benefits									Other Benefits
	2014					2013				2014		2013
	U.S.			Int’l.		U.S.		Int’l.
Change in Benefit Obligation
Benefit obligation at January 1	$	2,473		840		2,624		757		189		191
Service cost	121			38		125		36		7		8
Interest cost	108			35		91		31		8		7
Plan participant contributions	—			4		—		4		1		—
Actuarial loss (gain)	409			116		(194	)	1		4		(14	)
Benefits paid	(216		)	(18	)	(173	)	(15	)	(6	)	(3	)
Foreign currency exchange rate change	—			(74	)	—		26		—		—
Benefit obligation at December 31*	$	2,895		941		2,473		840		203		189
*Accumulated benefit obligation portion of above at December 31:	$	2,553		729		2,151		627

Change in Fair Value of Plan Assets
Fair value of plan assets at January 1	$	2,008		645		1,762		527		—		—
Actual return on plan assets	168			89		283		60		—		—
Company contributions	164			60		136		50		5		3
Plan participant contributions	—			4		—		4		1		—
Benefits paid	(216		)	(18	)	(173	)	(15	)	(6	)	(3	)
Foreign currency exchange rate change	—			(56	)	—		19		—		—
Fair value of plan assets at December 31	$	2,124		724		2,008		645		—		—

Funded Status at December 31	$	(771	)	(217	)	(465	)	(195	)	(203	)	(189	)

Amounts recognized in the consolidated balance sheet for our pension and other postretirement benefit plans at December 31, 2014 and 2013, include:



	Millions of Dollars
	Pension Benefits									Other Benefits
	2014					2013				2014		2013
	U.S.			Int’l.		U.S.		Int’l.
Amounts Recognized in the Consolidated Balance Sheet at December 31
Noncurrent assets	$	—		13		—		2		—		—
Current liabilities	(8		)	—		(8	)	—		(6	)	(3	)
Noncurrent liabilities	(763		)	(230	)	(457	)	(197	)	(197	)	(186	)
Total recognized	$	(771	)	(217	)	(465	)	(195	)	(203	)	(189	)

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Included in accumulated other comprehensive income at December 31 were the following before-tax amounts that had not been recognized in net periodic benefit cost:



	Millions of Dollars
	Pension Benefits							Other Benefits
	2014				2013			2014		2013
	U.S.		Int’l.		U.S.	Int’l.

Unrecognized net actuarial loss (gain)	$	741	165		399	120		(13	)	(18	)
Unrecognized prior service cost (credit)	9		(9	)	12	(11	)	(12	)	(13	)



	Millions of Dollars
	Pension Benefits								Other Benefits
	2014					2013			2014		2013
	U.S.			Int’l.		U.S.	Int’l.
Sources of Change in Other Comprehensive Income
Net gain (loss) arising during the period	$	(382	)	(57	)	356	25		(3	)	14
Amortization of (gain) loss included in income	40			12		84	16		(2	)	—
Net change during the period	$	(342	)	(45	)	440	41		(5	)	14

Prior service cost arising during the period	$	—		—		—	—		—		—
Amortization of prior service cost (credit) included in income	3			(2	)	3	(1	)	(1	)	(2	)
Net change during the period	$	3		(2	)	3	(1	)	(1	)	(2	)

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For our tax-qualified pension plans with projected benefit obligations in excess of plan assets, the projected benefit obligation, the accumulated benefit obligation, and the fair value of plan assets were $3,189 million, $2,815 million, and $2,295 million, respectively, at December 31, 2014, and $2,757 million, $2,407 million, and $2,177 million, respectively, at December 31, 2013. For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and the accumulated benefit obligation were $107 million and $83 million, respectively, at December 31, 2014, and $82 million and $58 million, respectively, at December 31, 2013.

The allocated benefit cost from Shared Plans, as well as the components of net periodic benefit cost associated with plans sponsored by us, for 2014, 2013 and 2012 is shown in the table below:



	Millions of Dollars
	Pension Benefits													Other Benefits
	2014					2013				2012				2014		2013		2012
	U.S.			Int’l.		U.S.		Int’l.		U.S.		Int’l.
Components of Net Periodic Benefit Cost
Service cost	$	121		38		125		36		82		22		7		8		4
Interest cost	108			35		91		31		65		25		8		7		5
Expected return on plan assets	(142		)	(37	)	(120	)	(29	)	(81	)	(21	)	—		—		—
Amortization of prior service cost (credit)	3			(2	)	3		(1	)	2		(1	)	(1	)	(2	)	—
Recognized net actuarial loss (gain)	40			12		84		16		49		7		(2	)	—		(1	)
Subtotal net periodic benefit cost	130			46		183		53		117		32		12		13		8
Allocated benefit cost from ConocoPhillips	—			—		—		—		71		13		—		—		7
Total net periodic benefit cost	$	130		46		183		53		188		45		12		13		15

In determining net periodic benefit cost, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize 10 percent of the unamortized balance each year. The amount subject to amortization is determined on a plan-by-plan basis. Amounts included in accumulated other comprehensive income at December 31, 2014, that are expected to be amortized into net periodic benefit cost during 2015 are provided below:



	Millions of Dollars
	Pension Benefits				Other Benefits
	U.S.		Int’l.

Unrecognized net actuarial loss (gain)	$	75	16		(1	)
Unrecognized prior service cost (credit)	3		(2	)	(1	)

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The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:



	Pension Benefits					Other Benefits
	2014			2013		2014	2013
	U.S.		Int’l.	U.S.	Int’l.
Assumptions Used to Determine Benefit Obligations:
Discount rate	3.90	%	3.10	4.55	4.30	3.70	4.40
Rate of compensation increase	4.00		3.20	4.00	3.90	—	—

Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate	4.55	%	4.30	3.60	4.20	4.40	3.70
Expected return on plan assets	7.00		5.50	7.00	5.50	—	—
Rate of compensation increase	4.00		3.90	3.85	3.60	—	—

For both U.S. and international pension plans, the overall expected long-term rate of return is developed from the expected future return of each asset class, weighted by the expected allocation of pension assets to that asset class. We rely on a variety of independent market forecasts in developing the expected rate of return for each class of assets.

Our other postretirement benefit plans for health insurance are contributory. Effective December 31, 2012, we terminated the subsidy for retiree medical. On or after January 1, 2013, eligible employees are 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 2015 that declines to 5.00 percent by 2023. A one percentage-point change in the assumed health care cost trend rate would be immaterial to Phillips 66.

Plan Assets

The investment strategy for managing pension plan assets is to seek a reasonable rate of return relative to an appropriate level of risk and provide adequate liquidity for benefit payments and portfolio management. We follow a policy of broadly diversifying pension plan assets across asset classes, investment managers, and individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include equities, fixed income, cash, real estate and insurance contracts. Plan fiduciaries may consider and add other asset classes to the investment program from time to time. The target allocations for plan assets are approximately 62 percent equity securities, 37 percent debt securities and 1 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 categorized in Level 1 are primarily based on quoted market prices.

•

Fair values of corporate debt securities, agency and mortgage-backed securities and government debt securities categorized in Level 2 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 market value is calculated by pricing models that benchmark the security against other securities with actual market prices.


•	Fair values of investments in common/collective trusts are determined by the issuer of each fund based on the

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fair value of the underlying assets.


•	Fair values of mutual funds are valued based on quoted market prices, which represent the net asset value of shares held. Certain mutual funds are categorized in Level 2 as they are not valued on a daily basis.


•	Cash and cash equivalents are valued at cost, which approximates fair value.


•	Fair values of exchange-traded derivatives classified in Level 1 are based on quoted market prices. For other derivatives classified in Level 2, the fair values are generally calculated from pricing models with market input parameters from third-party sources.


•	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 real estate investments are valued using real estate valuation techniques and other methods that include reference to third-party sources and sales comparables where available.

The fair values of our pension plan assets at December 31, by asset class, were as follows:



	Millions of Dollars
	U.S.					International
	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
2014
Equity Securities
U.S.	$	288	—	—	288	161	—	—	161
International	163		—	—	163	113	—	—	113
Common/collective trusts	—		920	—	920	—	110	—	110
Mutual funds	—		—	—	—	5	—	—	5
Debt Securities
Government	—		32	—	32	141	—	—	141
Corporate	—		51	—	51	—	—	—	—
Agency and mortgage-backed securities	—		—	—	—	—	—	—	—
Common/collective trusts	—		648	—	648	—	161	—	161
Mutual funds	—		—	—	—	2	—	—	2
Cash and cash equivalents	20		—	—	20	10	—	—	10
Derivatives	—		—	—	—	—	—	—	—
Insurance contracts	—		—	—	—	—	—	14	14
Real estate	—		—	—	—	—	—	7	7
Total*	$	471	1,651	—	2,122	432	271	21	724
* Fair values in the table exclude net receivables of $2 million.

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	Millions of Dollars
	U.S.						International
	Level 1			Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
2013
Equity Securities
U.S.	$	552		—	—	552	129	—	—	129
International	439			—	—	439	104	—	—	104
Common/collective trusts	—			302	—	302	—	103	—	103
Mutual funds	—			42	—	42	5	—	—	5
Debt Securities
Government	114			70	—	184	117	—	—	117
Corporate	—			305	—	305	—	—	—	—
Agency and mortgage-backed securities	—			90	—	90	—	—	—	—
Common/collective trusts	—			17	—	17	—	148	—	148
Mutual funds	—			—	—	—	1	—	—	1
Cash and cash equivalents	77			—	—	77	14	—	—	14
Derivatives	(1		)	1	—	—	—	—	—	—
Insurance contracts	—			—	—	—	—	—	16	16
Real estate	—			—	—	—	—	—	8	8
Total	$	1,181		827	—	2,008	370	251	24	645

As reflected in the table above, Level 3 activity was not material.

Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to international plans are subject to local laws and tax regulations. Actual contribution amounts are dependent upon plan asset returns, changes in pension obligations, regulatory environments, and other economic factors. In 2015, we expect to contribute approximately $30 million to our U.S. pension plans and other postretirement benefit plans and $70 million to our international pension plans.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by us in the years indicated:



	Millions of Dollars
	Pension Benefits			Other Benefits
	U.S.		Int’l.

2015	$	252	17	13
2016	254		22	15
2017	262		24	17
2018	277		23	18
2019	300		26	19
2020-2023	1,405		149	104

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Defined Contribution Plans

Most U.S. employees are eligible to participate in the Phillips 66 Savings Plan (Savings Plan). Employees can contribute up to 75 percent of their eligible pay, subject to certain statutory limits, in the thrift feature of the Savings Plan to a choice of investment funds. Phillips 66 provides a company match of participant thrift contributions up to 5 percent of eligible pay. In addition, participants who contribute at least 1 percent to the Savings Plan are eligible for “Success Share,” a semi-annual discretionary company contribution to the Savings Plan that can range from 0 to 6 percent of eligible pay, with a target of 2 percent. For the period January 2014 through June 2014, Success Share had an actual payout of 4 percent and for the period July 2014 through December 2014, it had an actual payout of 4 percent. For the period January 2013 through June 2013, Success Share had an actual payout of 3 percent and for the period July 2013 through December 2013, it had an actual payout of 5 percent.

The Savings Plan was amended effective January 1, 2013. Prior to that date, the company matched up to 1.25 percent of eligible pay, the Success Share did not exist, and instead the plan included a stock savings feature (discussed below). The total expense related to participants in the Savings Plan and predecessor plans for Phillips 66 employees, excluding the stock savings feature, was $112 million in 2014, $111 million in 2013 and $15 million in 2012.

Prior to the Separation, the stock savings feature of the Savings Plan was a leveraged employee stock ownership plan. After the Separation, it was a non-leveraged employee stock ownership plan. Employees could elect to participate in the stock savings feature by contributing 1 percent of eligible pay. Subsequently, they received a proportionate allocation of shares of common stock. The total expense related to participants of Phillips 66 in this stock savings feature and predecessor plans for Phillips 66 employees was $157 million in 2012, all of which was compensation expense. The stock savings feature of the Savings Plan was terminated on December 31, 2012.

Share-Based Compensation Plans

Prior to the Separation, our employees participated in the “2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips” (the COP Omnibus Plan), under which they were eligible to receive ConocoPhillips stock options, restricted stock units (RSUs) and restricted performance share units (PSUs). Effective on the separation date of April 30, 2012, our employees and non-employee directors began participating in the “Omnibus Stock and Performance Incentive Plan of Phillips 66” (the 2012 Plan). The 2012 Plan was superseded by the 2013 Omnibus Stock and Performance Incentive Plan of Phillips 66 (the P66 Omnibus Plan) that was approved by shareholders in May 2013. Subsequent to this approval, all new share-based awards are granted under the P66 Omnibus Plan.

The P66 Omnibus Plan authorizes the Human Resources and Compensation Committee of our Board of Directors (the Committee) 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 shares issued under the P66 Omnibus Plan to settle share-based awards may not exceed 45 million.

In connection with the Separation, share-based compensation awards granted under the COP Omnibus Plan and held by grantees as of April 30, 2012, were adjusted or substituted to preserve the intrinsic value of the awards as of April 30, 2012, as follows:


•	Exercisable awards of stock options and stock appreciation rights were converted in accordance with the Employee Matters Agreement providing the grantee with replacement options to purchase both ConocoPhillips and Phillips 66 common stock.


•	Unexercisable awards of stock options held by Phillips 66 employees were replaced with substitute options to purchase only Phillips 66 common stock.


•	Restricted stock and PSUs awarded for completed performance periods under the ConocoPhillips Performance Share Program (PSP) were converted in accordance with the Employee Matters Agreement providing the grantee with both ConocoPhillips and Phillips 66 restricted stock and PSUs.


•	Restricted stock and RSUs held by Phillips 66 employees under all programs other than the PSP were replaced entirely with Phillips 66 restricted stock and RSUs.

Awards granted in connection with the adjustment and substitution of awards originally issued under the COP Omnibus Plan are a part of and became subject to the 2012 Plan.

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The aforementioned adjustment and substitution of awards resulted in the recognition of $9 million of incremental compensation expense in the second quarter of 2012.

Our share-based compensation 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. For share-based awards granted prior to our adoption of Statement of Financial Accounting Standards No. 123(R), codified into Financial Accounting Standards Board Accounting Standards Codification (ASC) Topic 718, “Compensation—Stock Compensation,” we recognize expense over the period of time during which the employee earns the award, accelerating the recognition of expense only when an employee actually retires. For share-based awards granted after our adoption of ASC 718 on January 1, 2006, we recognize share-based compensation expense over the shorter of: the service period (i.e., the stated period of time required to earn the award); or 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 to not be subject to forfeiture.

Some of our share-based awards vest ratably (i.e., portions of the award vest at different times) while some of our awards cliff vest (i.e., all of the award vests at the same time). The company made a policy election under ASC 718 to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.

Total share-based compensation expense recognized in income and the associated tax benefit for the years ended December 31 were as follows:



	Millions of Dollars
	2014			2013		2012

Compensation cost	$	134		132		94
Tax benefit	(50		)	(50	)	(35	)

Stock Options

Stock options granted under the provisions of the P66 Omnibus Plan and earlier plans permit purchase of our common stock at exercise prices equivalent to the average market price of the stock on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-third of the options awarded vesting and becoming exercisable on each anniversary date for the three years following the date of grant. Options awarded to employees already eligible for retirement vest within six months of the grant date, but those options do not become exercisable until the end of the normal vesting period.

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The following summarizes our stock option activity from January 1, 2014, to December 31, 2014:



							Millions of Dollars
	Options		Weighted- Average Exercise Price		Weighted-Average Grant-Date Fair Value		Aggregate Intrinsic Value

Outstanding at January 1, 2014	6,890,066		$	30.38
Granted	570,100		72.26		$	18.95
Forfeited	(13,967	)	69.46
Exercised	(1,602,642	)	27.15				$	89
Expired or canceled	(2	)	14.62
Outstanding at December 31, 2014	5,843,555		$	35.26

Vested at December 31, 2014	5,508,738		$	33.78			$	212

Exercisable at December 31, 2014	4,468,680		$	28.80			$	195

All option awards presented in this table are for Phillips 66 stock only, including those awards held by ConocoPhillips employees.

The weighted-average remaining contractual terms of vested options and exercisable options at December 31, 2014, were 5.71 years and 5.14 years, respectively. During 2014, we received $44 million in cash and realized a tax benefit of $9 million from the exercise of options. At December 31, 2014, the remaining unrecognized compensation expense from unvested options held by employees of Phillips 66 was $3 million, which will be recognized over a weighted-average period of 20 months, the longest period being 25 months. The calculations of realized tax benefit, unamortized expense and weighted-average periods include awards based on both Phillips 66 and ConocoPhillips stock held by Phillips 66 employees.

During 2013, we granted options with a weighted-average grant-date fair value of $16.77 and our employees exercised options with an aggregate intrinsic value of $81 million.

The following table provides the significant assumptions used to calculate the grant date fair market values of options granted over the years shown below, as calculated using the Black-Scholes-Merton option-pricing model:



	2014		2013	2012
Assumptions used
Risk-free interest rate	1.96	%	1.18	1.62
Dividend yield	3.00	%	2.50	4.00
Volatility factor	34.97	%	35.47	33.30
Expected life (years)	6.23		6.23	7.42

Prior to the Separation, we calculated volatility using the most recent ConocoPhillips end-of-week closing stock prices spanning a period equal to the expected life of the options granted. We calculate the volatility of options granted after the Separation using a formula that adjusts the pre-Separation historical volatility of ConocoPhillips by the ratio of Phillips 66 implied market volatility on the grant date divided by the pre-Separation implied market volatility of ConocoPhillips.

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.

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Restricted Stock Unit Program

Generally, RSUs are granted annually under the provisions of the P66 Omnibus Plan and cliff vest at the end of three years. Most RSU awards granted prior to the Separation vested ratably over five years, with one-third of the units vesting in 36 months, one-third vesting in 48 months, and the final third vesting 60 months from the date of grant. In addition to the regularly scheduled annual awards, RSUs are also granted ad hoc to attract or retain key personnel, and the terms and conditions under which these RSUs vest vary by award. Upon vesting, RSUs are settled by issuing one share of Phillips 66 common stock per RSU. RSUs awarded to employees already eligible for retirement vest within six months of the grant date, but those units are not issued as shares until the end of the normal vesting period. Until issued as stock, most recipients of RSUs receive a quarterly cash payment of a dividend equivalent, and for this reason the grant date fair value of these units is deemed equal to the average Phillips 66 stock price on the date of grant. The grant date fair market value of RSUs that do not receive a dividend equivalent while unvested is deemed equal to the average Phillips 66 common stock price on the grant date, less the net present value of the dividend equivalents that will not be received.

The following summarizes our stock unit activity from January 1, 2014, to December 31, 2014:



					Millions of Dollars
	Stock Units		Weighted-Average Grant-Date Fair Value		Total Fair Value

Outstanding at January 1, 2014	4,440,261		$	35.48
Granted	818,213		73.28
Forfeited	(84,272	)	48.98
Issued	(1,527,286	)	27.88		$	116
Outstanding at December 31, 2014	3,646,916		$	46.83

Not Vested at December 31, 2014	2,159,724		$	47.55

All RSU awards presented in this table are for Phillips 66 stock only, including those awards held by ConocoPhillips employees.

At December 31, 2014, the remaining unrecognized compensation cost from the unvested RSU awards held by employees of Phillips 66 was $48 million, which will be recognized over a weighted-average period of 22 months, the longest period being 34 months. 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 2013, we granted RSUs with a weighted-average grant-date fair value of $62.14 and issued shares with an aggregate fair value of $100 million to settle RSUs.

Performance Share Program

Under the P66 Omnibus Plan, we also annually grant to senior management restricted PSUs that vest: (i) with respect to awards for performance periods beginning before 2009, when the employee becomes eligible for retirement by reaching age 55 with five years of service; or (ii) with respect to awards for performance periods beginning in 2009, five years after the grant date of the award (although recipients can elect to defer the lapsing of restrictions until retirement after reaching age 55 with five years of service); or (iii) with respect to awards for performance periods beginning in 2013 or later, on the grant date.

For PSU awards with performance periods beginning before 2013, we recognize compensation expense beginning on the date of grant and ending on the date the PSUs are scheduled to vest; however, since these awards are authorized three years prior to the grant date, we recognize compensation expense for employees that will become eligible for retirement by or shortly after the grant date over the period beginning on the date of authorization and ending on the date of grant. Since PSU awards with performance periods beginning in 2013 or later vest on the grant date, we recognize compensation expense beginning on the date of authorization and ending on the grant date for all employees participating in the PSU grant.

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We settle PSUs with performance periods that begin before 2013 by issuing one share of Phillips 66 common stock for each PSU. Recipients of these PSUs receive a quarterly cash payment of a dividend equivalent beginning on the grant date and ending on the settlement date.

We settle PSUs with performance periods beginning in 2013 or later by paying cash equal to the fair value of the PSU on the grant date, which is also the date the PSU vests. Since these PSUs vest and settle on the grant date, dividend equivalents are never paid on these awards.

The following summarizes our PSU activity from January 1, 2014, to December 31, 2014:



					Millions of Dollars
	Performance Share Units		Weighted-Average Grant-Date Fair Value		Total Fair Value

Outstanding at January 1, 2014	2,712,968		$	37.12
Granted	635,632		72.26
Forfeited	(14,774	)	52.39
Issued	(161,966	)	39.68		$	13
Outstanding at December 31, 2014	3,171,860		$	43.96

Not Vested at December 31, 2014	631,017		$	43.86

All PSU awards presented in this table are for Phillips 66 stock only, including those awards held by ConocoPhillips employees.

At December 31, 2014, the remaining unrecognized compensation cost from unvested PSU awards held by employees of Phillips 66 was $11 million, which will be recognized over a weighted-average period of 36 months, the longest period being 12 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 2013, we granted PSUs with a weighted-average grant-date fair value of $62.17 and issued shares with an aggregate fair value of $9 million to settle PSUs.

Note 22—Income Taxes

Income taxes charged to income were:



	Millions of Dollars
	2014			2013		2012
Income Taxes
Federal
Current	$	1,661		1,054		1,967
Deferred	(378		)	526		69
Foreign
Current	22			98		160
Deferred	80			(48	)	45
State and local
Current	274			146		253
Deferred	(5		)	68		(21	)
	$	1,654		1,844		2,473

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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:



	Millions of Dollars
	2014		2013
Deferred Tax Liabilities
Properties, plants and equipment, and intangibles	$	3,799	3,747
Investment in joint ventures	2,331		2,696
Investment in subsidiaries	115		401
Inventory	152		—
Other	29		—
Total deferred tax liabilities	6,426		6,844
Deferred Tax Assets
Benefit plan accruals	647		499
Inventory	—		51
Asset retirement obligations and accrued environmental costs	207		223
Other financial accruals and deferrals	131		223
Loss and credit carryforwards	149		123
Other	2		18
Total deferred tax assets	1,136		1,137
Less: valuation allowance	107		127
Net deferred tax assets	1,029		1,010
Net deferred tax liabilities	$	5,397	5,834

With the exception of certain foreign tax credit and separate company loss carryforwards, tax attributes were not allocated to us from ConocoPhillips. The foreign tax credit carryforwards were fully utilized by the end of 2014. The loss carryforwards, all of which are related to foreign operations, have indefinite carryforward periods.

Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be realized. During 2014, valuation allowances decreased by a total of $20 million. This decrease was primarily related to the utilization of certain foreign tax credits, partially offset by the recording of current year valuation allowances. Based on our historical taxable income, expectations for the future, and available tax-planning strategies, management expects remaining net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and the tax consequences of future taxable income.

As of December 31, 2014, we had undistributed earnings related to foreign subsidiaries and foreign corporate joint ventures of approximately $2 billion for which deferred income taxes have not been provided. We plan to reinvest these earnings for the foreseeable future. If these amounts were distributed to the United States, we would be subject to additional U.S. income taxes. Determination of the amount of unrecognized deferred income tax liability is not practicable due to the number of unknown variables inherent in the calculation.

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As a result of the Separation and pursuant to the Tax Sharing Agreement with ConocoPhillips, the unrecognized 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. Those unrecognized tax benefits are reflected in the following table which shows a reconciliation of the beginning and ending unrecognized tax benefits.



	Millions of Dollars
	2014			2013		2012

Balance at January 1	$	202		158		169
Additions based on tax positions related to the current year	13			30		3
Additions for tax positions of prior years	14			25		35
Reductions for tax positions of prior years	(68		)	(8	)	(47	)
Settlements	(19		)	(3	)	(2	)
Lapse of statute	—			—		—
Balance at December 31	$	142		202		158

Included in the balance of unrecognized tax benefits for 2014, 2013 and 2012 were $98 million, $161 million and $125 million, respectively, which, if recognized, would affect our effective tax rate. With respect to various unrecognized tax benefits and the related accrued liability, approximately $44 million may be recognized or paid within the next twelve months due to completion of audits.

At December 31, 2014, 2013 and 2012, accrued liabilities for interest and penalties totaled $16 million, $18 million and $15 million, respectively, net of accrued income taxes. Interest and penalties had no impact on earnings during 2014 and decreased earnings by $3 million and $6 million in 2013 and 2012, 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 (2011), Germany (2011) and United States (2008). Certain issues remain in dispute for audited years, and unrecognized tax benefits for years still subject to or currently undergoing an audit are subject to change. As a consequence, the balance in unrecognized 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 tax benefits, the amount of change is not estimable.

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The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes, were:



	Millions of Dollars							Percent of Pre-tax Income
	2014			2013		2012		2014		2013		2012
Income from continuing operations before income taxes
United States	$	5,121		5,158		6,192		89.1	%	93.3		94.4
Foreign	624			368		364		10.9		6.7		5.6
	$	5,745		5,526		6,556		100.0	%	100.0		100.0

Federal statutory income tax	$	2,011		1,934		2,295		35.0	%	35.0		35.0
Goodwill allocated to assets sold	18			—		9		0.3		—		0.1
Sale of MRC	(293		)	—		—		(5.1	)	—		—
Tax on foreign operations	(184		)	(198	)	141		(3.2	)	(3.6	)	2.2
Federal manufacturing deduction	(81		)	(68	)	(124	)	(1.4	)	(1.2	)	(1.9	)
State income tax, net of federal benefit	180			139		151		3.1		2.5		2.3
Other	3			37		1		0.1		0.7		—
	$	1,654		1,844		2,473		28.8	%	33.4		37.7

During 2012, we impaired a foreign investment for which no tax benefit was recognized. No tax benefit was recognized due to our ownership structure and assertion that the earnings of the foreign subsidiary that holds the investment will be reinvested for the foreseeable future. This item is reflected in “Tax on foreign operations” in the table above. Included in the line item “Sale of MRC” is a $224 million tax benefit related to the realization of excess tax basis during the fourth quarter.

Income tax benefits of $37 million, $34 million and $13 million for the years 2014, 2013 and 2012, respectively, are reflected in the “Capital in Excess of Par” column of the consolidated statement of equity.

Prior to the Separation, and except for certain state and dedicated foreign entity income tax returns, we were included in the ConocoPhillips income tax returns for all applicable years. In accordance with the Tax Sharing Agreement, a cash settlement was received from ConocoPhillips in 2013 upon the filing of the income tax return for the calendar year ended December 31, 2011. We received a further cash settlement in January 2014 for the January 1, 2012, through April 30, 2012 period. In 2013, we filed our initial U.S. consolidated income tax returns for the period May 1, 2012, through December 31, 2012.

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Note 23—Accumulated Other Comprehensive Income (Loss)

Changes in the balances of each component of accumulated other comprehensive income (loss) were as follows:



	Millions of Dollars
	Defined Benefit Plans			Foreign Currency Translation		Hedging		Accumulated Other Comprehensive Income (Loss)

December 31, 2011	$	(145	)	270		(3	)	122
Other comprehensive income (loss)	(93		)	196		1		104
Net transfer from ConocoPhillips*	(540		)	—		—		(540	)
December 31, 2012	(778		)	466		(2	)	(314	)
Other comprehensive income (loss) before reclassifications	312			(44	)	—		268
Amounts reclassified from accumulated other comprehensive income (loss)*
Foreign currency translation	—			21		—		21
Amortization of defined benefit plan items**
Actuarial losses	62			—		—		62
Net current period other comprehensive income (loss)	374			(23	)	—		351
December 31, 2013	(404		)	443		(2	)	37
Other comprehensive income (loss) before reclassifications	(330		)	(276	)	—		(606	)
Amounts reclassified from accumulated other comprehensive income (loss)*
Amortization of defined benefit plan items**
Actuarial losses	38			—		—		38
Net current period other comprehensive income (loss)	(292		)	(276	)	—		(568	)
December 31, 2014	$	(696	)	167		(2	)	(531	)

*See Consolidated Statement of Changes in Equity.

**Included in the computation of net periodic benefit cost. See Note 21—Employee Benefit Plans, for additional information.

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Note 24—Cash Flow Information



	Millions of Dollars
	2014		2013	2012
Noncash Investing and Financing Activities
Increase in net PP&E and debt related to capital lease obligation	$	33	177	—
Transfer of net PP&E in accordance with the Separation and Distribution Agreement with ConocoPhillips	—		—	374
Transfer of employee benefit obligations in accordance with the Separation and Distribution Agreement with ConocoPhillips	—		—	1,234
Increase in deferred tax assets associated with the employee benefit liabilities transferred in accordance with the Separation and Distribution Agreement with ConocoPhillips	—		—	461

Cash Payments
Interest	$	238	259	176
Income taxes*	2,185		1,021	2,183

*Excludes our share of cash tax payments made directly by ConocoPhillips prior to the Separation on April 30, 2012.

PSPI Noncash Stock Exchange

As discussed more fully in Note 7—Assets Held for Sale or Sold, on February 25, 2014, we completed the exchange of our flow improvers business for shares of Phillips 66 common stock owned by the other party to the transaction. The noncash portion of the net assets surrendered by us in the exchange was $204 million, and we received approximately 17.4 million shares of our common stock, with a fair value at the time of the exchange of $1.35 billion.

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Note 25—Other Financial Information



	Millions of Dollars Except Per Share Amounts
	2014			2013		2012
Interest and Debt Expense
Incurred
Debt	$	265		251		221
Other	22			24		25
	287			275		246
Capitalized	(20		)	—		—
Expensed	$	267		275		246

Other Income
Interest income	$	21		20		18
Other, net*	99			65		117
	$	120		85		135
*Includes derivatives-related activities. 2012 also includes a $37 million co-venturer contractual payment related to Rockies Express Pipeline.

Research and Development Expenditures—expensed	$	62		69		70

Advertising Expenses	$	70		68		57

Foreign Currency Transaction (Gains) Losses—after-tax
Midstream	$	—		—		—
Chemicals	—			—		—
Refining	6			(41	)	(17	)
Marketing and Specialties	8			(5	)	(5	)
Corporate and Other	—			2		—
	$	14		(44	)	(22	)

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Note 26—Related Party Transactions

Significant transactions with related parties were:



	Millions of Dollars
	2014		2013	2012

Operating revenues and other income (a)	$	6,514	7,907	8,226
Purchases (b)	15,647		18,320	22,446
Operating expenses and selling, general and administrative expenses (c)	133		109	208
Net interest expense (d)	7		8	8

(a)

We sold crude oil to MRC; NGL and other petrochemical feedstocks, along with solvents, to CPChem; gas oil and hydrogen feedstocks to Excel; and certain feedstocks and intermediate products to WRB. We also acted as agent for WRB in supplying other crude oil and feedstocks, wherein the transactional amounts did not impact operating revenues. In addition, we charged several of our affiliates, including CPChem and MSLP, for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.

(b)

We purchased refined products from WRB. We also acted as agent for WRB in distributing asphalt and solvents, wherein the transactional amounts did not impact purchases. We purchased natural gas and NGL from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchased refined products from MRC. We also paid fees to various pipeline equity companies for transporting finished refined products. In addition, we paid a price upgrade to MSLP for heavy crude processing. We purchased base oils and fuel products from Excel for use in our refining and specialty businesses.


(c)	We paid utility and processing fees to various affiliates.


(d)	We incurred interest expense on a note payable to MSLP. See Note 8—Investments, Loans and Long-Term Receivables and Note 14—Debt, for additional information on loans with affiliated companies.

Also included in the table above are transactions with ConocoPhillips through April 30, 2012, the effective date of the Separation. These transactions included crude oil purchased from ConocoPhillips as feedstock for our refineries and power sold to ConocoPhillips from our power generation facilities. For 2012, sales to ConocoPhillips, while it was a related party, were $381 million, while purchases from ConocoPhillips were $5,328 million.

As discussed in Note 1—Separation and Basis of Presentation, the consolidated statement of income includes expense allocations for certain corporate functions historically performed by ConocoPhillips and not allocated to its operating segments, including allocations of general corporate expenses related to executive oversight, accounting, treasury, tax, legal, procurement and information technology. Net charges from ConocoPhillips for these services, reflected in selling, general and administrative expenses in the consolidated statement of income, were $70 million for 2012.

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Note 27—Segment Disclosures and Related Information

Our operating segments are:

Midstream—Gathers, processes, transports and markets natural gas; and transports, fractionates and markets NGL in the United States. In addition, this segment transports crude oil and other feedstocks to our refineries and other locations, delivers refined and specialty products to market, and provides storage services for crude and petroleum products. The Midstream segment includes, among other businesses, our 50 percent equity investment in DCP Midstream and our investment in Phillips 66 Partners.


2)	Chemicals—Manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in CPChem.


3)	Refining—Buys, sells and refines crude oil and other feedstocks at 14 refineries, mainly in the United States and Europe.


4)	Marketing and Specialties (M&S)—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, as well as power generation operations.

Corporate and Other includes general corporate overhead, interest expense, our investments in new technologies and various other corporate activities. Corporate assets include all cash and cash equivalents.

We evaluate performance and allocate resources based on net income attributable to Phillips 66. Intersegment sales are at prices that approximate market, except for certain 2012 transportation services provided by the Midstream segment to the Refining and M&S segments.


•	We moved two of our equity investments, Excel Paralubes and Jupiter Sulphur, LLC, as well as the commission revenues related to needle and anode coke, polypropylene and solvents, from the Refining segment to the M&S segment.


•	We moved several refining logistics projects from the Refining segment to the Midstream Segment.

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Analysis of Results by Operating Segment



	Millions of Dollars
	2014			2013		2012
Sales and Other Operating Revenues
Midstream
Total sales	$	6,222		6,575		7,179
Intersegment eliminations	(1,104		)	(933	)	(901	)
Total Midstream	5,118			5,642		6,278
Chemicals	7			9		11
Refining
Total sales	115,326			124,480		131,113
Intersegment eliminations	(68,263		)	(72,503	)	(73,393	)
Total Refining	47,063			51,977		57,720
Marketing and Specialties
Total sales	110,540			115,405		116,681
Intersegment eliminations	(1,548		)	(1,467	)	(1,413	)
Total Marketing and Specialties	108,992			113,938		115,268
Corporate and Other	32			30		13
Consolidated sales and other operating revenues	$	161,212		171,596		179,290

Depreciation, Amortization and Impairments
Midstream	$	92		89		607
Chemicals	—			—		—
Refining	850			688		1,262
Marketing and Specialties	97			119		148
Corporate and Other	106			80		47
Consolidated depreciation, amortization and impairments	$	1,145		976		2,064

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	Millions of Dollars
	2014			2013		2012
Equity in Earnings of Affiliates
Midstream	$	360		436		343
Chemicals	1,634			1,362		1,192
Refining	311			1,107		1,409
Marketing and Specialties	162			169		190
Corporate and Other	(1		)	(1	)	—
Consolidated equity in earnings of affiliates	$	2,466		3,073		3,134

Income Taxes from Continuing Operations
Midstream	$	310		264		29
Chemicals	495			375		366
Refining	696			1,035		1,998
Marketing and Specialties	440			433		319
Corporate and Other	(287		)	(263	)	(239	)
Consolidated income taxes from continuing operations	$	1,654		1,844		2,473

Net Income Attributable to Phillips 66
Midstream	$	507		469		52
Chemicals	1,137			986		823
Refining	1,771			1,747		3,091
Marketing and Specialties	1,034			894		544
Corporate and Other	(393		)	(431	)	(434	)
Discontinued Operations	706			61		48
Consolidated net income attributable to Phillips 66	$	4,762		3,726		4,124

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	Millions of Dollars
	2014		2013	2012
Investments In and Advances To Affiliates
Midstream	$	2,461	2,328	2,011
Chemicals	5,183		4,241	3,524
Refining	2,103		4,192	4,461
Marketing and Specialties	290		318	295
Corporate and Other	1		1	—
Consolidated investments in and advances to affiliates	$	10,038	11,080	10,291

Total Assets
Midstream	$	7,295	5,485	4,671
Chemicals	5,209		4,377	3,815
Refining	22,808		26,046	26,643
Marketing and Specialties	7,051		7,331	7,968
Corporate and Other	6,378		6,348	4,770
Discontinued Operations*	—		211	206
Consolidated total assets	$	48,741	49,798	48,073
*In December 2013, $117 million of goodwill was allocated to assets held for sale in association with the planned disposition of PSPI. Although this goodwill was included in the M&S segment at December 31, 2012, for more useful comparisons, it is included in the discontinued operations line of this table for all periods presented.

Capital Expenditures and Investments
Midstream	$	2,173	597	707
Chemicals	—		—	—
Refining	1,038		820	735
Marketing and Specialties	439		226	119
Corporate and Other	123		136	140
Consolidated capital expenditures and investments	$	3,773	1,779	1,701

Interest Income and Expense
Interest income
Corporate and Other	$	21	20	18
Interest and debt expense
Corporate and Other	$	267	275	246



Sales and Other Operating Revenues by Product Line
Refined products	$	133,625	140,488	140,986
Crude oil resales	19,832		22,777	28,730
NGL	6,447		7,431	8,533
Other	1,308		900	1,041
Consolidated sales and other operating revenues by product line	$	161,212	171,596	179,290

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Geographic Information



	Millions of Dollars
	Sales and Other Operating Revenues*				Long-Lived Assets**
	2014		2013	2012	2014	2013	2012

United States	$	110,713	115,378	120,332	25,255	23,641	22,285
United Kingdom	20,131		21,868	22,129	1,469	1,485	2,018
Germany	9,424		9,799	9,908	534	587	567
Other foreign countries	20,944		24,551	26,921	126	765	828
Worldwide consolidated	$	161,212	171,596	179,290	27,384	26,478	25,698

*Sales and other operating revenues are attributable to countries based on the location of the operations generating the revenues.

**Defined as net properties, plants and equipment plus investments in and advances to affiliated companies.

Note 28—Phillips 66 Partners LP

Initial Public Offering

In 2013, we formed Phillips 66 Partners, a master limited partnership, to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum product and NGL pipelines and terminals, as well as other transportation and midstream assets. On July 26, 2013, Phillips 66 Partners completed its initial public offering (IPO) of 18,888,750 common units at a price of $23.00 per unit, which included a 2,463,750 common unit over-allotment option that was fully exercised by the underwriters. Phillips 66 Partners received $404 million in net proceeds from the sale of the units, after deducting underwriting discounts, commissions, structuring fees and offering expenses. Headquartered in Houston, Texas, Phillips 66 Partners’ assets currently consist of crude oil and refined petroleum product pipeline, terminal, and storage systems in the Central and Gulf Coast regions of the United States, as well as two crude oil rail-unloading facilities, all of which are integral to a connected Phillips 66-operated facility.

Contributions

Effective March 1, 2014, we contributed to Phillips 66 Partners certain transportation, terminaling and storage assets for total consideration of $700 million. These assets consisted of the Gold Line products system and the Medford spheres, two recently constructed refinery-grade propylene storage spheres. Phillips 66 Partners financed the acquisition with cash on hand of $400 million (primarily consisting of its IPO proceeds), the issuance of 3,530,595 and 72,053 additional common and general partner units, respectively, valued at $140 million, and a five-year, $160 million note payable to a subsidiary of Phillips 66.

Effective December 1, 2014, we contributed to Phillips 66 Partners certain logistics assets for total consideration of $340 million. These assets consisted of two recently constructed crude oil rail-unloading facilities located at or adjacent to our Bayway and Ferndale refineries, and the Cross-Channel Connector pipeline assets located near the partnership’s Pasadena terminal. Phillips 66 Partners financed the acquisition with the borrowing of $28 million under its revolving credit facility, the assumption of a five-year, $244 million note payable to a subsidiary of Phillips 66, and the issuance to Phillips 66 of 1,066,412 common and 21,764 general partner units valued at $68 million.

In addition to these two major transactions, we made smaller contributions to Phillips 66 Partners of projects under development in the fourth quarter, for consideration in the aggregate of approximately $55 million.

Ownership

At December 31, 2014, we owned a 73 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while the public owned a 25 percent limited partner interest. We consolidate Phillips 66 Partners as a variable interest entity for financial reporting purposes. The most significant assets of Phillips 66 Partners that are available to settle only its obligations were net PP&E of $485 million at December 31, 2014. See Note 4—Variable Interest Entities (VIEs) for additional information on why we consolidate the partnership. As a result of this consolidation, the public unitholders’ ownership interest in Phillips 66 Partners is reflected as a noncontrolling interest in our financial statements, including $415 million and $409 million in the equity section of our consolidated balance sheet

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as of December 31, 2014, and 2013, respectively. Generally, contributions of assets by us to Phillips 66 Partners will eliminate in consolidation, other than third-party debt or equity offerings made by Phillips 66 Partners to finance such transactions. For the 2014 contributions discussed above, the first did not impact our consolidated financial statements, while the second increased consolidated cash and debt by $28 million at the time of the transaction.

Recent Transactions

During February 2015, Phillips 66 Partners initiated two registered public offerings of securities:


•	5,250,000 common units representing limited partner interests, at a public offering price of $75.50 per unit. The net proceeds at closing are expected to be $384 million, not including an over-allotment option exercisable by the underwriters to purchase up to an additional 787,500 common units.


•	$1.1 billion aggregate principal amount of senior notes, which include $300 million of 2.646% Senior Notes due 2020, $500 million of 3.605% Senior Notes due 2025 and $300 million of 4.680% Senior Notes due 2045.

Note 29—New Accounting Standards

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The new standard converged guidance on recognizing revenues in contracts with customers under accounting principles generally accepted in the United States and International Financial Reporting Standards. This ASU is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets. ASU 2014-09 is effective for annual and quarterly reporting periods of public entities beginning after December 15, 2016. Early application for public entities is not permitted. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations.

Note 30—Condensed Consolidating Financial Information

Our $8.3 billion of outstanding Senior Notes were issued by Phillips 66 and are guaranteed by Phillips 66 Company, a 100-percent-owned subsidiary. Phillips 66 Company has fully and unconditionally guaranteed the payment obligations of Phillips 66 with respect to these debt securities. 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. The 2013 and 2012 condensed consolidating financial information was revised to eliminate intra-column lending transactions, to realign interest revenue from certain inter-column lending activities to the appropriate column, and to make the associated adjustments required to equity earnings and investments. These changes did not impact the total consolidated amounts.

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	Millions of Dollars
	Year Ended December 31, 2014
Statement of Income	Phillips 66			Phillips 66 Company		All Other Subsidiaries	Consolidating Adjustments		Total Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—		109,078		52,134	—		161,212
Equity in earnings of affiliates	4,257			3,021		444	(5,256	)	2,466
Net gain (loss) on dispositions	—			(46	)	341	—		295
Other income (loss)	—			105		15	—		120
Intercompany revenues	—			2,411		18,772	(21,183	)	—
Total Revenues and Other Income	4,257			114,569		71,706	(26,439	)	164,093

Costs and Expenses
Purchased crude oil and products	—			97,783		58,984	(21,019	)	135,748
Operating expenses	2			3,600		870	(37	)	4,435
Selling, general and administrative expenses	6			1,224		502	(69	)	1,663
Depreciation and amortization	—			761		234	—		995
Impairments	—			3		147	—		150
Taxes other than income taxes	—			5,478		9,563	(1	)	15,040
Accretion on discounted liabilities	—			18		6	—		24
Interest and debt expense	286			18		20	(57	)	267
Foreign currency transaction losses	—			—		26	—		26
Total Costs and Expenses	294			108,885		70,352	(21,183	)	158,348
Income from continuing operations before income taxes	3,963			5,684		1,354	(5,256	)	5,745
Provision (benefit) for income taxes	(103		)	1,427		330	—		1,654
Income from Continuing Operations	4,066			4,257		1,024	(5,256	)	4,091
Income from discontinued operations*	696			—		10	—		706
Net income	4,762			4,257		1,034	(5,256	)	4,797
Less: net income attributable to noncontrolling interests	—			—		35	—		35
Net Income Attributable to Phillips 66	$	4,762		4,257		999	(5,256	)	4,762

Comprehensive Income	$	4,194		3,689		721	(4,375	)	4,229
*Net of provision for income taxes on discontinued operations:	$	—		—		5	—		5

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	Millions of Dollars
	Year Ended December 31, 2013
Statement of Income	Phillips 66			Phillips 66 Company	All Other Subsidiaries		Consolidating Adjustments		Total Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—		113,499	58,097		—		171,596
Equity in earnings of affiliates	3,905			3,363	509		(4,704	)	3,073
Net gain on dispositions	—			49	6		—		55
Other income (loss)	(3		)	53	35		—		85
Intercompany revenues	—			1,796	19,623		(21,419	)	—
Total Revenues and Other Income	3,902			118,760	78,270		(26,123	)	174,809

Costs and Expenses
Purchased crude oil and products	—			102,780	66,746		(21,281	)	148,245
Operating expenses	—			3,442	790		(26	)	4,206
Selling, general and administrative expenses	6			1,025	540		(93	)	1,478
Depreciation and amortization	—			730	217		—		947
Impairments	—			—	29		—		29
Taxes other than income taxes	—			5,147	8,973		(1	)	14,119
Accretion on discounted liabilities	—			19	5		—		24
Interest and debt expense	266			13	14		(18	)	275
Foreign currency transaction gains	—			—	(40	)	—		(40	)
Total Costs and Expenses	272			113,156	77,274		(21,419	)	169,283
Income from continuing operations before income taxes	3,630			5,604	996		(4,704	)	5,526
Provision (benefit) for income taxes	(96		)	1,699	241		—		1,844
Income from Continuing Operations	3,726			3,905	755		(4,704	)	3,682
Income from discontinued operations*	—			—	61		—		61
Net income	3,726			3,905	816		(4,704	)	3,743
Less: net income attributable to noncontrolling interests	—			—	17		—		17
Net Income Attributable to Phillips 66	$	3,726		3,905	799		(4,704	)	3,726

Comprehensive Income	$	4,077		4,256	839		(5,078	)	4,094
*Net of provision for income taxes on discontinued operations:	$	—		—	34		—		34

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	Millions of Dollars
	Year Ended December 31, 2012
Statement of Income	Phillips 66			Phillips 66 Company		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—		117,574		61,716		—		179,290
Equity in earnings of affiliates	4,284			3,064		445		(4,659	)	3,134
Net gain on dispositions	—			192		1		—		193
Other income (loss)	2			(15	)	148		—		135
Intercompany revenues	1			2,951		23,134		(26,086	)	—
Total Revenues and Other Income	4,287			123,766		85,444		(30,745	)	182,752

Costs and Expenses
Purchased crude oil and products	—			106,687		73,715		(25,989	)	154,413
Operating expenses	—			3,329		760		(56	)	4,033
Selling, general and administrative expenses	4			1,319		421		(41	)	1,703
Depreciation and amortization	—			668		238		—		906
Impairments	—			71		1,087		—		1,158
Taxes other than income taxes	—			5,155		8,586		(1	)	13,740
Accretion on discounted liabilities	—			18		7		—		25
Interest and debt expense	212			29		4		1		246
Foreign currency transaction gains	—			—		(28	)	—		(28	)
Total Costs and Expenses	216			117,276		84,790		(26,086	)	176,196
Income from continuing operations before income taxes	4,071			6,490		654		(4,659	)	6,556
Provision (benefit) for income taxes	(53		)	2,206		320		—		2,473
Income from Continuing Operations	4,124			4,284		334		(4,659	)	4,083
Income from discontinued operations*	—			—		48		—		48
Net income	4,124			4,284		382		(4,659	)	4,131
Less: net income attributable to noncontrolling interests	—			—		7		—		7
Net Income Attributable to Phillips 66	$	4,124		4,284		375		(4,659	)	4,124

Comprehensive Income	$	4,228		4,388		418		(4,799	)	4,235
*Net of provision for income taxes on discontinued operations:	$	—		—		27		—		27

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	Millions of Dollars
	At December 31, 2014
Balance Sheet	Phillips 66			Phillips 66 Company		All Other Subsidiaries	Consolidating Adjustments		Total Consolidated
Assets
Cash and cash equivalents	$	—		2,045		3,162	—		5,207
Accounts and notes receivable	14			5,069		3,274	(1,102	)	7,255
Inventories	—			2,026		1,371	—		3,397
Prepaid expenses and other current assets	9			429		399	—		837
Total Current Assets	23			9,569		8,206	(1,102	)	16,696
Investments and long-term receivables	30,141			18,896		4,631	(43,479	)	10,189
Net properties, plants and equipment	—			12,267		5,079	—		17,346
Goodwill	—			3,040		234	—		3,274
Intangibles	—			694		206	—		900
Other assets	60			159		121	(4	)	336
Total Assets	$	30,224		44,625		18,477	(44,585	)	48,741

Liabilities and Equity
Accounts payable	$	—		5,618		3,548	(1,102	)	8,064
Short-term debt	798			26		18	—		842
Accrued income and other taxes	—			356		522	—		878
Employee benefit obligations	—			409		53	—		462
Other accruals	65			242		541	—		848
Total Current Liabilities	863			6,651		4,682	(1,102	)	11,094
Long-term debt	7,457			159		226	—		7,842
Asset retirement obligations and accrued environmental costs	—			494		189	—		683
Deferred income taxes	—			4,240		1,255	(4	)	5,491
Employee benefit obligations	—			1,074		231	—		1,305
Other liabilities and deferred credits	285			1,919		2,126	(4,041	)	289
Total Liabilities	8,605			14,537		8,709	(5,147	)	26,704
Common stock	12,812			25,405		8,240	(33,645	)	12,812
Retained earnings	9,338			5,214		1,074	(6,317	)	9,309
Accumulated other comprehensive income (loss)	(531		)	(531	)	7	524		(531	)
Noncontrolling interests	—			—		447	—		447
Total Liabilities and Equity	$	30,224		44,625		18,477	(44,585	)	48,741

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	Millions of Dollars
	At December 31, 2013
Balance Sheet	Phillips 66		Phillips 66 Company	All Other Subsidiaries	Consolidating Adjustments		Total Consolidated
Assets
Cash and cash equivalents	$	—	2,162	3,238	—		5,400
Accounts and notes receivable	9		2,169	8,013	(559	)	9,632
Inventories	—		1,962	1,392	—		3,354
Prepaid expenses and other current assets	10		368	473	—		851
Total Current Assets	19		6,661	13,116	(559	)	19,237
Investments and long-term receivables	33,178		27,416	6,571	(55,945	)	11,220
Net properties, plants and equipment	—		12,031	3,367	—		15,398
Goodwill	—		3,094	2	—		3,096
Intangibles	—		694	4	—		698
Other assets	40		112	1	(4	)	149
Total Assets	$	33,237	50,008	23,061	(56,508	)	49,798

Liabilities and Equity
Accounts payable	$	1	7,502	4,146	(559	)	11,090
Short-term debt	—		18	6	—		24
Accrued income and other taxes	—		250	622	—		872
Employee benefit obligations	—		422	54	—		476
Other accruals	49		179	241	—		469
Total Current Liabilities	50		8,371	5,069	(559	)	12,931
Long-term debt	5,796		152	183	—		6,131
Asset retirement obligations and accrued environmental costs	—		527	173	—		700
Deferred income taxes	—		5,045	1,084	(4	)	6,125
Employee benefit obligations	—		724	197	—		921
Other liabilities and deferred credits	5,441		2,153	6,694	(13,690	)	598
Total Liabilities	11,287		16,972	13,400	(14,253	)	27,406
Common stock	16,291		25,942	8,302	(34,244	)	16,291
Retained earnings	5,622		7,057	598	(7,655	)	5,622
Accumulated other comprehensive income	37		37	319	(356	)	37
Noncontrolling interests	—		—	442	—		442
Total Liabilities and Equity	$	33,237	50,008	23,061	(56,508	)	49,798

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	Millions of Dollars
	Year Ended December 31, 2014
Statement of Cash Flows	Phillips 66			Phillips 66 Company		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operating activities	$	(47	)	2,551		1,527		(504	)	3,527
Net cash provided by discontinued operations	—			—		2		—		2
Net Cash Provided by (Used in) Operating Activities	(47		)	2,551		1,529		(504	)	3,529

Cash Flows From Investing Activities
Capital expenditures and investments*	—			(2,230	)	(2,532	)	989		(3,773	)
Proceeds from asset dispositions	—			960		687		(403	)	1,244
Intercompany lending activities**	1,397			(1,402	)	5		—		—
Advances/loans—related parties	—			—		(3	)	—		(3	)
Collection of advances/loans—related parties	—			—		—		—		—
Other	—			(13	)	251		—		238
Net cash provided by (used in) continuing investing activities	1,397			(2,685	)	(1,592	)	586		(2,294	)
Net cash used in discontinued operations	—			—		(2	)	—		(2	)
Net Cash Provided by (Used in) Investing Activities	1,397			(2,685	)	(1,594	)	586		(2,296	)

Cash Flows From Financing Activities
Issuance of debt	2,459			—		28		—		2,487
Repayment of debt	—			(20	)	(29	)	—		(49	)
Issuance of common stock	1			—		—		—		1
Repurchase of common stock	(2,282		)	—		—		—		(2,282	)
Share exchange—PSPI transaction	(450		)	—		—		—		(450	)
Dividends paid on common stock	(1,062		)	—		(443	)	443		(1,062	)
Distributions to controlling interests	—			—		(323	)	323		—
Distributions to noncontrolling interests	—			—		(30	)	—		(30	)
Other*	(16		)	37		850		(848	)	23
Net cash provided by (used in) continuing financing activities	(1,350		)	17		53		(82	)	(1,362	)
Net cash provided by (used in) discontinued operations	—			—		—		—		—
Net Cash Provided by (Used in) Financing Activities	(1,350		)	17		53		(82	)	(1,362	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents	—			—		(64	)	—		(64	)

Net Change in Cash and Cash Equivalents	—			(117	)	(76	)	—		(193	)
Cash and cash equivalents at beginning of period	—			2,162		3,238		—		5,400
Cash and Cash Equivalents at End of Period	$	—		2,045		3,162		—		5,207
* Includes intercompany capital contributions.
** Non-cash investing activity: In the fourth quarter of 2014, Phillips 66 Company declared and distributed $6.1 billion of its Phillips 66 intercompany receivables to Phillips 66.

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	Millions of Dollars
	Year Ended December 31, 2013
Statement of Cash Flows	Phillips 66			Phillips 66 Company		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated
Cash Flows From Operating Activities
Net cash provided by continuing operating activities	$	5		4,972		1,045		(80	)	5,942
Net cash provided by discontinued operations	—			—		85		—		85
Net Cash Provided by Operating Activities	5			4,972		1,130		(80	)	6,027

Cash Flows From Investing Activities
Capital expenditures and investments*	—			(1,108	)	(690	)	19		(1,779	)
Proceeds from asset dispositions	—			63		1,151		—		1,214
Intercompany lending activities	4,055			(4,206	)	151		—		—
Advances/loans—related parties	—			—		(65	)	—		(65	)
Collection of advances/loans—related parties	—			—		165		—		165
Other	—			42		6		—		48
Net cash provided by (used in) continuing investing activities	4,055			(5,209	)	718		19		(417	)
Net cash used in discontinued operations	—			—		(27	)	—		(27	)
Net Cash Provided by (Used in) Investing Activities	4,055			(5,209	)	691		19		(444	)

Cash Flows From Financing Activities
Repayment of debt	(1,000		)	(18	)	(2	)	—		(1,020	)
Issuance of common stock	6			—		—		—		6
Repurchase of common stock	(2,246		)	—		—		—		(2,246	)
Dividends paid on common stock	(807		)	—		(72	)	72		(807	)
Distributions to controlling interests	—			—		(8	)	8		—
Distributions to noncontrolling interests	—			—		(10	)	—		(10	)
Net proceeds from issuance of Phillips 66 Partners LP common units	—			—		404		—		404
Other*	(13		)	7		19		(19	)	(6	)
Net cash provided by (used in) continuing financing activities	(4,060		)	(11	)	331		61		(3,679	)
Net cash provided by (used in) discontinued operations	—			—		—		—		—
Net Cash Provided by (Used in) Financing Activities	(4,060		)	(11	)	331		61		(3,679	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents	—			—		22		—		22

Net Change in Cash and Cash Equivalents	—			(248	)	2,174		—		1,926
Cash and cash equivalents at beginning of period	—			2,410		1,064		—		3,474
Cash and Cash Equivalents at End of Period	$	—		2,162		3,238		—		5,400
* Includes intercompany capital contributions.

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	Millions of Dollars
	Year Ended December 31, 2012
Statement of Cash Flows	Phillips 66			Phillips 66 Company		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operating activities	$	(42	)	7,429		(3,128	)	—		4,259
Net cash provided by discontinued operations	—			—		37		—		37
Net Cash Provided by (Used in) Operating Activities	(42		)	7,429		(3,091	)	—		4,296

Cash Flows From Investing Activities
Capital expenditures and investments	—			(861	)	(850	)	10		(1,701	)
Proceeds from asset dispositions	—			240		46		—		286
Intercompany lending activities	1,376			(4,334	)	2,958		—		—
Advances/loans—related parties	—			—		(100	)	—		(100	)
Collection of advances/loans—related parties	—			—		7		(7	)	—
Other	—			—		—		—		—
Net cash provided by (used in) continuing investing activities	1,376			(4,955	)	2,061		3		(1,515	)
Net cash used in discontinued operations	—			—		(20	)	—		(20	)
Net Cash Provided by (Used in) Investing Activities	1,376			(4,955	)	2,041		3		(1,535	)

Cash Flows From Financing Activities
Contributions from (distributions to) ConocoPhillips	(7,469		)	110		2,104		—		(5,255	)
Issuance of debt	7,794			—		—		—		7,794
Repayment of debt	(1,000		)	(208	)	(9	)	7		(1,210	)
Issuance of common stock	47			—		—		—		47
Repurchase of common stock	(356		)	—		—		—		(356	)
Dividends paid on common stock	(282		)	—		—		—		(282	)
Distributions to controlling interests	—			—		—		—		—
Distributions to noncontrolling interests	—			—		(5	)	—		(5	)
Other	(68		)	34		10		(10	)	(34	)
Net cash provided by (used in) continuing financing activities	(1,334		)	(64	)	2,100		(3	)	699
Net cash provided by (used in) discontinued operations	—			—		—		—		—
Net Cash Provided by (Used in) Financing Activities	(1,334		)	(64	)	2,100		(3	)	699

Effect of Exchange Rate Changes on Cash and Cash Equivalents	—			—		14		—		14

Net Change in Cash and Cash Equivalents	—			2,410		1,064		—		3,474
Cash and cash equivalents at beginning of period	—			—		—		—		—
Cash and Cash Equivalents at End of Period	$	—		2,410		1,064		—		3,474

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Selected Quarterly Financial Data (Unaudited)



	Millions of Dollars					Per Share of Common Stock
	Sales and Other Operating Revenues*		Income From Continuing Operations Before Income Taxes	Net Income	Net Income Attributable to Phillips 66	Net Income Attributable to Phillips 66
	Sales and Other Operating Revenues*		Income From Continuing Operations Before Income Taxes	Net Income	Net Income Attributable to Phillips 66	Basic	Diluted
2014
First	$	40,283	1,298	1,578	1,572	2.69	2.67
Second	45,549		1,359	872	863	1.52	1.51
Third	40,417		1,727	1,189	1,180	2.11	2.09
Fourth	34,963		1,361	1,158	1,147	2.07	2.05

2013
First	$	41,211	2,058	1,410	1,407	2.25	2.23
Second	43,190		1,453	960	958	1.55	1.53
Third	44,146		804	540	535	0.88	0.87
Fourth	43,049		1,211	833	826	1.38	1.37

*Includes excise taxes on petroleum products sales.

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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, 2014, 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, 2014.

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, 2014, 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 on page 66 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 on page 68 and is incorporated herein by reference.

Item 9B. OTHER INFORMATION

None.

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PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding our executive officers appears in Part I of this report on page 29.

Information required by Item 10 of Part III is incorporated herein by reference from our 2015 Definitive Proxy Statement.*

Item 11. EXECUTIVE COMPENSATION

Information required by Item 11 of Part III is incorporated herein by reference from our 2015 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 2015 Definitive Proxy Statement.*

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by Item 13 of Part III is incorporated herein by reference from our 2015 Definitive Proxy Statement.*

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required by Item 14 of Part III is incorporated herein by reference from our 2015 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 2015 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.

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PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES



(a)	1.	Financial Statements and Supplementary Data The financial statements and supplementary information listed in the Index to Financial Statements, which appears on page 65, are filed as part of this Annual Report on Form 10-K.

	2.	Financial Statement Schedules Schedule II—Valuation and Qualifying Accounts appears below. All other schedules are omitted because they are not required, not significant, not applicable or the information is shown in another schedule, the financial statements or the notes to consolidated financial statements.

	3.	Exhibits The exhibits listed in the Index to Exhibits, which appears on pages 139 to 142, are filed as part of this Annual Report on Form 10-K.

(c)		Pursuant to Rule 3-09 of Regulation S-X, the financial statements of WRB Refining LP and Chevron Phillips Chemical Company LLC, each as of, and for the three years ending, December 31, 2014, are included as exhibits to this Annual Report on Form 10-K.

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SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS (Consolidated)



	Millions of Dollars
Description	Balance at January 1		Charged to Expense		Other (a)		Deductions			Balance at December 31
2014
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable	$	47	29		—		(5	)	(b)	71
Deferred tax asset valuation allowance	127		(13	)	(7	)	—			107
2013
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable	$	50	10		—		(13	)	(b)	47
Deferred tax asset valuation allowance	329		20		(222	)	—			127
2012
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable	$	13	36		—		1		(b)	50
Deferred tax asset valuation allowance	210		61		54		4			329

(a)Represents acquisitions/dispositions/revisions, net transfers associated with the Separation and the effect of translating foreign financial statements.

(b)Amounts charged off less recoveries of amounts previously charged off.

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PHILLIPS 66

INDEX TO EXHIBITS



		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit Number	Filing Date	SEC File No.

2.1	Separation and Distribution Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	2.1	05/01/12	001-35349

3.1	Amended and Restated Certificate of Incorporation of Phillips 66.	8-K	3.1	05/01/12	001-35349

3.2	Amended and Restated By-Laws of Phillips 66.	8-K	3.2	05/01/12	001-35349

4.1	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.	10	4.3	04/05/12	001-35349

4.2	Form of the terms of the 1.950% Senior Notes due 2015, the 2.950% Senior Notes due 2017, the 4.300% Senior Notes due 2022 and the 5.875% Senior Notes due 2042, including the form of the 1.950% Senior Notes due 2015, the 2.950% Senior Notes due 2017, the 4.300% Senior Notes due 2022 and the 5.875% Senior Notes due 2042.	10-K	4.2	02/22/13	001-35349

4.3	Form of the terms of the 4.650% Senior Notes due 2034 and the 4.875% Senior Notes due 2044.	8-K	4.2	11/17/14	001-35349

10.1	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.	10	4.1	03/01/12	001-35349

10.2	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.	10-Q	10.1	05/01/14	001-35349

10.3*	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.

10.4	Third Amended and Restated Limited Liability Company Agreement of Chevron Phillips Chemical Company LLC, effective as of May 1, 2012.	10-Q	10.14	08/03/12	001-35349

10.5	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.	10	10.12	03/01/12	001-35349

10.6	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.	10	10.13	03/01/12	001-35349

10.7	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.	10	10.14	03/01/12	001-35349

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		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit Number	Filing Date	SEC File No.

10.8	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.	10	10.15	03/01/12	001-35349

10.9	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.	10	10.16	03/01/12	001-35349

10.10	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.	10-Q	10.1	10/30/14	001-35349

10.11	Indemnification and Release Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.1	05/01/12	001-35349

10.12	Intellectual Property Assignment and License Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.2	05/01/12	001-35349

10.13	Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.3	05/01/12	001-35349

10.14	Employee Matters Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.4	05/01/12	001-35349

10.15	Amendment to the Employee Matters Agreement by and between ConocoPhillips and Phillips 66, dated April 26, 2012.	10-Q	10.1	05/02/13	001-35349

10.16	Transition Services Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.5	05/01/12	001-35349

10.17	2013 Omnibus Stock and Performance Incentive Plan of Phillips 66.**	DEF14A	App. A	03/27/13	001-35349

10.18	Phillips 66 Key Employee Supplemental Retirement Plan.**	10-Q	10.15	08/03/12	001-35349

10.19	First Amendment to the Phillips 66 Key Employee Supplemental Retirement Plan.**	10-K	10.18	02/22/13	001-35349

10.20	Phillips 66 Executive Severance Plan.**	10-Q	10.16	08/03/12	001-35349

10.21	First Amendment to the Phillips 66 Executive Severance Plan.**	10-K	10.20	02/22/13	001-35349

10.22	Phillips 66 Deferred Compensation Plan for Non-Employee Directors.**	10-Q	10.17	08/03/12	001-35349

10.23	Phillips 66 Key Employee Deferred Compensation Plan-Title I.**	10-Q	10.18	08/03/12	001-35349

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		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit Number	Filing Date	SEC File No.

10.24	Phillips 66 Key Employee Deferred Compensation Plan-Title II.**	10-Q	10.19	08/03/12	001-35349

10.25	First Amendment to the Phillips 66 Key Employee Deferred Compensation Plan Title II.**	10-K	10.24	02/22/13	001-35349

10.26	Phillips 66 Defined Contribution Make-Up Plan Title I.**	10-Q	10.20	08/03/12	001-35349

10.27	Phillips 66 Defined Contribution Make-Up Plan Title II.**	10-K	10.26	02/22/13	001-35349

10.28	Phillips 66 Key Employee Change in Control Severance Plan.**	10-K	10.27	02/22/13	001-35349

10.29	First Amendment to Phillips 66 Key Employee Change in Control Severance Plan, Effective October 2, 2015.**	8-K	10.1	11/08/13	001-35349

10.30	Annex to the Phillips 66 Nonqualified Deferred Compensation Arrangements.**	10-Q	10.23	08/03/12	001-35349

10.31	Form of Stock Option Award Agreement under the 2013 Omnibus Stock and Performance Incentive Plan of Phillips 66.**	10-K	10.29	02/22/13	001-35349

10.32	Form of Restricted Stock or Restricted Stock Unit Award Agreement under the 2013 Omnibus Stock and Performance Incentive Plan of Phillips 66.**	10-K	10.30	02/22/13	001-35349

10.33	Form of Performance Share Unit Award Agreement under the 2013 Omnibus Stock and Performance Incentive Plan of Phillips 66.**	10-K	10.31	02/22/13	001-35349

12*	Computation of Ratio of Earnings to Fixed Charges.

21*	List of Subsidiaries of Phillips 66.

23.1*	Consent of Ernst & Young LLP, independent registered public accounting firm.

23.2*	Consent of Ernst & Young LLP, independent auditors for WRB Refining LP.

23.3*	Consent of Ernst & Young LLP, independent auditors for Chevron Phillips Chemicals Company LLC.

31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2*	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.

99.1*	The financial statements of WRB Refining LP, pursuant to Rule 3-09 of Regulation S-X.

99.2*	The financial statements of Chevron Phillips Chemical Company, LLC, pursuant to Rule 3-09 of Regulation S-X.

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		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit Number	Filing Date	SEC File No.

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.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	PHILLIPS 66



February 20, 2015	/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, as of February 20, 2015, on behalf of the registrant by the following officers in the capacity indicated and by a majority of directors.



Signature		Title



/s/ Greg C. Garland		Chairman of the Board of Directors
Greg C. Garland		and Chief Executive Officer
		(Principal executive officer)


/s/ Greg G. Maxwell		Executive Vice President, Finance
Greg G. Maxwell		and Chief Financial Officer
		(Principal financial officer)


/s/ Chukwuemeka A. Oyolu		Vice President and Controller
Chukwuemeka A. Oyolu		(Principal accounting officer)

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/s/ J. Brian Ferguson		Director
J. Brian Ferguson


/s/ William R. Loomis Jr.		Director
William R. Loomis Jr.


/s/ John E. Lowe		Director
John E. Lowe


/s/ Harold W. McGraw III		Director
Harold W. McGraw III


/s/ Glenn F. Tilton		Director
Glenn F. Tilton


/s/ Victoria J. Tschinkel		Director
Victoria J. Tschinkel


/s/ Marna C. Whittington		Director
Marna C. Whittington

144