Phillips 66 - Annual Report: 2015 (Form 10-K)

Closing Stock Price at December 31, 2015

Closing Stock Price at January 29, 2016

Number of Stockholders of Record at January 29, 2016



2015



	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, 2015
	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, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $80.56, was $43.3 billion. The registrant, solely for the purpose of this required presentation, had deemed its Board of Directors and executive officers to be affiliates, and deducted their stockholdings in determining the aggregate market value.

The registrant had 527,459,894 shares of common stock outstanding at January 31, 2016.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 4, 2016 (Part III).

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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
Technology Development	17
Competition	17
General	17
1A. Risk Factors	19
1B. Unresolved Staff Comments	26
3. Legal Proceedings	26
4. Mine Safety Disclosures	27
Executive Officers of the Registrant	28

PART II

5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
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	64
Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995	66
8. Financial Statements and Supplementary Data	67
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	133
9A. Controls and Procedures	133
9B. Other Information	133

PART III

10. Directors, Executive Officers and Corporate Governance	134
11. Executive Compensation	134
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	134
13. Certain Relationships and Related Transactions, and Director Independence	134
14. Principal Accounting Fees and Services	134

PART IV

15. Exhibits, Financial Statement Schedules	135
Signatures	141

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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.”

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). 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 terminaling and storage services for crude oil and petroleum products. The Midstream segment includes our master limited partnership, Phillips 66 Partners LP, as well as our 50 percent equity investment in DCP Midstream, LLC (DCP Midstream).


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.

At December 31, 2015, Phillips 66 had approximately 14,000 employees.

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SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 26—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

MIDSTREAM

The Midstream segment consists of three business lines:


•	Transportation—transports crude oil and other feedstocks to our refineries and other locations, delivers refined and specialty products to market, and provides terminaling and storage services for crude oil and petroleum products.


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


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

Phillips 66 Partners LP

In 2013, we formed Phillips 66 Partners LP, 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, 2015, we owned a 69 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while the public owned a 29 percent limited partner interest.

Headquartered in Houston, Texas, Phillips 66 Partners’ assets and equity investments consist of crude oil, NGL and refined petroleum product pipelines, terminals, rail racks and storage systems that are geographically dispersed throughout the United States, most of which are integral to a Phillips 66-operated refinery.

During 2015, Phillips 66 Partners expanded its business by acquiring from us:


•	One-third equity interests in DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC (Southern Hills), as well as a 19.5 percent equity interest in Explorer Pipeline Company (Explorer). This acquisition closed in March 2015.


•	A 40 percent equity interest in Bayou Bridge Pipeline, LLC (Bayou Bridge). This acquisition closed in December 2015.

The operations and financial results of Phillips 66 Partners are included in either the Transportation or NGL business line, based on the nature of the activity within the partnership.

Transportation

We own or lease various assets to provide environmentally safe, strategic and timely delivery and terminaling 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, 2015, 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, 16 crude oil terminals and 1 petroleum coke exporting facility.

During 2015, we continued to invest in our Beaumont Terminal, the largest terminal in the Phillips 66 portfolio, which currently has 4.7 million barrels of crude oil storage capacity and 2.4 million barrels of refined product storage capacity. As of December 31, 2015, we had 2.0 million barrels of incremental crude storage capacity under construction, which is

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Index to Financial Statements

expected to be completed in the third quarter of 2016. In addition, we have initiated a variety of other projects aimed at increasing storage and throughput capabilities as we continue the expansion of the Beaumont terminal from its current 7.1 million barrels of storage capacity to 16 million barrels.

Construction progressed in 2015 on our two crude oil pipeline systems being developed by our joint ventures, Dakota Access LLC (DAPL) and Energy Transfer Crude Oil Company, LLC (ETCOP). Phillips 66 owns 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 pipeline systems. The DAPL pipeline is expected to deliver 470,000 barrels per day of crude oil from the Bakken/Three Forks production area in North Dakota to market centers in the Midwest. The DAPL pipeline will provide shippers with access to Midwestern refineries, unit-train rail loading facilities to facilitate deliveries to East Coast refineries, and the Gulf Coast market through an interconnection in Patoka, Illinois, with ETCOP pipeline. The ETCOP pipeline will provide crude oil transportation service from the Midwest to the Sunoco Logistics Partners L.P. (Sunoco Logistics) and Phillips 66 storage terminals located in Nederland, Texas. The pipelines are expected to be operational in fourth-quarter 2016.

In the third quarter of 2015, Phillips 66 became a joint venture partner with a 40 percent equity interest in Bayou Bridge. Energy Transfer Partners, L.P. (ETP) and Sunoco Logistics each hold a 30 percent interest in the joint venture, with Sunoco Logistics serving as the operator. The joint venture was formed for the funding and development of the Bayou Bridge pipeline. The Bayou Bridge pipeline is a new-build 30” and 24” pipeline that will deliver crude oil from Nederland, Texas, to Lake Charles, Louisiana and on to St. James, Louisiana. Phillips 66 is constructing the segment to Lake Charles, which will be in service by the end of first-quarter 2016. The remaining section of the pipeline, which will be constructed by ETP, is scheduled for completion in the second half of 2017. Effective December 1, 2015, Phillips 66 Partners acquired Phillips 66’s 40 percent equity interest in Bayou Bridge.

In the fourth quarter of 2015, Phillips 66 Partners commenced operation of the Palermo Rail Terminal, which is located on a 710-acre site near Palermo, North Dakota. The crude terminal has an initial capacity of 100,000 barrels per day, with the flexibility to be expanded to 200,000 barrels per day. It is located on a railway with two mainline switches, allowing east- and west-bound deliveries. The terminal includes 6 truck unloading facilities and 206,000 barrels of operational storage, with permits allowing total storage capacity of up to 2.4 million barrels, as well as space for 6 additional truck unloading facilities. The terminal is owned by the joint venture Phillips 66 Partners Terminal LLC, of which Phillips 66 Partners holds a 70 percent interest, with Paradigm Energy Partners, LLC (Paradigm) owning the remaining 30 percent interest. Phillips 66 Partners is the operator.

In 2016, the Palermo Rail Terminal is anticipated to include a pipeline delivery and receipt connection to the 76-mile Sacagawea Pipeline, allowing the terminal to receive crude oil from areas in Dunn County and McKenzie County, North Dakota, and deliver it to terminals and pipelines located in Stanley, North Dakota. The Sacagawea Pipeline is owned by the joint venture Sacagawea Pipeline Company, LLC, of which Paradigm Pipeline LLC holds an 88 percent interest, with the remaining 12 percent interest owned by Grey Wolf Midstream, LLC. Phillips 66 Partners and Paradigm each own a 50 percent interest in Paradigm Pipeline LLC. Paradigm is constructing the pipeline and Phillips 66 Partners will be the operator.

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The following table depicts our ownership interest in major pipeline systems as of December 31, 2015:



Name	Origination/Terminus	Interest		Size	Length(Miles)	Gross Capacity (MBD)
Crude and Feedstocks
Glacier	Cut Bank, MT/Billings, MT	79	%	8”-12”	865	126
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”	224	28
Oklahoma Mainline	Wichita Falls, TX/Ponca City, OK	100		12”	217	100
Clifton Ridge †	Clifton Ridge, LA/Westlake, LA	71		20”	10	260
Eagle Ford Gathering †	Helena, TX	71		6”	6	20
Eagle Ford Gathering †	Tilden, TX/Whitsett, TX	71		6”, 10”	22	34
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 Products
Harbor	Woodbury, NJ/Linden, NJ	33		16”	80	171
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	34
Borger-Denver	McKee, TX/Denver, CO	70		6”-12”	405	38
Gold Line †	Borger, TX/East St. Louis, IL	71		8”-16”	681	120
SAAL	Amarillo, TX/Abernathy, TX	33		6”	102	33
SAAL	Abernathy, TX/Lubbock, TX	54		6”	19	30
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	71		8”, 10”	106	96
Standish	Marland Junction, OK/Wichita, KS	100		18”	92	72
Cherokee North	Ponca City, OK/Arkansas City, KS	100		10”	29	57
Cherokee East	Medford, OK/Mount Vernon, MO	100		10”, 12”	287	55
Cross Channel Connector †	Pasadena, TX/Galena Park, TX	71		20”	5	180
Explorer***†	Texas Gulf Coast/Chicago, IL	14		24”, 28”	1,830	660
Sweeny to Pasadena †	Sweeny, TX/Pasadena, TX	71		12”, 18”	120	294
LAX Jet Line	Wilmington, CA/Los Angeles, CA	50		8”	19	50
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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Name	Origination/Terminus	Interest		Size	Length (Miles)	Gross Capacity (MBD)
NGL
Powder River	Sage Creek, WY/Borger, TX	100	%	6”-8”	705	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	24		20”	1,190	250
Southern Hills**†	U.S. Midcontinent/Mont Belvieu, TX	24		20”	940	175
Sweeny NGL	Brazoria, TX/Sweeny, TX	100		20”	18	204
LPG
Blue Line	Borger, TX/East St. Louis, IL	100		8”-12”	688	29
Brown Line	Ponca City, OK/Wichita, KS	100		8”, 10”	76	26
Conway to Wichita	Conway, KS/Wichita, KS	100		12”	55	38
Medford	Ponca City, OK/Medford, OK	100		4”-6”	42	10
Sweeny LPG Lines	Sweeny/Mont Belvieu & Freeport, TX	100		10”-20”	246	842
Natural Gas
Rockies Express	Meeker, CO/Clarington, OH	25		36”-42”	1,712	1.8 BCFD

†Owned by Phillips 66 Partners LP; Phillips 66 held a 71 percent ownership interest in Phillips 66 Partners LP at December 31, 2015.

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

**Operated by DCP Midstream Partners, LP; Phillips 66 Partners holds a direct one-third ownership in the pipeline entities.

***Phillips 66 Partners holds a 19.5 percent ownership in Explorer.

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The following table depicts our ownership interest in finished product terminals as of December 31, 2015:



Facility Name	Location	Interest		Gross Storage Capacity (MBbl)	Gross 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	71		2,085	78
Glenpool North	Oklahoma	100		366	19
Great Falls	Montana	100		198	12
Hartford †	Illinois	71		1,075	25
Helena	Montana	100		178	10
Jefferson City †	Missouri	71		110	16
Kansas City †	Kansas	71		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		368	29
Moses Lake	Washington	50		186	13
Mount Vernon	Missouri	100		363	46
North Salt Lake	Utah	50		657	41
Oklahoma City	Oklahoma	100		352	48
Pasadena †	Texas	71		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	71		679	19

†Owned by Phillips 66 Partners LP; Phillips 66 held a 71 percent ownership interest in Phillips 66 Partners LP at December 31, 2015.

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The following table depicts our ownership interest in crude and other terminals as of December 31, 2015:



Facility Name	Location	Interest		Gross Storage Capacity (MBbl)	Gross Loading Capacity**
Crude
Beaumont	Texas	100	%	4,704	N/A
Billings	Montana	100		270	N/A
Borger	Texas	100		721	N/A
Clifton Ridge †	Louisiana	71		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
Palermo*	North Dakota	50		206	N/A
Pecan Grove †	Louisiana	71		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
Petroleum Coke
Lake Charles	Louisiana	50		N/A	N/A
Rail
Bayway †	New Jersey	71		N/A	75
Beaumont	Texas	100		N/A	20
Ferndale †	Washington	71		N/A	30
Missoula	Montana	50		N/A	82
Palermo*	North Dakota	50		N/A	100
Thompson Falls	Montana	50		N/A	84
Marine
Beaumont	Texas	100		N/A	13
Clifton Ridge †	Louisiana	71		N/A	48
Hartford †	Illinois	71		N/A	3
Pecan Grove †	Louisiana	71		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; Phillips 66 held a 71 percent ownership interest in Phillips 66 Partners LP at December 31, 2015.

*Owned by Phillips 66 Partners Terminal LLC; Phillips 66 Partners holds a 70 percent ownership interest in Phillips 66 Partners Terminal LLC.

**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 1,712 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 was originally 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. During 2015, as a result of east-to-west expansion projects, the REX Pipeline began transporting natural gas supplies from the Appalachian Basin to Midwest markets.

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Marine Vessels

At December 31, 2015, we had 12 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 three Jones Act compliant tankers and 66 tug/barge units. These vessels are used primarily to transport feedstocks or provide product transportation for certain of our refineries, including delivery of domestic crude oil to our Gulf Coast and East Coast refineries.

Truck and Rail

Truck and rail operations support our feedstock and distribution operations. Rail movements are provided via a fleet of more than 12,300 owned and leased railcars. Truck movements are provided through approximately 170 third-party truck companies, as well as through Sentinel Transportation LLC, in which we hold a 20 percent 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, 2015, DCP Midstream owned or operated 64 natural gas processing facilities, with a net processing capacity of approximately 8.0 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 68,000 miles of pipeline. DCP Midstream also owned or operated 12 NGL fractionation plants, along with natural gas and NGL storage facilities, a propane wholesale marketing business and NGL pipeline assets.

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

DCP Midstream markets a portion of its NGL to us and CPChem under existing 15-year contracts, the primary commitment of which began a ratable wind-down period in December 2014 and expires in January 2019. These purchase commitments are on an “if-produced, will-purchase” basis.

During 2015, DCP Midstream and DCP Midstream Partners, LP (DCP Partners), the MLP formed by DCP Midstream, completed or advanced the following growth projects:


•	The Sand Hills laterals were placed into service in the second and third quarters of 2015. The Sand Hills pipeline capacity expansion is underway and expected to be in service in the middle of 2016.


•	In March 2015, construction began on a gathering system in the Denver-Julesburg (DJ) Basin, named the Grand Parkway gathering project, with expected completion in the first quarter of 2016.


•	The expansion of the Keathley Canyon natural gas gathering pipeline system, which is part of DCP Partners’ Discovery joint venture, was placed into service in the first quarter of 2015.


•	The Lucerne 2 plant was placed into service in mid-2015.

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NGL

Our NGL business includes the following:


•	The 100,000 barrels-per-day (BPD) Sweeny Fractionator One is located in Old Ocean, Texas. The fractionator is supported by 250 miles of new pipelines and the Clemens Caverns storage facility located near Brazoria, Texas, with connectivity to local petrochemical customers, the Mont Belvieu market hub and our marine terminal in Freeport, Texas.


•	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 its 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 its capacity is 30,250 barrels per day.


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


•	Phillips 66 Partners owns a direct one-third interest in both Sand Hills and Southern Hills, whose pipelines connect Eagle Ford, Permian and Midcontinent production to the Mont Belvieu, Texas market.

In December 2015, operations began at Sweeny Fractionator One. Sweeny Fractionator One is located adjacent to our Sweeny Refinery and supplies purity ethane and LPG to the petrochemical industry and heating markets. Raw NGL supply to the fractionator is delivered from nearby major pipelines, including the Sand Hills pipeline.

The fractionator is supported by significant new infrastructure including connectivity to two NGL supply pipelines, a 180,000 BPD bi-directional pipeline to the Mont Belvieu market center and a multi-million barrel salt dome storage facility with access to our marine terminal in Freeport, Texas.

During 2015, construction progressed on the Freeport LPG Export Terminal located at the site of our existing marine terminal in Freeport, Texas. The terminal expansion will leverage our transportation and storage infrastructure to supply petrochemical, heating and transportation markets globally. In addition, a 100,000 BPD unit to upgrade domestic propane for export is being installed near the Sweeny Fractionator One. The terminal will have an initial export capacity of 150,000 BPD of LPG with a ship loading rate of 36,000 barrels per hour. The terminal is currently exporting 10,000 to 15,000 BPD of natural gasoline (C5+) from Sweeny Fractionator One.

The LPG produced at Sweeny Fractionator One is being delivered via pipeline to local petrochemical customers, as well as to the market hub at Mont Belvieu, Texas. We will have the capability to place the LPG into global markets upon completion of our Freeport LPG Export Terminal in the second half of 2016. Sweeny Fractionator One and the Freeport LPG Export Terminal represent a combined capital investment of more than $3 billion.

CHEMICALS

The Chemicals segment consists of our 50 percent equity investment in CPChem, which is headquartered in The Woodlands, Texas. At the end of 2015, CPChem owned or had joint-venture interests in 34 manufacturing facilities and two research and development centers located around the world.

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

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The manufacturing of petrochemicals and plastics involves the conversion of hydrocarbon-based raw material feedstocks into higher-value products, often through a thermal process referred to in the industry as “cracking.” For example, ethylene can be produced from cracking the feedstocks ethane, propane, butane, natural gasoline or certain refinery liquids, such as naphtha and gas oil. The produced ethylene has a number of uses, primarily as a raw material 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.

The following table reflects CPChem’s petrochemicals and plastics product capacities at December 31, 2015:



	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	2,335	2,850
Polyalphaolefins	105	235
Polyethylene pipe	590	590
Total O&P	19,050	25,280

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	430	550
Nylon 6,6	—	55
Nylon compounding	—	20
Polymer conversion	—	130
Total SA&S	5,975	8,755
Total O&P and SA&S	25,025	34,035

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

In 2015, CPChem continued 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 the second quarter of 2015, CPChem completed construction and started commercial operations of a 220-million-pounds-per-year expansion of normal alpha olefin (NAO) production capacity at its Cedar Bayou plant. 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.

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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 were undertaken through CPChem’s 50-percent-owned joint venture company, Petrochemical Conversion Company Ltd. The projects started operations in stages during 2014 through 2015, with the nylon 6,6 project achieving commercial production in December 2015.

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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, 2015:



				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 2015	Effective January 1 2016	Gasolines	Distillates	Clean Product Yield Capability
Atlantic Basin/Europe
Bayway	Linden, NJ	100.00	%	238	238	145	115	92	%
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	88
Lake Charles	Westlake, LA	100.00		244	249	90	115	70
Sweeny	Old Ocean, TX	100.00		247	247	125	120	87
				738	743

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		203	203	110	90	93
Billings	Billings, MT	100.00		59	60	35	25	90
				492	493

Western/Pacific
Ferndale	Ferndale, WA	100.00		101	101	55	30	81
Los Angeles	Carson/ Wilmington, CA	100.00		139	139	80	65	90
San Francisco	Arroyo Grande/San Francisco, CA	100.00		120	120	55	60	84
				360	360
				2,178	2,184

*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			l
Humber	l	l		l				l	l
Whitegate	l							l	l
MiRO	l	l						l	l
Alliance	l				l
Lake Charles	l	l	l	l	l	l	l		l
Sweeny	l	l	l	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		l
Ferndale	l	l			l	l
Los Angeles		l	l	l	l	l	l		l
San Francisco	l	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 Germany, Switzerland and 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 7—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for information on the ownership of MSLP.

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.

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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.

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 is supplied to 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.

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 and barge to customers in California.

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MARKETING AND SPECIALTIES

Our M&S segment purchases for resale and markets refined petroleum products (such as gasolines, distillates and aviation fuels), mainly in the United States and Europe. In addition, this segment includes the manufacturing and marketing of specialty products (such as base oils and lubricants), as well as power generation operations.

Marketing

Marketing—United States

In the United States, as of December 31, 2015, we marketed gasoline, diesel and aviation fuel through approximately 8,350 marketer-owned or -supplied outlets in 48 states. These sites utilize the Phillips 66, Conoco or 76 brands.

At December 31, 2015, our wholesale operations utilized a network of marketers operating approximately 6,700 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 800 sites. Our refined products are marketed on both a branded and unbranded basis. A high percentage of our branded marketing sales are made in the Midcontinent, Rockies and West Coast regions, where our wholesale marketing operations provide efficient off-take from our refineries. We continue to utilize consignment fuels agreements with several marketers whereby we own the fuel inventory and pay the marketers a fixed monthly fee.

In the Gulf Coast and East Coast regions, most sales are conducted via unbranded sales which do not require a highly integrated marketing and distribution infrastructure to secure product placement for refinery pull through. We are expanding our export capability at our U.S. coastal refineries to meet growing international demand and increase flexibility to provide product to the highest-value markets.

In addition to automotive gasoline and diesel, we produce and market jet fuel and aviation gasoline, which is used by smaller piston-engine aircraft. At December 31, 2015, aviation gasoline and jet fuel were sold through dealers and independent marketers at approximately 850 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.

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, 2015, we had approximately 1,280 marketing outlets in our European operations, of which approximately 950 were company owned and 330 were dealer owned. In addition, through our joint venture operations in Switzerland, we have interests in 295 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.

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Lubricants

We manufacture and sell automotive, commercial, industrial and specialty lubricants which are marketed worldwide under the Phillips 66, Conoco, 76, Kendall, Red Line and Smart Blend brands, as well as other private label brands. We also market Group II Pure Performance base oils globally as well as import and market Group III Ultra-S base oils through an agreement with South Korea’s S-Oil corporation.

Other

Power Generation

We own a cogeneration power plant located adjacent to the Sweeny Refinery. The plant generates electricity and provides process steam to the refinery, as well as merchant power into the Texas market. The plant has a net electrical output of 440 megawatts and is capable of generating up to 3.6 million pounds per hour of process steam.

TECHNOLOGY DEVELOPMENT

Our Technology organization conducts applied and fundamental research in three areas: 1) support for our current business, 2) new environmental solutions for governmental regulations and 3) future growth. Technology programs include evaluating advantaged crudes, modeling for increased clean product yield, and increasing reliability. Our sustainability group concentrates on alternative and renewable energy, carbon dioxide capture, processing improvements, and product innovation. Another ongoing initiative studies whether fuel cells can be converted to use abundant natural gas, as opposed to hydrogen, to produce electricity. Additionally, we research in the areas of solar panels and water use and quality.

COMPETITION

The Midstream segment, through our equity investment in DCP Midstream and our other operations, competes with numerous integrated petroleum companies, as well as natural gas transmission and distribution companies, to deliver components of natural gas to end users in commodity natural gas markets. DCP Midstream is one of the leading natural gas gatherers and processors in the United States based on wellhead volumes, and one of the largest U.S. producers and marketers of NGL, based on published industry sources. Principal methods of competing include economically securing the right to purchase raw natural gas for gathering systems, managing the pressure of those systems, operating efficient NGL processing plants and securing markets for the products produced.

In the Chemicals segment, CPChem is ranked among the top 10 producers of many of its major product lines, based on average 2015 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 7, 2015, issue of the Oil & Gas Journal, we are one of the largest refiners of petroleum products in the United States. 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, 2015, we held a total of 404 active patents in 30 countries worldwide, including 260 active U.S. patents. During 2015, we received 31 patents in the United States and 14 foreign patents. 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 $65 million, $62 million and $69 million in 2015, 2014 and 2013, respectively.

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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 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 2015 and those expected for 2016 and 2017.

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 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, marketing and petrochemical margins.

Our revenues, operating results and future rate of growth are highly dependent on a number of factors, including fixed and variable expenses (including the cost of crude oil, NGLs, and other refinery and petrochemical feedstocks) and the margin we can derive from selling refined and Chemicals segment products. The prices of feedstocks and our products fluctuate substantially. These prices depend on numerous factors beyond our control, including the global supply and demand for feedstocks and our products, which are subject to, among other things:


•	Changes in the global economy and the level of foreign and domestic production of crude oil, natural gas and 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. During the period between the time we purchase feedstocks and sell the refined products from these feedstocks, price changes could have a significant effect on our financial results. We also purchase refined products produced by others for sale to our customers. Price 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 cash generated from operations with proceeds from financing activities. Uncertainty and illiquidity in financial markets may materially impact the ability of the participating financial institutions to fund their commitments to us under our liquidity facilities. Accordingly, we may not be able to obtain the full amount of the funds available under our liquidity facilities to satisfy our cash requirements, and our failure to do so could have a material adverse effect on our operations and financial position.

Deterioration in our credit profile could increase our costs of borrowing money and limit our access to the capital markets and commercial credit, and could trigger co-venturer rights under joint venture arrangements.

Our or Phillips 66 Partners’ credit ratings could be lowered or withdrawn entirely by a rating agency if, in its judgment, the circumstances warrant. If a rating agency were to downgrade our rating below investment grade, our or Phillips 66 Partners’ borrowing costs would increase, and our funding sources could decrease. In addition, a failure by us to maintain an investment grade rating could affect our business relationships with suppliers and operating partners. For example, our agreement with Chevron regarding CPChem permits Chevron to buy our 50 percent interest in CPChem for fair market value if we experience a change in control or if both 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 credit ratings could have a materially adverse impact on our future operations and financial position.

We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations. Likewise, future environmental laws and regulations may impact or limit our current business plans and reduce demand for our products.

Our business is subject to numerous laws and regulations relating to the protection of the environment. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:


•	The discharge of pollutants into the environment.


•	Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury emissions, and greenhouse gas emissions as they are, or may become, regulated).


•	The quantity of renewable fuels that must be blended into motor fuels.


•	The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous and nonhazardous wastes.


•	The dismantlement, 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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The adoption of climate change legislation could result in increased operating costs and reduced demand for the refined products we produce.

The U.S. government, including the EPA, as well as several state and international governments, have either considered or adopted legislation or regulations in an effort to reduce greenhouse gas (GHG) emissions. These proposed or promulgated laws apply or could apply in states and/or countries where we have interests or may have interests in the future. In addition, various groups suggest that additional laws may be needed in an effort to address climate change. We cannot predict the extent to which any such legislation will be enacted and, if so, what its provisions would be. To the extent we incur additional costs required to comply with the adoption of new laws and regulations that are not ultimately reflected in the prices of our products and services, our business, financial condition, results of operations and cash flows in future periods could be materially adversely affected. In addition, demand for the refined products we produce could be adversely affected.

Climate change may adversely affect our facilities and our ongoing operations.

The potential physical effects of climate change on our operations are highly uncertain and depend upon the unique geographic and environmental factors present. Examples of such effects include rising sea levels at our coastal facilities, changing storm patterns and intensities, and changing temperature levels. As many of our facilities are located near coastal areas, rising sea levels may disrupt our ability to operate those facilities or transport crude oil and refined petroleum products. Extended periods of such disruption could have an adverse effect on our results of operation. We could also incur substantial costs to 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

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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 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 produced from unconventional sources. 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

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studies and/or convened hearings regarding the potential environmental impacts of hydraulic fracturing activities. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed to provide for such regulation. In addition, some communities have adopted measures to ban hydraulic fracturing in their communities. We cannot predict whether any such legislation will ever be enacted and, if so, what its provisions would be. Any additional levels of regulation and permits required with the adoption of new laws and regulations at the federal or state level could result in our having to rely on higher priced crude oil for our refineries. This could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through DCP Midstream’s gathering systems and could reduce supplies and increase costs of NGL feedstocks to CPChem ethylene facilities. This could materially adversely affect our results of operations and the ability of DCP Midstream and CPChem to make cash distributions to us.

DCP Midstream’s success depends on its ability to obtain new sources of natural gas and NGL. Any decrease in the volumes of natural gas DCP Midstream gathers could adversely affect its business and operating results.

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

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

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

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

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

We currently use commodity derivative instruments, and we expect to use them in the future. If the instruments we utilize to hedge our exposure to various types of risk are not effective, we may incur losses. Derivative transactions involve the risk that counterparties may be unable to satisfy their obligations to us. A large percentage of our future production is subject to commodity price changes and our ability to fund our planned activities could be adversely affected if any of our counterparties were to default on their obligations to us under the hedging contracts or seek bankruptcy protection. The risk of counterparty default is heightened in a poor economic environment.

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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.

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 based on a variety of independent market information and in consultation with outside actuaries. If we determine that changes are warranted in the assumptions used, such as the discount rate, expected long-term rate of return, or health care cost trend rate, our future pension and postretirement benefit expenses and funding requirements could increase. In addition, several factors could cause actual results to differ significantly from the actuarial assumptions that we use. Funding obligations are determined based on the value of assets and liabilities on a specific date as required under relevant regulations. Future pension funding requirements, and the timing of funding payments, could be affected by legislation enacted by governmental authorities.

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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) any of our representations or undertakings being incorrect or violated, or (ii) other actions or failures to act by us. Our indemnification obligations to ConocoPhillips and

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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

In November and December of 2015, the Bay Area Quality Management District (AQMD) issued demands to settle 17 Notices of Violation (NOVs) issued in 2013 and 2014 with respect to alleged violations of regulatory and/or permit requirements at the Rodeo refining facility. The settlement demands aggregate to approximately $180,000. We are working with the Bay Area AQMD to resolve these matters.

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 in January 2016 an agreement was reached with LDEQ to resolve the remaining allegations.

In May 2012, the Illinois Attorney General’s office filed and notified us of a complaint with respect to operations at the Wood River Refinery alleging violations of the Illinois groundwater standards and a third-party’s hazardous waste permit. The complaint seeks as relief remediation of area groundwater; compliance with the hazardous waste permit; enhanced pipeline and tank integrity measures; additional spill reporting; and 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.

In October 2012, July 2014 and May 2015, the Bay Area AQMD issued demands to settle 64 NOVs issued in 2010 through 2013 with respect to alleged violations of regulatory and/or permit requirements at the Rodeo Refinery. The settlement demands aggregate approximately $900,000. We are working with the Bay Area AQMD to resolve these matters.

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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 September 2014, the EPA issued an NOV alleging a violation of hazardous air pollution regulations at the Wood River Refinery during 2014. We are working with the EPA to resolve this NOV.

In January 2015, the Bay Area AQMD made a $262,000 demand to settle five NOVs issued in 2012 with respect to an incident involving the release of material from a sour water tank at the Rodeo facility in June 2012. 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	58
Tim G. Taylor	President	62
Robert A. Herman	Executive Vice President, Midstream	56
Paula A. Johnson	Executive Vice President, Legal, General Counsel and Corporate Secretary	52
Kevin J. Mitchell	Executive Vice President, Finance and Chief Financial Officer	49
Lawrence M. Ziemba	Executive Vice President, Refining	60
Chukwuemeka A. Oyolu	Vice President and Controller	46
*On February 12, 2016.

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 Phillips 66’s Chairman, President and Chief Executive Officer from April 2012 to June 2014. Mr. Garland previously served as ConocoPhillips’ Senior Vice President, Exploration and Production—Americas from October 2010 to April 2012, and as President and Chief Executive Officer of CPChem from 2008 to 2010.

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 was Vice President, Health, Safety, and Environment for ConocoPhillips, from 2010 to 2012.

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 of ConocoPhillips from 2009 to 2012.

Kevin J. Mitchell is Executive Vice President, Finance and Chief Financial Officer of Phillips 66, a position he has held since January 2016. Previously, Mr. Mitchell served as Phillips 66’s Vice President, Investor Relations since joining the company in September 2014. Prior to joining the company, he served as the General Auditor of ConocoPhillips from May 2010 until September 2014.

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 from 2010 to 2012.

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
2015
First Quarter	$	80.59	57.33	.50
Second Quarter	82.19		76.43	.56
Third Quarter	84.85		69.79	.56
Fourth Quarter	94.12		76.45	.56

2014
First Quarter	$	80.39	68.78	.39
Second Quarter	87.05		76.18	.50
Third Quarter	87.98		78.53	.50
Fourth Quarter	82.00		64.02	.50

Performance Graph

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In the 2014 annual report, the performance graph included a peer index (the “Old Peer Group”) composed of Dow, Marathon Petroleum, Tesoro and Valero. To better reflect our unique portfolio of assets, we revised our peer index for 2015 (the “New Peer Group”) to include an expanded representative population of companies with assets and operations in all four of our major businesses; Midstream, Chemicals, Refining, and Marketing and Specialties. The New Peer Index is composed of Celanese, Delek, Dow, Eastman Chemical, Energy Transfer, Enterprise Products, HollyFrontier, Huntsman, Marathon Petroleum, Oneok, PBF Energy, Targa Resources, Tesoro, Valero, Western Refining, and Westlake Chemical. We anticipate using the index identified as “New Peer Index” in future annual reports.

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, 2015	1,556,053	$	80.99	1,556,053	$	2,884
November 1-30, 2015	1,314,018	90.96		1,314,018	2,765
December 1-31, 2015	1,861,861	85.63		1,861,861	2,604
Total	4,731,932	$	85.59	4,731,932

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

**Our Board of Directors has authorized repurchases totaling up to $9 billion of our outstanding common stock. The current authorization was announced in July 2014, in the amount of $2 billion, and increased to $4 billion as announced in October 2015. The authorization does not have an expiration date. 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, 2015, 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 the combined results of the downstream businesses for the four months ended April 30, 2012. The selected income statement data for the year ended December 31, 2011, consists entirely of the combined results of the downstream businesses.


•	The selected balance sheet data at December 31, 2015, 2014, 2013 and 2012, consist of the consolidated balances of Phillips 66, while the selected balance sheet data at December 31, 2011, consists of the combined balances of the downstream businesses.



	Millions of Dollars Except Per Share Amounts
	2015		2014	2013	2012	2011

Sales and other operating revenues	$	98,975	161,212	171,596	179,290	195,931
Income from continuing operations	4,280		4,091	3,682	4,083	4,737
Income from continuing operations attributable to Phillips 66	4,227		4,056	3,665	4,076	4,732
Per common share
Basic	7.78		7.15	5.97	6.47	7.54
Diluted	7.73		7.10	5.92	6.40	7.45
Net income	4,280		4,797	3,743	4,131	4,780
Net income attributable to Phillips 66	4,227		4,762	3,726	4,124	4,775
Per common share
Basic	7.78		8.40	6.07	6.55	7.61
Diluted	7.73		8.33	6.02	6.48	7.52
Total assets*	48,580		48,692	49,769	48,035	43,211
Long-term debt*	8,843		7,793	6,101	6,924	361
Cash dividends declared per common share	2.1800		1.8900	1.3275	0.4500	—

*Prior period amounts have been retrospectively adjusted for Accounting Standards Update No. 2015-03.

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.”

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, 2015, we had total assets of $48.6 billion.

Executive Overview

We reported earnings of $4.2 billion in 2015 and generated $5.7 billion in cash from operating activities. Phillips 66 Partners LP issued $1.1 billion of debt and $384 million of its common units to the public. We used available cash primarily to fund capital expenditures and investments of $5.8 billion, pay dividends of $1.2 billion, repurchase $1.5 billion of our common stock, and repay $800 million of senior notes that came due in 2015. We ended 2015 with $3.1 billion of cash and cash equivalents and approximately $4.9 billion of total capacity under our available liquidity facilities.

Our financial performance in 2015 demonstrated the benefit of a diversified portfolio of businesses in a low commodity price environment. We continue to focus on the following strategic priorities:

•

Operating Excellence. Our commitment to operating excellence guides everything we do. We are committed to protecting the health and safety of everyone who has a role in our operations and the communities in which we operate. Continuous improvement in safety, environmental stewardship, reliability and cost efficiency is a fundamental requirement for our company and employees. We employ rigorous training and audit programs to drive ongoing improvement in both personal and process safety as we strive for zero incidents. Since we cannot control commodity prices, controlling operating expenses and overhead costs, within the context of our commitment to safety and environmental stewardship, is a high priority. 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 2015, our worldwide refining crude oil capacity utilization rate was 91 percent.

•

Growth. We have budgeted $3.9 billion in capital expenditures and investments in 2016, including $0.3 billion for Phillips 66 Partners. Including our share of expected capital spending by joint ventures DCP Midstream, LLC (DCP Midstream), Chevron Phillips Chemical Company LLC (CPChem) and WRB Refining LP (WRB), our total 2016 capital program is expected to be $5.3 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

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reinvestment of its earnings to build additional manufacturing capacity benefiting from cost-advantaged NGL feedstocks. We continue to focus on funding the most attractive growth opportunities across our portfolio.


•	Returns. We plan to improve refining returns by increasing throughput of advantaged feedstocks, disciplined capital allocation and portfolio optimization. A disciplined capital allocation process ensures that we focus investments in projects that generate competitive returns throughout the business cycle. During 2015, 93 percent of the company's U.S. crude slate was advantaged.

•

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 quarterly dividend rate by 12 percent during 2015, and have increased it 180 percent since our separation from ConocoPhillips in 2012 (the Separation). Regular dividends demonstrate the confidence our management has in our capital structure and operation’s capability to generate free cash flow throughout the business cycle. Through December 31, 2015, we have cumulatively repurchased $6.4 billion, or approximately 92.5 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. In October 2015, our Board of Directors increased our current share repurchase authorization by $2 billion resulting in a total authorization of $4 billion. Since July 2012, our Board of Directors has authorized repurchases of our outstanding common stock totaling up to $9 billion.

•

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 culture. Throughout the company, we focus on getting results in the right way and believe success is both what we do and how we do it. We encourage collaboration throughout our company, while valuing differences, respecting diversity of thought, and creating a great place to work. We foster an environment of learning and development through structured programs focused on enhancing functional and technical skills where employees are engaged in our business and committed to their own, as well as the company’s, success.

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Business Environment

The dramatic fall in commodity prices, which started during the second half of 2014, continued throughout 2015. The U.S. oil rig count declined over 60 percent and crude oil production declined well below its peak which was set during the second quarter of 2015. Additionally, the discount for U.S. benchmark West Texas Intermediate (WTI) vs. the international benchmark Brent narrowed over the course of 2015 as logistical constraints between oil producing areas and major refining centers were incrementally removed during the year. Falling commodity prices have had a variety of impacts, both favorable and unfavorable, on our downstream businesses that vary by segment.

Earnings in the Midstream segment, which includes our 50 percent equity investment in DCP Midstream, are closely linked to NGL prices, natural gas prices and crude oil prices. NGL prices weakened throughout 2015 as NGL production growth from liquids-rich shale plays outpaced domestic demand growth from the petrochemical industry while export capacity remained constrained—driving prices lower and pushing inventories higher. Natural gas prices weakened throughout 2015 as well, as natural gas production growth continued and unseasonably warm weather limited demand.

During 2015, our Chemicals segment, which consists of our 50 percent equity investment in CPChem, continued to benefit from feedstock cost advantages associated with manufacturing ethylene in regions of the world with significant NGL production. The chemicals and plastics industry is mainly a commodity-based industry where the margins for key products are based on supply and demand, as well as cost factors. The petrochemicals industry continues to experience lower ethylene cash costs in regions of the world where ethylene manufacturing is based upon NGL rather than crude oil-derived feedstocks. In particular, companies with North American light NGL-based crackers have benefited from lower-priced feedstocks; however, the ethylene-to-polyethylene chain margins were compressed in 2015 because of the significant decline in crude oil prices that began in 2014.

Our Refining segment is driven by several factors including refining margins, cost control, refinery throughput and product yields. Refinery margins, often referred to as crack spreads, are measured as the difference between market prices for refined petroleum products and crude oil. During 2015, the U.S. 3:2:1 crack spread (three barrels of crude oil producing two barrels of gasoline and one barrel of diesel) improved over 2014 across all quarters, largely attributable to strong gasoline crack spreads which were driven by robust demand growth both in the U.S. and globally. The diesel crack spread weakened throughout 2015, driven by growing product inventories as a result of high refinery utilization to capture robust gasoline cracks and an unseasonably warm fourth quarter. The U.S. West Coast crack spread increased year over year as a result of significant refinery planned/unplanned maintenance in the region.

European refineries benefited during 2015 as domestic and export gasoline demand expanded considerably. Northwest European crack spreads on average increased in the first three quarters of the year and declined in the fourth quarter resulting in an average increase in 2015 compared to 2014. Strong margins were driven by the strength in gasoline margins which offset subdued diesel cracks during much of the year as large volumes of imported diesel from the United States, India, Asia Pacific and Russia kept diesel margins under pressure throughout the second half of the year.

Results for our Marketing and Specialties (M&S) segment depend largely on marketing fuel margins, lubricant margins and other specialty product margins. While M&S margins are primarily based on market factors, largely determined by the relationship between supply and demand, marketing fuel margins, in particular, are primarily determined by the trend of spot prices for refined products. Generally speaking, a downward trend of spot prices has a favorable impact on marketing fuel margins, while an upward trend of spot prices has an unfavorable impact on marketing fuel margins.

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RESULTS OF OPERATIONS

Consolidated Results

A summary of the company’s earnings follows:



	Millions of Dollars
	Year Ended December 31
	2015			2014		2013

Midstream	$	13		507		469
Chemicals	962			1,137		986
Refining	2,555			1,771		1,747
Marketing and Specialties	1,187			1,034		894
Corporate and Other	(490		)	(393	)	(431	)
Income from continuing operations attributable to Phillips 66	4,227			4,056		3,665
Discontinued Operations	—			706		61
Net income attributable to Phillips 66	$	4,227		4,762		3,726

2015 vs. 2014

Our earnings from continuing operations increased $171 million, or 4 percent, in 2015, primarily resulting from:


•	Improved realized refining margins as a result of increased gasoline crack spreads and improved secondary product margins.


•	Recognition of $242 million after-tax in 2015, compared with $126 million after-tax in 2014, of the deferred gain related to the sale in 2013 of the Immingham Combined Heat and Power Plant (ICHP).

These increases were partially offset by:


•	Lower equity earnings from DCP Midstream, primarily as a result of goodwill and other asset impairments and lower commodity prices.


•	Lower ethylene margins in our Chemicals segment.

2014 vs. 2013

Our earnings from continuing operations increased $391 million, or 11 percent, in 2014, primarily resulting from:


•	A gain on disposition and related deferred tax adjustment associated with the sale of Malaysian Refining Company Sdn. Bdh. (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 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.

Discontinued operations in 2014 included the recognition of a noncash $696 million after-tax gain related to the Phillips Specialty Products Inc. (PSPI) share exchange.

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

Income Statement Analysis

2015 vs. 2014

Sales and other operating revenues decreased 39 percent in 2015, while purchased crude oil and products decreased 46 percent. The decreases were primarily due to lower average prices for petroleum products, crude oil and NGL.

Equity in earnings of affiliates decreased 36 percent in 2015, primarily resulting from decreased earnings from DCP Midstream, CPChem and WRB.


•	Equity in earnings of DCP Midstream decreased $676 million in 2015. The decrease was primarily due to lower NGL, crude oil and natural gas prices. In addition, DCP Midstream recorded goodwill and other asset impairments in 2015 due to the significant downturn in commodity prices since mid-2014.


•	Equity in earnings of CPChem decreased 19 percent, primarily due to lower ethylene margins and lower equity earnings from CPChem’s equity affiliates, partially offset by lower utility costs.


•	Equity in earnings of WRB decreased 13 percent, primarily driven by its lower realized refining margins, resulting from lower feedstock advantage partially offset by higher secondary product margins.

Impairments in 2015 were $7 million, compared with $150 million in 2014. There were no significant impairments in 2015, compared with a $131 million impairment of the Whitegate Refinery recorded in 2014. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Interest and debt expense increased 16 percent in 2015. The increase was mainly due to a higher average debt principal balance in 2015, partially offset by increased capitalized interest.

See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rates.

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.

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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 was $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 6—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.

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 10—Impairments, in the Notes to Consolidated Financial Statements.

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 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information on this transaction.

See Note 21—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
	2015			2014	2013
	Millions of Dollars
Net Income (Loss) Attributable to Phillips 66
Transportation	$	288		233	199
DCP Midstream	(324		)	135	210
NGL	49			139	60
Total Midstream	$	13		507	469

	Dollars Per Unit
Weighted Average NGL Price*
DCP Midstream (per gallon)	$	0.45		0.89	0.90

*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*	3,264	3,206	3,144
Terminals	1,981	1,683	1,274
Operating Statistics
NGL extracted**	410	454	426
NGL fractionated***	112	109	115

*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.

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

***Excludes DCP Midstream.

The Midstream segment 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 terminaling and storage services for crude oil and petroleum products. The Midstream segment includes our master limited partnership, Phillips 66 Partners LP, as well as our 50 percent equity investment in DCP Midstream.

2015 vs. 2014

Earnings from the Midstream segment decreased $494 million in 2015, compared with 2014. The decrease was primarily due to lower earnings from DCP Midstream and our NGL business, partially offset by higher earnings from our transportation business.

Transportation earnings increased $55 million in 2015, compared with 2014. This increase reflects the startup of our Bayway and Ferndale crude oil rail unloading facilities in the second half of 2014, as well as a full year of operations from the Beaumont Terminal acquired in 2014. Increased railcar fleet activities, higher terminal revenues, and improved earnings from equity affiliates also benefited earnings in 2015. These benefits were partially offset by higher earnings attributable to noncontrolling interests.

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Earnings associated with our investment in DCP Midstream decreased $459 million in 2015, compared with 2014. The decrease in 2015 mainly resulted from lower NGL, crude oil, and natural gas prices, partially offset by increased volumes due to asset growth, and lower operating costs as a result of cost saving initiatives. In addition, goodwill and other asset impairments recorded by DCP Midstream in 2015 contributed to the loss recognized from our investment in DCP Midstream. DCP Midstream performed a goodwill impairment assessment and other asset impairment assessments based on internal discounted cash flow models taking into account various observable and non-observable factors, such as prices, volumes, expenses and discount rates. The impairment tests resulted in DCP Midstream’s recognition of a $460 million goodwill impairment and $342 million in other asset impairments, net of tax impacts. Together, these impairments reduced our equity earnings from DCP Midstream by $232 million after-tax.

DCP Midstream Partners, LP (DCP Partners), a master limited partnership formed by DCP Midstream, periodically issues limited partner units to the public. These issuances benefited our equity in earnings from DCP Midstream, on an after-tax basis, by approximately $1 million in 2015, compared with approximately $45 million in 2014.

The earnings from our NGL business decreased $90 million in 2015, compared with 2014. The decrease was primarily driven by lower realized margins and higher earnings attributable to noncontrolling interests. We also incurred higher tax expense in 2015, driven by a lower manufacturing deduction resulting from bonus depreciation associated with the start-up of Sweeny Fractionator One. These decreases were partially offset by higher earnings from equity affiliates.

See the “Business Environment and Executive Overview” section for information on market factors impacting this year’s results.

As previously disclosed, in early 2015 we and our co-venturer in DCP Midstream agreed to forgo cash distributions from DCP Midstream due to the significant decrease in commodity prices since mid-2014. The sustained weak commodity price environment during 2015 caused DCP Midstream to impair its goodwill in 2015 by $460 million, and impair certain assets and in-process capital projects in the fourth quarter of 2015 by an additional $342 million. To strengthen its balance sheet, during the fourth quarter of 2015 we contributed $1.5 billion of cash to DCP Midstream, while our co-venturer contributed its interests in certain operating assets held as equity investments. At December 31, 2015, the carrying value of our investment in DCP Midstream was approximately $2.3 billion. We will continue to monitor DCP Midstream’s operations and the continued weak commodity price environment for any further impacts on DCP Midstream or the carrying value of our investment.

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.

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 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 unit 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.

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Earnings from the NGL business increased $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 DCP Sand Hills, LLC (Sand Hills) and DCP Southern Hills, LLC (Southern Hills). These increases were partially offset by an increase in costs associated with growth projects.

Chemicals



	Year Ended December 31
	2015			2014	2013
	Millions of Dollars

Net Income Attributable to Phillips 66	$	962		1,137	986

	Millions of Pounds
CPChem Externally Marketed Sales Volumes*
Olefins and Polyolefins	16,916			16,815	16,071
Specialties, Aromatics and Styrenics	5,301			6,294	6,230
	22,217			23,109	22,301
*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)	91		%	88	88

The Chemicals segment consists of our 50 percent interest in CPChem, which we account for under the equity method. CPChem uses NGL and other feedstocks to produce petrochemicals. These products are then marketed and sold or used as feedstocks to produce plastics and other chemicals. We structure our reporting of CPChem’s operations around two primary business segments: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P business segment produces and markets ethylene and other olefin products; ethylene produced is primarily consumed within CPChem for the production of polyethylene, normal alpha olefins and polyethylene pipe. The SA&S business segment manufactures and markets aromatics and styrenics products, such as benzene, styrene, paraxylene and cyclohexane, as well as polystyrene 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.

2015 vs. 2014

Earnings from the Chemicals segment decreased $175 million, or 15 percent, in 2015, compared with 2014. The decrease in earnings was primarily due to lower margins resulting from lower sales prices, lower earnings from CPChem’s O&P equity affiliates, and higher turnaround and maintenance activities.

These decreases were partially offset by higher ethylene and polyethylene sales volumes, as well as lower repair costs due to the impact on 2014 costs of the fire at CPChem’s Port Arthur, Texas facility. Lower feedstock costs, lower utility costs due to falling natural gas prices, and lower impairment charges also benefited the 2015 operating 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 2014. 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 in 2014. CPChem recorded earnings, on a 100 percent basis, of $88 million and $120 million for business interruption and property damage insurance proceeds in 2015 and 2014, respectively.

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See the “Business Environment and Executive Overview” section for information on market factors impacting CPChem’s results.

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.

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Refining



	Year Ended December 31
	2015			2014	2013
	Millions of Dollars
Net Income Attributable to Phillips 66
Atlantic Basin/Europe	$	569		198	9
Gulf Coast	551			252	113
Central Corridor	857			967	1,540
Western/Pacific	578			354	85
Worldwide	$	2,555		1,771	1,747

	Dollars Per Barrel
Refining Margins
Atlantic Basin/Europe	$	9.39		8.94	7.09
Gulf Coast	9.29			7.64	6.49
Central Corridor	14.88			15.63	19.30
Western/Pacific	16.86			8.89	8.83
Worldwide	11.84			9.93	9.90

	Thousands of Barrels Daily
Operating Statistics
Refining operations*
Atlantic Basin/Europe
Crude oil capacity	588			588	588
Crude oil processed	539			554	546
Capacity utilization (percent)	92		%	94	93
Refinery production	587			605	578
Gulf Coast
Crude oil capacity	738			733	733
Crude oil processed	654			676	651
Capacity utilization (percent)	89		%	92	89
Refinery production	733			771	736
Central Corridor
Crude oil capacity	492			485	477
Crude oil processed	465			475	472
Capacity utilization (percent)	95		%	98	99
Refinery production	486			494	489
Western/Pacific
Crude oil capacity	360			440	440
Crude oil processed	330			403	410
Capacity utilization (percent)	92		%	92	93
Refinery production	359			435	445
Worldwide
Crude oil capacity	2,178			2,246	2,238
Crude oil processed	1,988			2,108	2,079
Capacity utilization (percent)	91		%	94	93
Refinery production	2,165			2,305	2,248
*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.

2015 vs. 2014

Earnings for the Refining segment increased $784 million, or 44 percent, compared with 2014. The increase in earnings in 2015 primarily resulted from higher realized refining margins due to higher gasoline crack spreads and improved secondary product margins, as well as lower utility costs. These increases were partially offset by lower feedstock advantage, lower distillate crack spreads, lower clean product differentials, and lower refining volumes as a result of higher unplanned downtime and turnaround activities.

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 91 percent in 2015, compared to 94 percent in 2014. The decrease reflects higher unplanned downtime and turnaround activities.

Effective January 1, 2015, we aligned the results of the activities previously included in “Other Refining” into the Atlantic Basin/Europe, Gulf Coast, Central Corridor, and Western/Pacific refining regions. There were no changes to the consolidated Refining operating segment as a result of this alignment. The new alignment is presented for the year ended December 31, 2015, with the prior periods retrospectively adjusted for comparability.

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.

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 occurred in the Gulf Coast region in 2013.

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Marketing and Specialties



	Year Ended December 31
	2015		2014	2013
	Millions of Dollars
Net Income Attributable to Phillips 66
Marketing and Other	$	1,004	836	688
Specialties	183		198	206
Total Marketing and Specialties	$	1,187	1,034	894

	Dollars Per Barrel
Realized Marketing Fuel Margin*
U.S.	$	1.65	1.51	1.21
International	4.40		5.22	4.36
*On third-party petroleum products sales.

	Dollars Per Gallon
U.S. Average Wholesale Prices*
Gasoline	$	1.92	2.72	2.88
Distillates	1.77		2.95	3.10
*Excludes excise taxes.

	Thousands of Barrels Daily
Marketing Petroleum Products Sales
Gasoline	1,205		1,195	1,174
Distillates	953		979	967
Other	16		17	17
	2,174		2,191	2,158

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.

2015 vs. 2014

Earnings from the M&S segment increased $153 million, or 15 percent, in 2015, compared with 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. We recognized $242 million after-tax and $126 million after-tax of the deferred gain in 2015 and 2014, respectively.

Earnings from the M&S segment also benefited from higher domestic marketing activities, higher domestic marketing and lubricants volumes, and increased tax credits from biodiesel blending activities. These benefits were partially offset by lower international marketing margins and lubricants margins.

See the “Business Environment and Executive Overview” section for information on marketing fuel margins and other market factors impacting 2015 results.

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2014 vs. 2013

Earnings from the M&S segment increased $140 million, or 16 percent, in 2014, compared with 2013. 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 2014, we recognized $126 million after-tax of the deferred gain related to the sale in 2013 of the ICHP, increasing earnings. These increases were partially offset by the lack of ICHP earnings in 2014, compared with earnings of $53 million in 2013.

Corporate and Other



	Millions of Dollars
	Year Ended December 31
	2015			2014		2013
Net Loss Attributable to Phillips 66
Net interest expense	$	(186	)	(160	)	(166	)
Corporate general and administrative expenses	(157		)	(156	)	(145	)
Technology	(60		)	(58	)	(50	)
Other	(87		)	(19	)	(70	)
Total Corporate and Other	$	(490	)	(393	)	(431	)

2015 vs. 2014

Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense increased $26 million in 2015, compared with 2014, primarily due to a higher average debt principal balance as a result of the issuance of debt in the fourth quarter of 2014 and Phillips 66 Partners’ debt issuance in the first quarter of 2015. The increase was partially offset by higher capitalized interest. For additional information, see Note 13—Debt, in the Notes to Consolidated Financial Statements.

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 increase in costs in 2015 was primarily due to foreign tax credit carryforwards that were utilized in 2014 and other tax adjustments made in 2015.

2014 vs. 2013

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 13—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 decrease in other costs was primarily due to increased utilization of foreign tax credit carryforwards. In addition, higher environmental costs negatively affected our 2013 results.

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Discontinued Operations



	Millions of Dollars
	Year Ended December 31
	2015		2014	2013
Net Income Attributable to Phillips 66
Discontinued operations	$	—	706	61

In December 2013, we entered into an agreement to exchange the stock of PSPI, a flow improver business that was included in our M&S segment, for shares of Phillips 66 common stock owned by the other party to the transaction. In February 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 6—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
	2015			2014	2013

Cash and cash equivalents	$	3,074		5,207	5,400
Net cash provided by operating activities	5,713			3,529	6,027
Short-term debt	44			842	24
Total debt	8,887			8,635	6,125
Total equity	23,938			22,037	22,392
Percent of total debt to capital*	27		%	28	21
Percent of floating-rate debt to total debt	1		%	1	1
*Capital includes total debt and total equity.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities and Phillips 66 Partners’ debt and equity financings. During 2015, we generated $5.7 billion in cash from operations and received $1.1 billion from Phillips 66 Partners’ issuance of senior notes and $0.4 billion from the issuance of Phillips 66 Partners’ common units to the public. We used available cash primarily for capital expenditures and investments ($5.8 billion), including a contribution to DCP Midstream ($1.5 billion); debt repayments ($0.9 billion); repurchases of our common stock ($1.5 billion); and dividend payments on our common stock ($1.2 billion). During 2015, cash and cash equivalents decreased by $2.1 billion, to $3.1 billion.

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

Significant Sources of Capital

Operating Activities

During 2015, cash of $5,713 million was provided by operating activities, a 62 percent increase over 2014. Net income in 2015 was lower than 2014; however, in both years large noncash items affected earnings, including the gain on the PSPI exchange in 2014, recognition in 2015 and 2014 of a deferred gain from a 2013 asset disposition, and goodwill and other asset impairments by DCP Midstream in 2015. Excluding these items, underlying earnings in 2015 were slightly improved compared with 2014, primarily reflecting increased refining margins and increased domestic marketing volumes, partially offset by lower midstream prices. Negative working capital impacted operating cash flow by $221 million and $1,020 million in 2015 and 2014, respectively. The lower negative working capital impact in 2015 was driven by decreased refining payables due to lower feedstock costs in 2015 as compared with 2014, partially offset by a reduction in receivables due to reduced commodity prices. See the following paragraph for a discussion of 2014 working capital effects.

During 2014, cash of $3,529 million was provided by operating activities, a 41 percent decrease from cash from operations of $6,027 million in 2013. Although net income was higher in 2014 than in 2013, certain large noncash items benefitted 2014 earnings, including the gain on the PSPI exchange, gains from asset dispositions and the deferred tax effects of certain asset dispositions. Excluding 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

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balance sheet than receivables. By comparison, accounts payable activity increased cash from operations by $360 million in 2013, reflecting both higher volumes and commodity prices, while lower refining margins, reflecting less favorable market conditions and tightening of crude differentials, negatively impacted 2013 working capital. 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.

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. Factors such as operating efficiency, maintenance turnarounds, market conditions, feedstock availability and weather conditions can affect output. We actively manage the operations of our refineries, and any variability in their operations typically has not been as significant to cash flows as that caused by margins and prices. Our worldwide refining crude oil capacity utilization was 91 percent in 2015, compared with 94 percent in 2014. We expect 2016 utilization to be in the mid 90-percent range.

Equity Affiliates

Our operating cash flows are also impacted by distribution decisions made by our equity affiliates, including DCP Midstream, CPChem and WRB. Over the three years ended December 31, 2015, we received distributions of $452 million from DCP Midstream, $2,879 million from CPChem and $2,938 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.

During the second quarter of 2015, CPChem made a special distribution to its owners, with our share totaling $696 million. CPChem funded the distribution by issuing $1.4 billion of senior notes with maturities ranging from three to five years, with a combination of fixed and variable interest rates. This cash inflow from CPChem was included in operating cash flows, as we had cumulative undistributed equity earnings attributable to CPChem in excess of the amount distributed.

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

Net proceeds from asset sales in 2015 were $70 million, compared with $1,244 million in 2014 and $1,214 million in 2013. The 2015 net proceeds were attributed to the sale of the Bantry Bay terminal in Ireland and the sale of certain retail sites in Kansas and Missouri, and were partially offset by a working capital true-up related to the 2014 sale of our interest in MRC. 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.

Foreign Cash Holdings

At December 31, 2015, approximately 44 percent of our consolidated cash and cash equivalents balance was available to fund domestic opportunities without incurring material additional U.S. income taxes in excess of the amounts already accrued in the financial statements. We believe the remaining amount, primarily attributable to cash we hold in foreign locations where we have asserted our intention to indefinitely reinvest earnings, does not materially affect our consolidated liquidity due to the following factors:

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•	A substantial portion of our foreign cash supports the liquidity needs and regulatory requirements of our foreign operations.


•	We have the ability to fund a significant portion of our domestic capital requirements with cash provided by domestic operating activities.


•	We have access to U.S. capital markets through our $5 billion committed revolving credit facility, commercial paper program, and shelf registration statement.

See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information on income taxes associated with foreign earnings.

Income Taxes

As part of our normal tax administrative process, we made scheduled U.S. federal income tax payments in 2015 using the Internal Revenue Service (IRS) safe harbor method for estimated 2015 taxable income. We determined that a portion of those payments is refundable as an overpayment of estimated tax, primarily due to U.S. tax legislation enacted late in the year, and we filed a refund claim with the IRS in the first quarter of 2016. We expect this refund to benefit cash from operations in the first quarter of 2016 by approximately $590 million.

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. 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.

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.

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 of 2014, for consideration in the aggregate of approximately $55 million.

Effective March 2, 2015, we contributed to Phillips 66 Partners our one-third equity interests in Sand Hills and Southern Hills, as well as our 19.5 percent equity interest in Explorer Pipeline Company (Explorer), for total consideration of $1,010 million. Each of these investments is accounted for under the equity method of accounting. Phillips 66 Partners financed the acquisition with $880 million in cash, partially funded by a public offering of common units representing limited partner interests and debt financing, and the issuance to us of 1,587,376 and 139,538 additional common units and general partner units, respectively, with an aggregate fair value of $130 million.

Effective December 1, 2015, we contributed to Phillips 66 Partners our 40 percent equity interest in Bayou Bridge Pipeline, LLC (Bayou Bridge) for total consideration of $70 million. This investment is accounted for under the equity method of accounting. Phillips 66 Partners financed one-half of the acquisition with a $35 million note payable to us and one-half with the issuance to us of 606,056 and 12,369 additional common units and general partner units, respectively,

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having an aggregate fair value of $35 million. Phillips 66 Partners immediately repaid the note payable. See Note 13—Debt and Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information.

Ownership

At December 31, 2015, we owned a 69 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while its public unitholders owned a 29 percent limited partner interest. We consolidate Phillips 66 Partners as a variable interest entity for financial reporting purposes. See Note 3—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 an $809 million noncontrolling interest in our financial statements at December 31, 2015. Generally, contributions of assets by us to Phillips 66 Partners will eliminate in consolidation, except for third-party debt or equity offerings made by Phillips 66 Partners to finance such transactions. For the first contribution in 2015 together with the public offerings of common units and senior notes discussed below, our consolidated cash increased by $1.5 billion, consolidated debt increased by $1.1 billion and consolidated equity increased by $384 million as a result of the transactions. The Bayou Bridge contribution in 2015 discussed above did not impact our consolidated financial statements. 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.

Debt and Equity Financings

In February 2015, Phillips 66 Partners closed on a public offering of $1.1 billion aggregate principal amount of unsecured senior notes, consisting of:


•	$300 million of 2.646% Senior Notes due 2020.


•	$500 million of 3.605% Senior Notes due 2025.


•	$300 million of 4.680% Senior Notes due 2045.

Interest on each series of the senior notes is payable semi-annually in arrears.

In February 2015, Phillips 66 Partners completed a public offering of 5,250,000 common units representing limited partner interests. The net proceeds received at closing were $384 million.

Phillips 66 Partners used a portion of the net proceeds of both the debt and equity offerings to fund its March 2015 acquisition transaction described above. See Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on this acquisition.

Credit Facilities and Commercial Paper

Phillips 66 has a $5 billion revolving credit facility that extends until December 2019. The 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 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, 2015, no amount had been directly drawn under our $5 billion credit facility; however, $51 million in letters of credit had been issued that were supported by this facility. As a result, we ended 2015 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, 2015, we had no borrowings under our commercial paper program.

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Phillips 66 Partners has a $500 million revolving credit facility that extends until November 2019. The Phillips 66 Partners facility is with a broad syndicate of financial institutions. As of December 31, 2015, no amounts were outstanding under the facility.

Debt Financing

Our $7.5 billion of outstanding Senior Notes were issued by Phillips 66 and are guaranteed by Phillips 66 Company, a 100-percent-owned subsidiary. Our senior unsecured long-term debt has been rated investment grade by S&P (BBB+) and Moody’s (A3). We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating. If our credit rating deteriorated to a level prohibiting us from accessing the commercial paper market, we would expect to be able to access funds under our liquidity facilities mentioned above.

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

We have capital lease obligations related to equipment and transportation assets, and the use of an oil terminal in the United Kingdom. These leases mature within the next eighteen years. The present value of our minimum capital lease payments for these obligations as of December 31, 2015, was $208 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, 2015, the aggregate principal amount of MSLP debt guaranteed by us was $157 million.

For additional information about guarantees, see Note 14—Guarantees, in the Notes to Consolidated Financial Statements.

Capital Requirements

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

Our debt balance at December 31, 2015, was $8.9 billion and our debt-to-capital ratio was 27 percent. Excluding Phillips 66 Partners’ debt of $1.1 billion and its noncontrolling interest of $809 million, our adjusted debt-to-capital ratio at December 31, 2015, was 25 percent. Our target adjusted debt-to-capital ratio, excluding the impact of Phillips 66 Partners, is between 20 and 30 percent.

On February 3, 2016, our Board of Directors declared a quarterly cash dividend of $0.56 per common share, payable March 1, 2016, to holders of record at the close of business on February 16, 2016. We are forecasting a double-digit percentage increase in our quarterly dividend rate in 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 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, 2015, approximately $486 million had been drawn to fund construction costs, of which approximately $440 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. We expect the lease to commence in the first half of 2016.

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outstanding common stock totaling up to $9 billion. The share repurchases are expected to be funded primarily through available cash. The shares will be repurchased from time to time in the open market at our discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Since the inception of our share repurchases in 2012 through December 31, 2015, we have repurchased a total of 92,503,292 shares at a cost of $6.4 billion. Shares of stock repurchased are held as treasury shares.

On May 1, 2015, the U.S. Department of Transportation issued a final rule focused on the safe transportation of flammable liquids by rail. The final rule, which is being challenged, subjects new and existing railcars transporting crude oil in high volumes to heightened design standards, including thicker tank walls and heat shields, improved pressure relief valves and enhanced braking systems. We are currently evaluating the impact of the new regulations on our crude oil railcar fleet, which is mostly held under operating leases. The regulations become effective subsequent to the expiration dates of our leases. Although we have no direct contractual obligation to retrofit these leased railcars, certain leases are subject to residual value guarantees. Under the lease terms, we have the option either to purchase the railcars or to return them to the lessors. If railcars are returned to the lessors, we may be required to make the lessors whole under the residual value guarantees, which are subject to a cap. The current market demand for crude oil railcars is low, which has resulted in a significant decline in crude oil railcar prices. Due to current market uncertainties, it is not currently possible to reasonably estimate the future market value for railcars at the end of their lease terms.

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Contractual Obligations

The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2015:



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

Debt obligations (a)	$	8,679	28	1,565	352	6,734
Capital lease obligations	208		16	31	22	139
Total debt	8,887		44	1,596	374	6,873
Interest on debt	6,735		394	714	678	4,949
Operating lease obligations	2,009		510	726	405	368
Purchase obligations (b)	62,691		23,502	8,497	5,530	25,162
Other long-term liabilities (c)
Asset retirement obligations	251		7	16	10	218
Accrued environmental costs	485		64	104	70	247
Unrecognized tax benefits (d)	13		13	(d)	(d)	(d)
Total	$	81,071	24,534	11,653	7,067	37,817


(a)	For additional information, see Note 13—Debt, in the Notes to Consolidated Financial Statements.

(b)

Represents any agreement to purchase goods or services that is enforceable, legally binding and specifies all significant terms. We expect these purchase obligations will be fulfilled by operating cash flows in the applicable maturity period. The majority of the purchase obligations are market-based contracts, including exchanges and futures, for the purchase of products such as crude oil and unfractionated NGL. The products are mostly used to supply our refineries and fractionators, optimize the supply chain, and resell to customers. Product purchase commitments with third parties totaled $32,326 million. In addition, $16,807 million are product purchases from CPChem, mostly for natural gas and NGL over the remaining contractual term of 84 years, and $4,409 million from Excel Paralubes, for base oil over the remaining contractual term of 9 years.

Purchase obligations of $5,600 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 2016 through 2020 time period, we expect to contribute an average of $170 million per year to our qualified and nonqualified pension and other postretirement benefit plans in the United States and an average of $50 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 $50 million for 2016 and then approximately $200 million per year for the remaining four years. Our minimum funding in 2016 is expected to be $50 million in the United States and $50 million outside the United States.

(d)

Excludes unrecognized tax benefits of $69 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 $19 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
	2016 Budget		2015	2014	2013
Capital Expenditures and Investments
Midstream	$	2,346	4,457	2,173	597
Chemicals	—		—	—	—
Refining	1,217		1,069	1,038	820
Marketing and Specialties	137		122	439	226
Corporate and Other	180		116	123	136
Total consolidated from continuing operations	$	3,880	5,764	3,773	1,779

Discontinued operations	$	—	—	—	27

Selected Equity Affiliates*
DCP Midstream	$	223	438	776	971
CPChem**	1,016		1,319	886	613
WRB	184		175	140	109
	$	1,423	1,932	1,802	1,693

*Our share of capital spending.

**2014 amount restated.

Midstream

During the three-year period ended December 31, 2015, DCP Midstream’s capital expenditures and investments were $4.4 billion on a 100 percent basis. In 2013 and 2014, we made additional investments of $0.3 billion in both Sand Hills and Southern Hills, increasing our total direct investment to $0.8 billion. In October 2015, we contributed $1.5 billion of cash to DCP Midstream and our co-venturer contributed its interests in certain operating assets of equal value, that are held as equity investments. Upon completion of this transaction, our interest in DCP Midstream remained at 50 percent.

Other capital spending in our Midstream segment during the three-year period ended December 31, 2015, included:


•	Construction activities related to our Sweeny Fractionator One and Freeport LPG Export Terminal projects.


•	Acquisition of a 7.1 million-barrel-storage-capacity crude oil and petroleum products terminal located near Beaumont, Texas.


•	Construction of rail racks to accept advantaged crude deliveries at our Bayway and Ferndale refineries.


•	Purchase of an additional 5.7 percent interest in the refined products Explorer pipeline.


•	Pipeline projects being developed by two of our joint ventures, Dakota Access LLC (DAPL) and Energy Transfer Crude Oil Company, LLC (ETCOP). We own a 25 percent interest in each of these joint ventures.


•	Spending associated with return, reliability and maintenance projects in our Transportation and NGL businesses.

In April 2015, Rockies Express Pipeline LLC (REX) repaid $450 million of its debt, reducing its long-term debt to approximately $2.6 billion. REX funded the repayment through member cash contributions. Our 25 percent share was approximately $112 million, which we contributed to REX in April 2015.

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Chemicals

During the three-year period ended December 31, 2015, CPChem had a self-funded capital program, and thus required no new capital infusions from us or our co-venturer. During this period, on a 100 percent basis, CPChem’s capital expenditures and investments were $5.6 billion. In addition, CPChem’s advances to equity affiliates, primarily used for project construction and start-up activities, were $0.3 billion and its repayments received from equity affiliates were $0.1 billion.

Refining

Capital spending for the Refining segment during the three-year period ended December 31, 2015, was $2.9 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 new coke drums at the Ponca City refinery.


•	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.


•	Installation of facilities to improve clean product yields at Sweeny and Lake Charles refineries.


•	Installation of facilities to improve processing of advantaged crudes at Alliance and Ponca City refineries.

Major construction activities in progress include:


•	Installation of a crude tank to increase accessibility of waterborne crude at the Los Angeles Refinery.


•	Installation of facilities to comply with U.S. Environmental Protection Agency (EPA) Tier 3 gasoline regulations at the Sweeny, Alliance, Bayway and Lake Charles refineries.


•	Installation of facilities to improve processing of advantaged crudes at Billings refinery.


•	Installation of facilities to improve clean product yield at Bayway and Ponca City refineries.

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 $0.9 billion. We expect WRB’s 2016 capital program to be self-funding.

Marketing and Specialties

Capital spending for the M&S segment during the three-year period ended December 31, 2015, 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, which have subsequently been disposed of; the acquisition of Spectrum Corporation, a private label specialty lubricants business headquartered in Memphis, Tennessee; the acquisition of 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, 2015, was primarily for projects related to information technology and facilities.

2016 Budget

Our 2016 capital budget is $3.9 billion including Phillips 66 Partners’ capital budget of $0.3 billion. This excludes our portion of planned capital spending by joint ventures DCP Midstream, CPChem and WRB totaling $1.4 billion, all of which are expected to be self-funded.

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The Midstream capital budget of $2.3 billion is focused on growth projects, such as continued construction of the 150,000 barrels-per-day Freeport LPG Export Terminal on the U.S. Gulf Coast, the new DAPL and ETCOP pipeline projects, expansion of the Beaumont Terminal, and the Bayou Bridge pipeline project.

Refining’s capital budget of $1.2 billion is directed toward reliability, safety and environmental projects, including compliance with the new Tier 3 gasoline specifications, as well as projects designed to improve product yields and lower feedstock costs.

In Marketing and Specialties, we plan to invest approximately $0.1 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 that arose in the ordinary course of business have been filed against us or are subject to indemnifications provided by us. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for financial recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other potentially responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.

Legal and Tax Matters

Our legal and tax matters are handled by our legal and tax organizations. These organizations apply their knowledge, experience and professional judgment to the specific characteristics of our cases and uncertain tax positions. We employ a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases and enables the tracking of those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required. In the case of income-tax-related contingencies, we monitor tax legislation and court decisions, the status of tax audits and the statute of limitations within which a taxing authority can assert a liability. See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information about income-tax-related contingencies.

Environmental

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.

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•	European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH), which governs the manufacture, placing on the market or use of chemicals.


•	U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur.


•	U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage and disposal of solid waste.


•	U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories to local emergency planning committees and response departments.


•	U.S. Federal 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 as well as owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States.


•	European Union Trading Directive resulting in the European Union Emissions Trading Scheme (EU ETS), which uses a market-based mechanism to incentivize the reduction of greenhouse gas emissions.

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

Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of 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 of this 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. For the 2016 compliance year, the U.S. Environmental Protection Agency (EPA) will require greater volumes of advanced and total renewable fuel than mandated in previous years; it is uncertain if these increased obligations will be achievable by fuel producers and shippers without drawing on the Renewable Identification Number (RIN) bank. For compliance years after 2016, we do not know whether the EPA will utilize its authority to reduce statutory volumes. Additionally, we may experience a decrease in demand for refined petroleum products due to the regulatory program as currently promulgated. This program continues to be the subject of possible Congressional review and re-promulgation in revised form, and the EPA’s recently enacted regulations pertaining to the 2014, 2015, and 2016 compliance years are subject to legal challenge, further creating uncertainty regarding renewable fuel volume requirements and obligations.

The EPA’s Renewable Fuel Standard (RFS) program was also 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 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

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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 purchased RINs in the past that were invalid due to fraudulent activity of third parties. Costs to replace fraudulently marketed RINs that have been determined to be invalid have not been material through December 31, 2015; however, 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.

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.

We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2014, we reported that we had been notified of potential liability under CERCLA and comparable state laws at 34 sites within the United States. During 2015, we were notified of four new sites, settled and closed one site, and resolved one site, leaving 36 unresolved sites with potential liability at December 31, 2015.

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 $581 million in 2015 and are expected to be approximately $655 million in each of the years 2016 and 2017. Capitalized environmental costs were $330 million in 2015 and are expected to be approximately $235 million in each of the years 2016 and 2017. 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).

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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, 2015, our balance sheet included total accrued environmental costs of $485 million, compared with $496 million at December 31, 2014, and $492 million at December 31, 2013. 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 on our results of operations or financial position as a result of compliance with current environmental laws and regulations.

Climate Change

There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) emissions reduction, including various regulations proposed or issued by the EPA. These proposed or promulgated laws apply or could apply in states and/or countries where we have interests or may have interests in the future. We consider and take into account future GHG emissions in designing and developing major facilities and projects, and implement energy efficiency initiatives to reduce such emissions. Laws regulating GHG emissions continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, potentially could have a material impact on our results of operations and financial condition as a result of increasing costs of compliance, lengthening project implementation and agency review items, or reducing demand for certain hydrocarbon products. Examples of legislation or precursors for possible regulation that do or could affect our operations include:


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

•

California’s Global Warming Solutions Act, which requires the California Air Resources Board to develop regulations and market mechanisms that will target reduction of California’s GHG emissions by 25 percent by 2020. Other GHG emissions programs in the western U.S. states have been enacted or are in the process of development, including amendments to California's Low Carbon Fuel Standard, Oregon's Low Carbon Fuel Standard, and Washington's cap and trade program.


•	The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S. Ct. 1438 (2007), confirming that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under the Federal Clean Air Act.

•

The EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that triggers regulation of GHGs under the Clean Air Act. These collectively may lead to more climate-based claims for damages, and may result in longer agency review time for development projects to determine the extent of potential climate change.


•	EPA's 2015 Final Rule regulating GHG emissions from existing fossil fuel-fired electrical generating units under the Federal Clean Air Act, commonly referred to as the Clean Power Plan.


•	Carbon taxes in certain jurisdictions.


•	GHG emission cap and trade programs in certain jurisdictions.

In the EU, the first phase of the EU ETS completed at the end of 2007 and Phase II was undertaken from 2008 through to 2012. The current phase (Phase III) runs from 2013 through to 2020, with the main changes being reduced allocation of

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free allowances and increased auctioning of new allowances. Phillips 66 has assets that are subject to the EU ETS, and the company is actively engaged in minimizing any financial impact from the EU ETS.

From November 30 to December 12, 2015, more than 190 countries, including the United States, participated in the United Nations Climate Change Conference in Paris, France. The conference culminated in what is known as the “Paris Agreement,” which is currently open for agreement by countries until April 22, 2016. The Paris Agreement establishes a commitment by signatory parties to pursue domestic GHG emission reductions.

In the United States, some additional form of regulation is likely to 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 had been limited to certain stationary sources, which include our refineries in California, but beginning in January 2015 expanded to include emissions from transportation fuels distributed in California. Inclusion of transportation fuels in California’s cap and trade program as currently promulgated has increased our cap and trade program compliance costs. The ultimate impact on our financial performance, either positive or negative, from this and similar programs, will depend on a number of factors, including, but not limited to:


•	Whether and to what extent legislation or regulation is enacted.


•	The nature of the legislation or regulation (such as a cap and trade system or a tax on emissions).


•	The GHG reductions required.


•	The price and availability of offsets.


•	The 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 1—Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussion of critical accounting estimates, along with the discussion of contingencies in this report, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

Impairments

Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected 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

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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 are indicators of a loss in value, such as a lack of sustained earnings capacity or a current fair value less than the investment’s carrying amount. When it is determined that an indicated impairment is other than temporary, a charge is recognized for the difference between the investment’s carrying value and its estimated fair value.

When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention to retain our investment for a period that allows for recovery. When quoted market prices are not available, the fair value is usually based on the present value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants and a market analysis of comparable assets, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period.

Asset Retirement Obligations

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

Environmental Costs

In addition to asset retirement obligations discussed above, 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, 2015, we had $770 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, 2015, 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.

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Because quoted market prices for our reporting units are not available, management applies judgment in determining the estimated fair values of the reporting units for purposes of performing the goodwill impairment test. Management uses all available information to make this fair value determination, including observed market earnings multiples of comparable companies, our common stock price and associated total company market capitalization and the present values of expected future cash flows using discount rates commensurate with the risks associated with the assets. Sales or dispositions of significant assets within a reporting unit are allocated a portion of that reporting unit’s goodwill, based on relative fair values, which impacts the amount of gain or loss on the sale or disposition.

We completed our annual impairment test, as of October 1, 2015, and concluded that the fair value of our reporting units exceeded their recorded net book values (including goodwill). The fair values of each of our Refining, Transportation and M&S reporting units exceeded their respective 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. After we’ve completed our annual test, we continue to monitor for impairment indicators, which can lead to further goodwill impairment testing.

Tax Assets and Liabilities

Our operations are subject to various taxes, including federal, state and foreign income taxes, property taxes, and transactional taxes such as excise, sales/use and payroll taxes. We record tax liabilities based on our assessment of existing tax laws and regulations. The recording of tax liabilities requires significant judgment and estimates. We recognize the financial statement effects of an income tax position when it is more likely than not that the position will be sustained upon examination by a taxing authority. A contingent liability related to a transactional tax claim is recorded if the loss is both probable and estimable. Actual incurred tax liabilities can vary from our estimates for a variety of reasons, including different interpretations of tax laws and regulations and different assessments of the amount of tax due.

In determining our income tax 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 impacts the obligations on the balance sheet and the amount of benefit expense in the income statement. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future 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 percentage-point decrease in the discount rate assumption would increase annual benefit expense by an estimated $60 million, while a 1 percentage-point decrease in the return on plan assets assumption would increase annual benefit expense by an estimated $30 million. In determining the discount rate, we use yields on high-quality fixed income investments with payments matched to the estimated distributions of benefits from our plans.

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In 2015 and 2014, the company used an expected long-term rate of return of 7 percent for the U.S. pension plan assets, which account for 73 percent of the company’s pension plan assets. The actual asset returns were a loss of less than 1 percent in 2015 and a gain of 9 percent in 2014. For the past ten years, actual returns averaged 7 percent for the U.S. pension plan assets.

NEW ACCOUNTING STANDARDS

In January 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-01, “Financial Instruments-Overall (Subtopic 825-10),” to meet its objective of providing more decision-useful information about financial instruments. The majority of this ASU’s provisions amend only the presentation or disclosures of financial instruments; however, one provision will also affect net income. Equity investments carried under the cost method or lower of cost or fair value method of accounting, in accordance with current generally accepted accounting principles, will have to be carried at fair value upon adoption of ASU 2016-01, with changes in fair value recorded in net income. For equity investments that do not have readily determinable fair values, a company may elect to carry such investments at cost less impairments, if any, adjusted up or down for price changes in similar financial instruments issued by the investee, when and if observed. Public business entities should apply the guidance in ASU 2016-01 for annual periods beginning after December 15, 2017, and interim periods within those annual periods, with early adoption prohibited. We are currently evaluating the provisions of ASU 2016-01 and assessing the impact, if any, it may have on our financial position and results of operations.

In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes - Balance Sheet Classification of Deferred Taxes.” The new update will simplify the presentation of deferred income taxes and will require deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The classification shall be made at the tax-paying component level of an entity, after reflecting any offset of deferred tax liabilities, deferred tax assets and any related valuation allowances. Public business entities should apply the guidance in ASU 2015-17 for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application for public entities is permitted. The amendments can be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. We are currently evaluating the provisions of ASU 2015-17.

In June 2014, the FASB issued ASU 2014-10, “Development Stage Entities (Topic 915).” The new standard removes the definition of a development stage entity from the Master Glossary of Accounting Standard Codification and the related financial reporting requirements specific to development stage entities. This ASU is intended to reduce cost and complexity of financial reporting for entities that have not commenced planned principal operations. For financial reporting requirements other than the VIE guidance in ASC Topic 810, “Consolidation,” ASU 2014-10 was effective for annual and quarterly reporting periods of public entities beginning after December 15, 2014. For the financial reporting requirements related to VIEs in ASC Topic 810, “Consolidation,” ASU 2014-10 is effective for annual and quarterly reporting periods of public entities beginning after December 15, 2015. Early application for public entities is permitted. We are currently evaluating the provisions of ASU 2014-10. Our preliminary assessment indicates that additional disclosures related to VIEs may be required for our joint ventures if the planned principal operations have not commenced.

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. In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The amendment in this ASU defers the effective date of ASU 2014-09 for all entities for one year. Public business entities should apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier adoption is permitted only as of annual reporting periods beginning after December 31, 2016, including interim reporting periods within that reporting period. Retrospective or modified retrospective application of the accounting standard is required. 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. As part of our assessment work to-date, we have formed an implementation work team, completed training of the new ASU’s revenue recognition model and begun contract review and documentation.

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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, exposing our revenues, purchases, cost of operating activities, and cash flows to fluctuations in the prices for these commodities. Generally, our policy is to remain exposed to the market prices of commodities. Consistent with this policy, our Commercial organization uses derivative contracts to effectively convert our exposure from fixed-price sales contracts, often requested by refined product customers, back to fluctuating market prices. Conversely, our Commercial organization also uses futures, forwards, swaps and options in various markets to accomplish the following objectives to optimize the value of our supply chain, and this may reduce our exposure to fluctuations in market prices:


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


•	Manage the risk to our cash flows from price exposures on specific crude oil, refined product, natural gas, NGL, and electric power transactions.


•	Enable us to use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades. Derivatives may be utilized to optimize these activities.

We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of adverse changes in market conditions on the derivative financial instruments and derivative commodity instruments held or issued, including commodity purchase and sales contracts recorded on the balance sheet at December 31, 2015, 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, 2015 and 2014, was immaterial to our cash flows and net income.

The VaR for instruments held for purposes other than trading at December 31, 2015 and 2014, was also immaterial to our cash flows and net income.

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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 2015
2016	$	27	7.24	%	$	—	—	%
2017		1,529	3.03			—	—
2018		26	7.18			12	0.01
2019		24	7.12			—	—
2020		319	2.90			12	0.01
Remaining years		6,800	4.79			26	0.01
Total	$	8,725			$	50
Fair value	$	8,434			$	50



	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

For additional information about our use of derivative instruments, see Note 16—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, petroleum products and natural gas prices and refining, marketing and petrochemical margins.


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


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


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


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


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


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


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


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


•	International monetary conditions and exchange controls.


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


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


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


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


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


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


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


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


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


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


•	Fluctuations in consumer demand for refined products.


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

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Index to Financial Statements

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PHILLIPS 66

INDEX TO FINANCIAL STATEMENTS



	Page

Report of Management	68

Reports of Independent Registered Public Accounting Firm	69

Consolidated Financial Statements of Phillips 66:

Consolidated Statement of Income for the years ended December 31, 2015, 2014 and 2013	71

Consolidated Statement of Comprehensive Income for the years ended December 31, 2015, 2014 and 2013	72

Consolidated Balance Sheet at December 31, 2015 and 2014	73

Consolidated Statement of Cash Flows for the years ended December 31, 2015, 2014 and 2013	74

Consolidated Statement of Changes in Equity for the years ended December 31, 2015, 2014 and 2013	75

Notes to Consolidated Financial Statements	77

Supplementary Information

Selected Quarterly Financial Data (Unaudited)	132

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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 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, 2015. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2013). Based on this assessment, management concluded the company’s internal control over financial reporting was effective as of December 31, 2015.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2015, and their report is included herein.




/s/ Greg C. Garland		/s/ Kevin J. Mitchell

Greg C. Garland		Kevin J. Mitchell
Chairman and		Executive Vice President, Finance and
Chief Executive Officer		Chief Financial Officer



February 19, 2016

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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, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, 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, 2015, 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 19, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 19, 2016

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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 Phillips 66’s internal control over financial reporting as of December 31, 2015, 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, 2015, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2015 consolidated financial statements of Phillips 66 and our report dated February 19, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 19, 2016

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Index to Financial Statements



Consolidated Statement of Income	Phillips 66



	Millions of Dollars
Years Ended December 31	2015		2014	2013
Revenues and Other Income
Sales and other operating revenues*	$	98,975	161,212	171,596
Equity in earnings of affiliates	1,573		2,466	3,073
Net gain on dispositions	283		295	55
Other income	118		120	85
Total Revenues and Other Income	100,949		164,093	174,809

Costs and Expenses
Purchased crude oil and products	73,399		135,748	148,245
Operating expenses	4,294		4,435	4,206
Selling, general and administrative expenses	1,670		1,663	1,478
Depreciation and amortization	1,078		995	947
Impairments	7		150	29
Taxes other than income taxes*	14,077		15,040	14,119
Accretion on discounted liabilities	21		24	24
Interest and debt expense	310		267	275
Foreign currency transaction (gains) losses	49		26	(40	)
Total Costs and Expenses	94,905		158,348	169,283
Income from continuing operations before income taxes	6,044		5,745	5,526
Provision for income taxes	1,764		1,654	1,844
Income from Continuing Operations	4,280		4,091	3,682
Income from discontinued operations**	—		706	61
Net income	4,280		4,797	3,743
Less: net income attributable to noncontrolling interests	53		35	17
Net Income Attributable to Phillips 66	$	4,227	4,762	3,726

Amounts Attributable to Phillips 66 Common Stockholders:
Income from continuing operations	$	4,227	4,056	3,665
Income from discontinued operations	—		706	61
Net Income Attributable to Phillips 66	$	4,227	4,762	3,726

Net Income Attributable to Phillips 66 Per Share of Common Stock (dollars)
Basic
Continuing operations	$	7.78	7.15	5.97
Discontinued operations	—		1.25	0.10
Net Income Attributable to Phillips 66 Per Share of Common Stock	$	7.78	8.40	6.07
Diluted
Continuing operations	$	7.73	7.10	5.92
Discontinued operations	—		1.23	0.10
Net Income Attributable to Phillips 66 Per Share of Common Stock	$	7.73	8.33	6.02

Dividends Paid Per Share of Common Stock (dollars)	$	2.1800	1.8900	1.3275

Average Common Shares Outstanding (in thousands)
Basic	542,355		565,902	612,918
Diluted	546,977		571,504	618,989
*Includes excise taxes on petroleum product sales:	$	13,780	14,698	13,866
**Net of provision for income taxes on discontinued operations:	$	—	5	34
See Notes to Consolidated Financial Statements.

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Consolidated Statement of Comprehensive Income	Phillips 66

	Millions of Dollars
Years Ended December 31	2015			2014		2013

Net Income	$	4,280		4,797		3,743
Other comprehensive income (loss)
Defined benefit plans
Actuarial gain/loss:
Actuarial gain (loss) arising during the period	(138		)	(451	)	401
Amortization to net income of net actuarial loss and settlements	174			56		96
Plans sponsored by equity affiliates	11			(66	)	88
Income taxes on defined benefit plans	(13		)	169		(211	)
Defined benefit plans, net of tax	34			(292	)	374
Foreign currency translation adjustments	(163		)	(294	)	(21	)
Income taxes on foreign currency translation adjustments	7			18		(2	)
Foreign currency translation adjustments, net of tax	(156		)	(276	)	(23	)
Hedging activities by equity affiliates	—			—		1
Income taxes on hedging activities by equity affiliates	—			—		(1	)
Hedging activities by equity affiliates, net of tax	—			—		—
Other Comprehensive Income (Loss), Net of Tax	(122		)	(568	)	351
Comprehensive Income	4,158			4,229		4,094
Less: comprehensive income attributable to noncontrolling interests	53			35		17
Comprehensive Income Attributable to Phillips 66	$	4,105		4,194		4,077
See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet	Phillips 66

	Millions of Dollars
At December 31	2015			2014
Assets
Cash and cash equivalents	$	3,074		5,207
Accounts and notes receivable (net of allowances of $55 million in 2015 and $71 million in 2014)	4,411			6,306
Accounts and notes receivable—related parties	762			949
Inventories	3,477			3,397
Prepaid expenses and other current assets*	532			833
Total Current Assets	12,256			16,692
Investments and long-term receivables	12,143			10,189
Net properties, plants and equipment	19,721			17,346
Goodwill	3,275			3,274
Intangibles	906			900
Other assets*	279			291
Total Assets	$	48,580		48,692

Liabilities
Accounts payable	$	5,155		7,488
Accounts payable—related parties	500			576
Short-term debt	44			842
Accrued income and other taxes	878			878
Employee benefit obligations	576			462
Other accruals	378			848
Total Current Liabilities	7,531			11,094
Long-term debt*	8,843			7,793
Asset retirement obligations and accrued environmental costs	665			683
Deferred income taxes	6,041			5,491
Employee benefit obligations	1,285			1,305
Other liabilities and deferred credits	277			289
Total Liabilities	24,642			26,655

Equity
Common stock (2,500,000,000 shares authorized at $.01 par value) Issued (2015—639,336,287 shares; 2014—637,031,760 shares)
Par value	6			6
Capital in excess of par	19,145			19,040
Treasury stock (at cost: 2015—109,925,907 shares; 2014—90,649,984 shares)	(7,746		)	(6,234	)
Retained earnings	12,348			9,309
Accumulated other comprehensive loss	(653		)	(531	)
Total Stockholders’ Equity	23,100			21,590
Noncontrolling interests	838			447
Total Equity	23,938			22,037
Total Liabilities and Equity	$	48,580		48,692
*Prior period amounts have been retrospectively adjusted for Accounting Standards Update No. 2015-03.
See Notes to Consolidated Financial Statements.

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Consolidated Statement of Cash Flows	Phillips 66

	Millions of Dollars
Years Ended December 31	2015			2014		2013
Cash Flows From Operating Activities
Net income	$	4,280		4,797		3,743
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	1,078			995		947
Impairments	7			150		29
Accretion on discounted liabilities	21			24		24
Deferred taxes	529			(488	)	594
Undistributed equity earnings	185			197		(354	)
Net gain on dispositions	(283		)	(295	)	(55	)
Income from discontinued operations	—			(706	)	(61	)
Other	117			(127	)	195
Working capital adjustments
Decrease (increase) in accounts and notes receivable	2,129			2,226		481
Decrease (increase) in inventories	(144		)	(85	)	38
Decrease (increase) in prepaid expenses and other current assets	324			(316	)	20
Increase (decrease) in accounts payable	(2,300		)	(3,323	)	360
Increase (decrease) in taxes and other accruals	(230		)	478		(19	)
Net cash provided by continuing operating activities	5,713			3,527		5,942
Net cash provided by discontinued operations	—			2		85
Net Cash Provided by Operating Activities	5,713			3,529		6,027

Cash Flows From Investing Activities
Capital expenditures and investments	(5,764		)	(3,773	)	(1,779	)
Proceeds from asset dispositions*	70			1,244		1,214
Advances/loans—related parties	(50		)	(3	)	(65	)
Collection of advances/loans—related parties	50			—		165
Other	(44		)	238		48
Net cash used in continuing investing activities	(5,738		)	(2,294	)	(417	)
Net cash used in discontinued operations	—			(2	)	(27	)
Net Cash Used in Investing Activities	(5,738		)	(2,296	)	(444	)

Cash Flows From Financing Activities
Issuance of debt	1,169			2,487		—
Repayment of debt	(926		)	(49	)	(1,020	)
Issuance of common stock	(19		)	1		6
Repurchase of common stock	(1,512		)	(2,282	)	(2,246	)
Share exchange—PSPI transaction	—			(450	)	—
Dividends paid on common stock	(1,172		)	(1,062	)	(807	)
Distributions to noncontrolling interests	(46		)	(30	)	(10	)
Net proceeds from issuance of Phillips 66 Partners LP common units	384			—		404
Other	5			23		(6	)
Net cash used in continuing financing activities	(2,117		)	(1,362	)	(3,679	)
Net cash used in discontinued operations	—			—		—
Net Cash Used in Financing Activities	(2,117		)	(1,362	)	(3,679	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents	9			(64	)	22

Net Change in Cash and Cash Equivalents	(2,133		)	(193	)	1,926
Cash and cash equivalents at beginning of year	5,207			5,400		3,474
Cash and Cash Equivalents at End of Year	$	3,074		5,207		5,400
* Includes return of investments in equity affiliates and working capital true-ups on dispositions.
See Notes to Consolidated Financial Statements.

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Consolidated Statement of Changes in Equity											Phillips 66

	Millions of Dollars
	Attributable to Phillips 66
	Common Stock
	Par Value		Capital in Excess of Par		Treasury Stock		Retained Earnings		Accum. Other Comprehensive Income (Loss)		Noncontrolling Interests		Total

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
Net income	—		—		—		4,227		—		53		4,280
Other comprehensive loss	—		—		—		—		(122	)	—		(122	)
Cash dividends paid on common stock	—		—		—		(1,172	)	—		—		(1,172	)
Repurchase of common stock	—		—		(1,512	)	—		—		—		(1,512	)
Benefit plan activity	—		105		—		(16	)	—		—		89
Issuance of Phillips 66 Partners LP common units	—		—		—		—		—		384		384
Distributions to noncontrolling interests and other	—		—		—		—		—		(46	)	(46	)
December 31, 2015	$	6	19,145		(7,746	)	12,348		(653	)	838		23,938

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	Shares in Thousands
	Common Stock Issued	Treasury Stock
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
Repurchase of common stock	—	19,276
Shares issued—share-based compensation	2,304	—
December 31, 2015	639,336	109,926
See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements	Phillips 66

Note 1—Summary of Significant Accounting Policies

▪

Consolidation Principles and Investments—Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and variable interest entities 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.


▪	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 or nonrecurring costs or research and development costs. Materials and supplies inventories are valued using the weighted-average-cost method.

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▪

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 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 asset.

▪

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, the fair value of intangible assets is determined based upon the present values of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable.

▪

Goodwill—Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination. It is not amortized but is tested annually for impairment and when events or changes in circumstance indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, the implied fair value of goodwill is calculated. The excess, if any, of the book value over the implied fair value of the goodwill is charged to net income. 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

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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.

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—The 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 PP&E.

Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures relating to an existing condition caused by past operations, and those having no future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a 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—The fair value of a guarantee is determined and recorded as a liability at the time the guarantee is given. The initial liability is subsequently reduced as we are released from exposure under the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we have information indicating the liability 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

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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.

▪

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 not to 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—Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Interest related to unrecognized tax benefits is reflected in interest expense, and penalties in operating expenses.


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


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

Note 2—Changes in Accounting Principles

Effective December 1, 2015, we early adopted the Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30) - Simplifying the Presentation of Debt Issuance Costs” and ASU 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-15 states that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing these costs when they relate to a line-of-credit arrangement. Upon adoption, we reclassified $54 million and $49 million as a reduction of debt on our 2015 and 2014 consolidated balance sheets, respectively.

Note 3—Variable Interest Entities (VIEs)

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. We consolidate Phillips 66 Partners as we determined that Phillips 66 Partners is a VIE and we are the primary beneficiary. As general partner of Phillips 66 Partners, we have the ability to control its financial interests, as well as the ability to direct the activities of Phillips 66 Partners that most significantly impact its economic performance. See Note 27—Phillips 66 Partners LP, for additional information.

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

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 7—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.

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(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 and in September 2015, the petition was denied. In January 2016, PDVSA filed an appeal with the appellate court seeking to reverse this ruling. Until all legal challenges are 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 our separation from ConocoPhillips in 2012 (the Separation), we provided a 100 percent debt guarantee to the lender of MSLP’s 8.85% senior notes (MSLP Senior Notes). PDVSA did not participate in the debt guarantee. In our VIE assessment, this disproportionate debt guarantee, plus other liquidity support provided jointly by us and PDVSA independently of equity ownership, 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 being vacated, because under the partnership agreement, the co-venturers jointly direct the activities of MSLP that most significantly impact economic performance. At December 31, 2015, our maximum exposure to loss was the outstanding principal balance of the MSLP Senior Notes of $157 million and our investment in MSLP of $158 million.

We have a 50 percent ownership interest with a 50 percent governance interest in Excel Paralubes (Excel). In securing lender consents in connection with the Separation, ConocoPhillips provided a 50 percent debt guarantee to the lender of Excel’s 7.43% senior secured bonds (Excel Senior Bonds). We provided a full indemnity to ConocoPhillips for this debt guarantee. Our co-venturer did not participate in the debt guarantee. In November 2015, Excel repaid this debt and our guarantee was relieved. Also, liquidity support up to $60 million is provided jointly by us and our co-venturer independently of equity ownership. In our assessment, Excel is a VIE as this liquidity support 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, 2015, our maximum exposure to loss was half of the $60 million liquidity support, or $30 million, and our investment in Excel of $148 million.

Note 4—Inventories

Inventories at December 31 consisted of the following:



	Millions of Dollars
	2015		2014

Crude oil and petroleum products	$	3,214	3,141
Materials and supplies	263		256
	$	3,477	3,397

Inventories valued on the LIFO basis totaled $3,085 million and $3,004 million at December 31, 2015 and 2014, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $1,300 million and $3,000 million at December 31, 2015 and 2014, respectively.

During each of the three years ended December 31, 2015, certain reductions in inventory caused liquidations of LIFO inventory values. These liquidations decreased net income by approximately $37 million and $8 million in 2015 and 2014, respectively, and increased net income by approximately $109 million in 2013.

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Note 5—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 supplying utilities and other services to one of our refineries.

We funded each of these acquisitions with cash on hand. Total cash consideration paid in 2014 was $741 million, net of cash acquired. Cash consideration paid for acquisitions 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. Our acquisition accounting for these transactions is final and there were no material adjustments to the provisional amounts recorded in the twelve-month period ended December 31, 2015.

Note 6—Assets Held for Sale or Sold

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 July 2014, we entered into an agreement to sell the Bantry Bay terminal in Ireland, which was included in our Refining segment. Accordingly, the net assets of the terminal were classified as held for sale, which resulted in a before-tax impairment of $12 million from the reduction of the carrying value of the long-lived assets to estimated fair value less costs to sell. As of December 31, 2014, long-lived assets of $77 million were recorded in the “Prepaid expenses and other current assets” line of our consolidated balance sheet. In addition, an immaterial amount of long-term liabilities was recorded in the “Other accruals” line of our consolidated balance sheet. In February 2015, we completed the sale of the terminal. At the time of the disposition, the terminal had a net carrying value of $68 million, which primarily related to net PP&E. An immaterial gain was recognized on this disposition.

In February 2014, we exchanged 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 another party. The PSPI share exchange resulted 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. Revenues, income before tax and net income from discontinued operations, excluding the recognized before-tax gain of $696 million at closing, were not material for the years ended December 31, 2014 and 2013.

In July 2013, we completed the sale of the Immingham Combined Heat and Power Plant (ICHP), which was included in our M&S segment. A gain on this disposal was deferred at the time of the sale due to an indemnity provided to the buyer. We recognized the deferred gain into earnings as our exposure under the indemnity declined, beginning in the third quarter of 2014 and ending in the second quarter of 2015 when the indemnity expired. We recognized $242 million and $126 million of the deferred gain during the years ended December 31, 2015 and 2014, respectively.

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In May 2013, we sold our E-Gas™ Technology business which was included in our M&S segment. A $48 million before-tax gain was recognized during 2013 from this disposition.

Note 7—Investments, Loans and Long-Term Receivables

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



	Millions of Dollars
	2015		2014

Equity investments	$	11,977	10,035
Long-term receivables	84		76
Other investments	82		78
	$	12,143	10,189

Equity Investments

Affiliated companies in which we had a significant equity investment at December 31, 2015, included:


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


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


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


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


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


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

•

Dakota Access LLC (DAPL)/Energy Transfer Crude Oil Company, LLC (ETCOP)—two 25 percent owned joint ventures with Energy Transfer Equity L.P. and Energy Transfer Partners L.P. (collectively “Energy Transfer”). DAPL is constructing a crude oil pipeline system from the Bakken/Three Forks production area in North Dakota to Patoka, Illinois, and ETCOP is constructing a crude oil pipeline system from Patoka to Nederland, Texas.

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



	Millions of Dollars
	2015		2014	2013

Revenues	$	33,126	57,979	59,500
Income before income taxes	3,180		4,791	5,975
Net income	3,158		4,700	5,838
Current assets	6,024		7,402	9,865
Noncurrent assets	46,047		41,271	40,188
Current liabilities	4,130		6,854	7,971
Noncurrent liabilities	11,493		9,736	9,959

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, 2015, retained earnings included $1,444 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $1,769 million, $3,305 million, and $2,752 million in 2015, 2014 and 2013, respectively.

WRB

WRB’s operating assets consist of the Wood River and Borger refineries, located in Roxana, Illinois, and Borger, Texas, respectively, for which we are the operator and managing partner. As a result of our contribution of these two assets to WRB, a basis difference was created because the fair value of the contributed assets recorded by WRB exceeded their historical book value. The difference is primarily amortized and recognized as a benefit evenly over a period of 26 years, which was the estimated remaining useful life of the refineries’ PP&E at the closing date. At December 31, 2015, the book value of our investment in WRB was $1,967 million, and the basis difference was $3,155 million. Equity earnings in 2015, 2014 and 2013 were increased by $218 million, $184 million, and $185 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 supply agreements, the primary production commitment of which began a ratable wind-down period in December 2014 and expires in January 2019. This purchase commitment is on an “if-produced, will-purchase” basis. NGL is purchased under this agreement at various published market index prices, less transportation and fractionation fees.

The deferred gain of $156 million related to the sale of our interest in the Seaway Products Pipeline Company, now Southern Hills, to DCP Midstream began amortizing in 2013.

In 2015, we contributed $1,500 million in cash to DCP Midstream as a capital contribution. Our co-venturer contributed its interests in Sand Hills and Southern Hills as a capital contribution. Our ownership percentage in DCP Midstream remained unchanged.

At December 31, 2015, the book value of our investment in DCP Midstream was $2,293 million, and the basis difference was $56 million.

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CPChem

CPChem manufactures and markets petrochemicals and plastics. At December 31, 2015, the book value of our equity method investment in CPChem was $5,177 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. In April 2015, REX repaid $450 million of its debt, reducing its long-term debt to approximately $2.6 billion. REX funded the repayment through member cash contributions. Our 25 percent share was approximately $112 million, which we contributed to REX in April 2015. At December 31, 2015, the book value of our equity method investment in REX was $407 million.

Sand Hills

The Sand Hills pipeline is a fee-based pipeline that transports NGL from the Permian Basin and Eagle Ford Shale to facilities along the Texas Gulf Coast and the Mont Belvieu market hub. This investment was contributed to Phillips 66 Partners LP in March 2015 as discussed further in Note 27—Phillips 66 Partners LP. At December 31, 2015, the book value of our equity investment in Sand Hills was $431 million.

Southern Hills

The Southern Hills pipeline is a fee-based pipeline that transports NGL from the Midcontinent to facilities along the Texas Gulf Coast and the Mont Belvieu market hub. This investment was contributed to Phillips 66 Partners LP in March 2015 as discussed further in Note 27—Phillips 66 Partners LP. At December 31, 2015, the book value of our investment in Southern Hills was $213 million, and the basis difference was $98 million.

DAPL/ETCOP

In 2014, we formed two joint ventures to develop the DAPL and ETCOP pipelines. The DAPL pipeline will connect the Bakken/Three Forks production area in North Dakota to Patoka, Illinois, with the ETCOP pipeline. The ETCOP pipeline will provide crude oil transportation service from Patoka to storage terminals located in Nederland, Texas. The DAPL and ETCOP pipelines are expected to have capacities of 470,000 and 395,000 barrels per day, respectively, and will be interstate Federal Energy Regulatory Commission regulated pipelines. At December 31, 2015, the book values of our investments in DAPL and ETCOP were $317 million and $104 million, respectively.

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, and in September 2015, the petition was denied. In January 2016, PDVSA filed an appeal in the appellate court to vacate this 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 all legal challenges are resolved, 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

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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.

Note 8—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, pipeline assets over a 45-year life and terminal assets over a 33-year life. The company’s investment in PP&E, with the associated accumulated depreciation and amortization (Accum. D&A), at December 31 was:



	Millions of Dollars
	2015				2014
	Gross PP&E		Accum. D&A	Net PP&E	Gross PP&E	Accum. D&A	Net PP&E

Midstream	$	6,978	1,293	5,685	4,726	1,185	3,541
Chemicals	—		—	—	—	—	—
Refining	20,850		8,046	12,804	19,951	7,424	12,527
Marketing and Specialties	1,422		746	676	1,490	738	752
Corporate and Other	1,060		504	556	978	452	526
	$	30,310	10,589	19,721	27,145	9,799	17,346

Note 9—Goodwill and Intangibles

Goodwill

The carrying amount of goodwill was as follows:



	Millions of Dollars
	Midstream		Refining		Marketing and Specialties	Total

Balance at January 1, 2014	$	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
Goodwill assigned to asset acquisitions	—		—		1	1
Balance at December 31, 2015	$	623	1,813		839	3,275

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Intangible Assets

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



	Millions of Dollars
	Gross Carrying Amount
	2015		2014
Indefinite-Lived Intangible Assets
Trade names and trademarks	$	503	503
Refinery air and operating permits	266		239
Other	1		14
	$	770	756

At year-end 2015, the net book value of our amortized intangible assets was $136 million, which included accumulated amortization of $135 million, compared with $144 million and $132 million, respectively, at year-end 2014. See Note 5—Business Combinations for more information on intangible assets acquired in business acquisitions. Amortization expense was not material for 2015 and 2014, and is not expected to be material in future years.

Note 10—Impairments

During 2015, 2014 and 2013, we recognized the following before-tax impairment charges:



	Millions of Dollars
	2015		2014	2013

Midstream	$	1	—	1
Refining	3		147	3
Marketing and Specialties	3		3	16
Corporate and Other	—		—	9
	$	7	150	29

2015

During the year ended December 31, 2015, there were no significant impairments.

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 6—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.

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Note 11—Asset Retirement Obligations and Accrued Environmental Costs

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



	Millions of Dollars
	2015			2014

Asset retirement obligations	$	251		279
Accrued environmental costs	485			496
Total asset retirement obligations and accrued environmental costs	736			775
Asset retirement obligations and accrued environmental costs due within one year*	(71		)	(92	)
Long-term asset retirement obligations and accrued environmental costs	$	665		683

*Classified as a current liability on the consolidated 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 2015 and 2014, our overall asset retirement obligation changed as follows:



	Millions of Dollars
	2015			2014

Balance at January 1	$	279		309
Accretion of discount	9			11
New obligations	—			2
Changes in estimates of existing obligations	(7		)	(16	)
Spending on existing obligations	(20		)	(17	)
Property dispositions	(2		)	(1	)
Foreign currency translation	(8		)	(9	)
Balance at December 31	$	251		279

Accrued Environmental Costs

Total accrued environmental costs at December 31, 2015 and 2014, were $485 million and $496 million, respectively. The 2015 decrease in total accrued environmental costs is due to payments and settlements exceeding new accruals, accrual adjustments and accretion during the year.

We had accrued environmental costs at December 31, 2015 and 2014, of $270 million and $268 million, respectively, primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations; $168 million and $178 million, respectively, associated with nonoperator sites; and $47 million and $50 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 $246 million at December 31, 2015. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $25 million in 2016, $24 million in 2017, $21 million in 2018, $20 million in 2019, $24 million in 2020, and $200 million for all future years after 2020.

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Note 12—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.



	2015				2014			2013
	Basic			Diluted	Basic		Diluted	Basic		Diluted
Amounts Attributed to Phillips 66 Common Stockholders (millions):
Income from continuing operations attributable to Phillips 66	$	4,227		4,227	4,056		4,056	3,665		3,665
Income allocated to participating securities	(6		)	—	(7	)	—	(5	)	—
Income from continuing operations available to common stockholders	4,221			4,227	4,049		4,056	3,660		3,665
Discontinued operations	—			—	706		706	61		61
Net income available to common stockholders	$	4,221		4,227	4,755		4,762	3,721		3,726

Weighted-average common shares outstanding (thousands):	537,602			542,355	561,859		565,902	608,983		612,918
Effect of stock-based compensation	4,753			4,622	4,043		5,602	3,935		6,071
Weighted-average common shares outstanding—EPS	542,355			546,977	565,902		571,504	612,918		618,989

Earnings Per Share of Common Stock (dollars):
Income from continuing operations attributable to Phillips 66	$	7.78		7.73	7.15		7.10	5.97		5.92
Discontinued operations	—			—	1.25		1.23	0.10		0.10
Earnings Per Share	$	7.78		7.73	8.40		8.33	6.07		6.02

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Note 13—Debt

Long-term debt at December 31 was:



	Millions of Dollars
	2015			2014

1.95% Senior Notes due 2015	$	—		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			1,000
4.875% Senior Notes due 2044	1,500			1,500
5.875% Senior Notes due 2042	1,500			1,500
Phillips 66 Partners 2.646% Senior Notes due 2020	300			—
Phillips 66 Partners 3.605% Senior Notes due 2025	500			—
Phillips 66 Partners 4.680% Senior Notes due 2045	300			—
Industrial Development Bonds due 2018 through 2021 at 0.01% at year-end 2015 and 0.02%-0.05% at year-end 2014	50			50
Sweeny Cogeneration, L.P. notes due 2020 at 7.54%	41			53
Note payable to Merey Sweeny, L.P. due 2020 at 7% (related party)	83			97
Phillips 66 Partners revolving credit facility due 2019 at 1.33% at year-end 2014	—			18
Other	1			1
Debt at face value	8,775			8,519
Capitalized leases	208			210
Net unamortized discounts and debt issuance costs	(96		)	(94	)
Total debt	8,887			8,635
Short-term debt	(44		)	(842	)
Long-term debt	$	8,843		7,793

Maturities of long-term borrowings, inclusive of net unamortized discounts and debt issuance costs, for each of the years from 2016 through 2020 are $44 million, $1,545 million, $51 million, $37 million and $337 million, respectively.

Debt Issuance

In February 2015, Phillips 66 Partners closed on a public offering of $1.1 billion aggregate principal amount of unsecured senior notes, consisting of:


•	$300 million of 2.646% Senior Notes due 2020.


•	$500 million of 3.605% Senior Notes due 2025.


•	$300 million of 4.680% Senior Notes due 2045.

Phillips 66 Partners utilized a portion of the net proceeds to fund part of the purchase price for its acquisition of our equity interests in Sand Hills, Southern Hills and Explorer Pipeline Company (Explorer). The remaining proceeds were used to repay existing borrowings from a subsidiary of Phillips 66, fund capital expenditures and for general partnership purposes. See Note 27—Phillips 66 Partners LP, for additional information.

Credit Facilities and Commercial Paper

Phillips 66 has a $5 billion revolving credit facility that extends until December 2019. This facility may be used for direct bank borrowings, as support for issuances of letters of credit, or as support for our commercial paper program. The facility is with a broad syndicate of financial institutions and contains covenants that we consider usual and customary for an agreement of this type for comparable commercial borrowers, including a maximum consolidated net debt-to-

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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 Ratings Services and Moody’s Investors Service. The facility also provides for customary fees, including administrative agent fees and commitment fees. As of December 31, 2015, no amount had been directly drawn under this revolving credit agreement, while $51 million in letters of credit had been issued that were supported by it. As a result, we ended 2015 with $4.9 billion of capacity under this facility.

Note 14—Guarantees

At December 31, 2015, 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 MSLP Senior Notes issued in July 1999. At December 31, 2015, the maximum potential amount of future payments to third parties under the guarantee was estimated to be $157 million, which could become payable if MSLP fails to meet its obligations under the senior notes agreement. The MSLP Senior Notes mature in 2019.

Other Guarantees

We have residual value guarantees associated with leases with maximum future potential payments totaling $389 million. We have other guarantees with maximum future potential payment amounts totaling $117 million, which consist primarily of guarantees to fund the short-term cash liquidity deficits of certain joint ventures and guarantees of the lease payment obligations of a joint venture. These guarantees generally extend up to 9 years or 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, 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 with generally indefinite terms, and the maximum amount of future payments is generally unlimited. The carrying amount recorded for indemnifications at December 31, 2015, was $198 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 estimate of the maximum potential amount of future payments. Included in the recorded carrying amount were $98 million of environmental accruals for known contamination that were primarily included in “Asset retirement obligations and accrued environmental costs” at December 31, 2015. For additional information about environmental liabilities, see Note 15—Contingencies and Commitments.

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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 15—Contingencies and Commitments

Environmental

We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information available at the time. We measure estimates and base 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 alleged to have liability at a particular site. Due to such joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar and time limits.

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We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those pertaining to sites acquired in a 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 11—Asset Retirement Obligations and Accrued Environmental Costs, for a summary of our accrued environmental liabilities.

Legal Proceedings

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases and enables the tracking of those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.

Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized.

At December 31, 2015, we had performance obligations secured by letters of credit and bank guarantees of $308 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 third-party financing arrangements. The agreements typically provide for crude oil transportation to be used in the ordinary course of our business. The aggregate amounts of estimated payments under these various agreements are $312 million annually for each of the years from 2016 through 2020 and $3,147 million in the aggregate for years 2021 and thereafter. Total payments under the agreements were $328 million in 2015, $331 million in 2014 and $345 million in 2013.

Note 16—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. Because we have not used 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 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

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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 17—Fair Value Measurements.

Commodity Derivative Contracts—We sell into or receive supply from the worldwide crude oil, refined products, natural gas, NGL, and electric power markets, exposing our revenues, purchases, cost of operating activities, and cash flows to fluctuations in the prices for these commodities. Generally, our policy is to remain exposed to the market prices of commodities; however, we use futures, forwards, swaps and options in various markets to balance physical systems, meet customer needs, manage price exposures on specific transactions, and do a limited, immaterial amount of trading not directly related to our physical business, all of which may reduce our exposure to fluctuations in market prices. We also use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades.

The following table indicates the 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 17—Fair Value Measurements.



	Millions of Dollars
	2015		2014
Assets
Accounts and notes receivable	$	—	(1	)
Prepaid expenses and other current assets	2,607		3,839
Other assets	5		29
Liabilities
Other accruals	2,425		3,472
Other liabilities and deferred credits	5		1

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

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



	Millions of Dollars
	2015		2014	2013

Sales and other operating revenues	$	162	658	17
Equity in earnings of affiliates	—		66	(19	)
Other income	58		20	3
Purchased crude oil and products	121		136	95

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, 2015 and 2014.



	Open Position Long / (Short)
	2015		2014
Commodity
Crude oil, refined products and NGL (millions of barrels)	(17	)	(11	)

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 to us.

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

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, 2015 or 2014.

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Note 17—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.


•	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 Intercontinental Exchange, 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 either with: (1) adjusted quoted prices from an active market for similar assets or liabilities; or (2) other valuation inputs that are directly or indirectly observable.


•	Level 3: Fair value measured with unobservable inputs that are significant to the measurement.

We classify the fair value of an asset or liability based on the 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. For the year ended December 31, 2015, derivative assets with an aggregate value of $502 million and derivative liabilities with an aggregate value of $512 million were transferred into Level 1, as measured from the beginning of the reporting period. The measurements were reclassified within the fair value hierarchy due to the availability of unadjusted quoted prices from an active market.

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 quotes provided by brokers and price index developers such as Platts and Oil Price Information Service. We corroborate these quotes with market data and classify the resulting fair values as Level 2. 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

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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.

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 agreements for all of our exchange-cleared derivative instruments, the majority of our OTC derivative instruments, and certain physical commodity forward contracts (primarily pipeline crude oil deliveries). The following tables show the fair value 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 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, 2015
	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	$	1,851	703	—	2,554	(2,389	)	(100	)	—	65	—
OTC instruments	—		13	—	13	(12	)	—		—	1	—
Physical forward contracts*	3		40	2	45	—		—		—	45	—
Rabbi trust assets	83		—	—	83	N/A		N/A		—	83	N/A
	$	1,937	756	2	2,695	(2,401	)	(100	)	—	194

Commodity Derivative Liabilities
Exchange-cleared instruments	$	1,745	646	—	2,391	(2,389	)	—		—	2	—
OTC instruments	—		17	—	17	(12	)	—		—	5	—
Physical forward contracts*	—		22	—	22	—		—		—	22	—
Floating-rate debt	50		—	—	50	N/A		N/A		—	50	N/A
Fixed-rate debt, excluding capital leases**	—		8,434	—	8,434	N/A		N/A		195	8,629	N/A
	$	1,795	9,119	—	10,914	(2,401	)	—		195	8,708

*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, 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

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

The rabbi trust assets appear on our consolidated balance sheet in the “Investments and long-term receivables” line, while the floating-rate and fixed-rate debt appear in the “Short-term debt” and “Long-term debt” lines. For information regarding where our commodity derivative assets and liabilities appear on the balance sheet, see the first table in Note 16—Derivatives and Financial Instruments.

Nonrecurring Fair Value Remeasurements

During the year ended December 31, 2015, there were no significant nonrecurring fair value remeasurements of assets subsequent to their initial recognition.

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 year ended December 31, 2014:



	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 properties, plants and equipment (held for sale)	72		72	—	12

*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 6—Assets Held for Sale or Sold, for additional information.

Note 18—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, 2015 or 2014.

Treasury Stock

On October 9, 2015, our Board of Directors increased our current share repurchase authorization by $2 billion resulting in a total authorization of $4 billion. Since July 2012, our Board of Directors has authorized repurchases of our outstanding common stock totaling up to $9 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. 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, 2015, we have repurchased a total of 92,503,292 shares at a cost of $6.4 billion. Shares of stock repurchased are held as treasury shares.

Common Stock Dividends

On February 3, 2016, our Board of Directors declared a quarterly cash dividend of $0.56 per common share, payable March 1, 2016, to holders of record at the close of business on February 16, 2016.

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Note 19—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 $231 million and $203 million at December 31, 2015 and 2014, respectively.

Future minimum lease payments as of December 31, 2015, for operating and capital lease obligations were:



	Millions of Dollars
	Capital Lease Obligations		Operating Lease Obligations

2016	$	24	510
2017	25		418
2018	19		308
2019	18		234
2020	14		171
Remaining years	169		368
Total	269		2,009
Less: income from subleases	—		99
Net minimum lease payments	$	269	1,910
Less: amount representing interest	61
Capital lease obligations	$	208

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



	Millions of Dollars
	2015		2014	2013

Minimum rentals	$	641	570	572
Contingent rentals	6		8	7
Less: sublease rental income	136		135	133
	$	511	443	446

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Note 20—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
	2015					2014				2015		2014
	U.S.			Int’l.		U.S.		Int’l.
Change in Benefit Obligation
Benefit obligation at January 1	$	2,895		941		2,473		840		203		189
Service cost	124			38		121		38		7		7
Interest cost	109			28		108		35		7		8
Plan participant contributions	—			3		—		4		1		1
Actuarial loss (gain)	(25		)	(10	)	409		116		13		4
Benefits paid	(312		)	(20	)	(216	)	(18	)	(12	)	(6	)
Foreign currency exchange rate change	—			(68	)	—		(74	)	—		—
Benefit obligation at December 31*	$	2,791		912		2,895		941		219		203
*Accumulated benefit obligation portion of above at December 31:	$	2,485		712		2,553		729

Change in Fair Value of Plan Assets
Fair value of plan assets at January 1	$	2,124		724		2,008		645		—		—
Actual return on plan assets	(10		)	18		168		89		—		—
Company contributions	221			63		164		60		11		5
Plan participant contributions	—			3		—		4		1		1
Benefits paid	(312		)	(20	)	(216	)	(18	)	(12	)	(6	)
Foreign currency exchange rate change	—			(46	)	—		(56	)	—		—
Fair value of plan assets at December 31	$	2,023		742		2,124		724		—		—

Funded Status at December 31	$	(768	)	(170	)	(771	)	(217	)	(219	)	(203	)

Amounts recognized in the consolidated balance sheet for our pension and other postretirement benefit plans at December 31, 2015 and 2014, include:



	Millions of Dollars
	Pension Benefits									Other Benefits
	2015					2014				2015		2014
	U.S.			Int’l.		U.S.		Int’l.
Amounts Recognized in the Consolidated Balance Sheet at December 31
Noncurrent assets	$	—		20		—		13		—		—
Current liabilities	(10		)	—		(8	)	—		(10	)	(6	)
Noncurrent liabilities	(758		)	(190	)	(763	)	(230	)	(209	)	(197	)
Total recognized	$	(768	)	(170	)	(771	)	(217	)	(219	)	(203	)

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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
	2015				2014			2015		2014
	U.S.		Int’l.		U.S.	Int’l.

Unrecognized net actuarial loss (gain)	$	710	143		741	165		2		(13	)
Unrecognized prior service cost (credit)	6		(7	)	9	(9	)	(10	)	(12	)



	Millions of Dollars
	Pension Benefits									Other Benefits
	2015					2014				2015		2014
	U.S.			Int’l.		U.S.		Int’l.
Sources of Change in Other Comprehensive Income
Net gain (loss) arising during the period	$	(124	)	7		(382	)	(57	)	(14	)	(3	)
Amortization of (gain) loss and settlements included in income	155			15		40		12		(1	)	(2	)
Net change during the period	$	31		22		(342	)	(45	)	(15	)	(5	)

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

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 $3,005 million, $2,676 million, and $2,183 million, respectively, at December 31, 2015, and $3,189 million, $2,815 million, and $2,295 million, respectively, at December 31, 2014. For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and the accumulated benefit obligation were $137 million and $112 million, respectively, at December 31, 2015, and $107 million and $83 million, respectively, at December 31, 2014.

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The allocated benefit cost from Shared Plans, as well as the components of net periodic benefit cost associated with plans sponsored by us, for 2015, 2014 and 2013 is shown in the table below:



	Millions of Dollars
	Pension Benefits													Other Benefits
	2015					2014				2013				2015		2014		2013
	U.S.			Int’l.		U.S.		Int’l.		U.S.		Int’l.
Components of Net Periodic Benefit Cost
Service cost	$	124		38		121		38		125		36		7		7		8
Interest cost	109			28		108		35		91		31		7		8		7
Expected return on plan assets	(138		)	(37	)	(142	)	(37	)	(120	)	(29	)	—		—		—
Amortization of prior service cost (credit)	3			(1	)	3		(2	)	3		(1	)	(2	)	(1	)	(2	)
Recognized net actuarial loss (gain)	75			15		40		12		84		16		(1	)	(2	)	—
Settlements	80			—		—		—		—		—		—		—		—
Total net periodic benefit cost	$	253		43		130		46		183		53		11		12		13

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, 2015, that are expected to be amortized into net periodic benefit cost during 2016 are provided below:



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

Unrecognized net actuarial loss	$	72	14		—
Unrecognized prior service cost (credit)	3		(1	)	(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
	2015			2014		2015	2014
	U.S.		Int’l.	U.S.	Int’l.
Assumptions Used to Determine Benefit Obligations:
Discount rate	4.35	%	3.35	3.90	3.10	4.00	3.70
Rate of compensation increase	4.00		3.65	4.00	3.20	—	—

Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate	3.90	%	3.10	4.55	4.30	3.70	4.40
Expected return on plan assets	7.00		5.15	7.00	5.50	—	—
Rate of compensation increase	4.00		3.20	4.00	3.90	—	—

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. Since January 1, 2013, eligible employees have been able to utilize notional amounts credited to an account during their period of service with the company to pay all, or a portion, of their cost to participate in postretirement health insurance through the company. In general, employees hired after December 31, 2012, will not receive credits to an account, but will have unsubsidized access to health insurance through the plan. The cost of health insurance will be adjusted annually by the company’s actuary to reflect actual experience and expected health care cost trends. The measurement of the accumulated benefit obligation assumes a health care cost trend rate of 6.75 percent in 2016 that declines to 5.00 percent by 2023. A 1 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 based on quoted market prices.


•	Fair values of corporate 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.

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•	Fair values of mutual funds are valued based on quoted market prices, which represent the net asset value of shares held.


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


•	Fair values of insurance contracts are valued at the present value of the future benefit payments owed by the insurance company to the plans’ participants.


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


•	Fair values of investments in common/collective trusts are valued at net asset value (NAV) as determined by the issuer of each fund. Certain investments that are measured at fair value using the NAV value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy.

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



	Millions of Dollars
	U.S.					International
	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
2015
Equity Securities
U.S.	$	322	—	—	322	136	—	—	136
International	125		—	—	125	99	—	—	99
Mutual funds	—		—	—	—	—	—	—	—
Debt Securities
Government	—		—	—	—	144	—	—	144
Corporate	—		—	—	—	—	—	—	—
Mutual funds	41		—	—	41	—	—	—	—
Cash and cash equivalents	22		—	—	22	3	—	—	3
Insurance contracts	—		—	—	—	—	—	13	13
Real estate	—		—	—	—	—	—	6	6
Subtotal	510		—	—	510	382	—	19	401
Common/collective trusts measured at NAV:
Equity securities					855				168
Debt securities					658				171
Other receivables					—				2
Total	$	510	—	—	2,023	382	—	19	742

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	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
Mutual funds	—		—	—	—	5	—	—	5
Debt Securities
Government	—		32	—	32	141	—	—	141
Corporate	—		51	—	51	—	—	—	—
Mutual funds	—		—	—	—	2	—	—	2
Cash and cash equivalents	20		—	—	20	10	—	—	10
Insurance contracts	—		—	—	—	—	—	14	14
Real estate	—		—	—	—	—	—	7	7
Subtotal	471		83	—	554	432	—	21	453
Common/collective trusts measured at NAV:
Equity securities					920				110
Debt securities					648				161
Other receivables					2				—
Total	$	471	83	—	2,124	432	—	21	724

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 2016, we expect to contribute approximately $50 million to our U.S. pension plans and other postretirement benefit plans and $50 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.

2016	$	270	20	25
2017	261		22	27
2018	259		21	26
2019	267		24	25
2020	292		24	25
2021-2024	1,333		144	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. The total expense related to participants in the Savings Plan was $134 million, $112 million and $111 million in 2015, 2014 and 2013, respectively.

Share-Based Compensation Plans

In accordance with the Employee Matters Agreement related to the Separation, compensation awards based on ConocoPhillips stock and granted before April 30, 2012 (the Separation Date) were converted to compensation awards based on both ConocoPhillips and Phillips 66 stock if, on the Separation Date, the awards were: (1) options outstanding and exercisable; or (2) restricted stock or restricted stock units (RSUs) awarded for completed performance periods under the ConocoPhillips Performance Share Program. Phillips 66 restricted stock, RSUs, and options issued in this conversion became subject to the “Omnibus Stock and Performance Incentive Plan of Phillips 66” (the 2012 Plan) on the Separation Date, whether held by grantees working for the company or grantees that remained employees of ConocoPhillips. Some of these awards based on Phillips 66 stock and held by employees of ConocoPhillips are still outstanding and appear in the activity tables for the Stock Option and the Performance Share Programs presented later in this footnote.

In May 2013, shareholders approved the 2013 Omnibus Stock and Performance Incentive Plan of Phillips 66 (the P66 Omnibus Plan). Subsequent to this approval, all new share-based awards are granted under the P66 Omnibus Plan, which

authorizes the Human Resources and Compensation Committee 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 that may be issued under the P66 Omnibus Plan to settle share-based awards may not exceed 45 million.

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. We recognize share-based compensation expense over the shorter of: (1) the service period (i.e., the stated period of time required to earn the award); or (2) the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months as this is the minimum period of time required for an award not to be subject to forfeiture.

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 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 benefits for the years ended December 31 were as follows:



	Millions of Dollars
	2015			2014		2013

Share-based compensation expense	$	144		134		132
Tax benefit	(54		)	(50	)	(50	)

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

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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.

The following summarizes our stock option activity from January 1, 2015, to December 31, 2015:



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

Outstanding at January 1, 2015	5,843,555		$	35.26
Granted	675,300		74.14		$	18.84
Forfeited	(15,692	)	73.96
Exercised	(1,071,424	)	28.73				$	60
Expired or canceled	—		—
Outstanding at December 31, 2015	5,431,739		$	41.27

Vested at December 31, 2015	5,137,728		$	39.47			$	218

Exercisable at December 31, 2015	4,222,873		$	32.53			$	208

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, 2015, were 5.60 years and 4.96 years, respectively. During 2015, we received $31 million in cash and realized a tax benefit of $8 million from the exercise of options. At December 31, 2015, 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 21 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 2014, we granted options with a weighted-average grant-date fair value of $18.95 and employees exercised options with an aggregate intrinsic value of $89 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:



	2015		2014	2013
Assumptions used
Risk-free interest rate	1.60	%	1.96	1.18
Dividend yield	3.00	%	3.00	2.50
Volatility factor	34.17	%	34.97	35.47
Expected life (years)	6.66		6.23	6.23

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 RSU activity from January 1, 2015, to December 31, 2015:



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

Outstanding at January 1, 2015	3,646,916		$	46.83
Granted	970,268		74.09
Forfeited	(80,729	)	61.17
Issued	(1,401,840	)	34.99		$	107
Outstanding at December 31, 2015	3,134,615		$	60.19

Not Vested at December 31, 2015	1,874,062		$	60.99

At December 31, 2015, the remaining unrecognized compensation cost from the unvested RSU awards held by employees of Phillips 66 was $46 million, which will be recognized over a weighted-average period of 20 months, the longest period being 35 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 2014, we granted RSUs with a weighted-average grant-date fair value of $73.28 and issued shares with an aggregate fair value of $116 million to settle RSUs.

Performance Share Program

Under the P66 Omnibus Plan, we also annually grant to senior management restricted performance share units (PSUs) that vest: (1) 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 (2) 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 (3) 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, 2015, to December 31, 2015:



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

Outstanding at January 1, 2015	3,171,860		$	43.96
Granted	838,710		74.14
Forfeited	—		—
Issued	(453,744	)	51.48		$	37
Outstanding at December 31, 2015	3,556,826		$	50.11

Not Vested at December 31, 2015	602,428		$	51.80

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

At December 31, 2015, the remaining unrecognized compensation cost from unvested PSU awards held by employees of Phillips 66 was $15 million, which will be recognized over a weighted-average period of 36 months, the longest period being 11 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 2014, we granted PSUs with a weighted-average grant-date fair value of $72.26 and issued shares with an aggregate fair value of $13 million to settle PSUs.

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Note 21—Income Taxes

Income taxes charged to income were:



	Millions of Dollars
	2015			2014		2013
Income Taxes
Federal
Current	$	1,128		1,661		1,054
Deferred	444			(378	)	526
Foreign
Current	(74		)	22		98
Deferred	42			80		(48	)
State and local
Current	227			274		146
Deferred	(3		)	(5	)	68
	$	1,764		1,654		1,844

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
	2015		2014
Deferred Tax Liabilities
Properties, plants and equipment, and intangibles	$	4,361	3,799
Investment in joint ventures	2,292		2,331
Investment in subsidiaries	236		115
Inventory	176		152
Other	24		29
Total deferred tax liabilities	7,089		6,426
Deferred Tax Assets
Benefit plan accruals	751		647
Asset retirement obligations and accrued environmental costs	215		207
Other financial accruals and deferrals	175		131
Loss and credit carryforwards	227		149
Other	1		2
Total deferred tax assets	1,369		1,136
Less: valuation allowance	160		107
Net deferred tax assets	1,209		1,029
Net deferred tax liabilities	$	5,880	5,397

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 2015, valuation allowances increased by a total of $53 million. This increase was primarily related to valuation allowances re-established for deferred tax assets that were reinstated in conjunction with German tax legislation enacted in 2015. The German tax legislation reinstated net operating loss and interest deduction carryforwards

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attributable to pre-Separation tax periods. The deferred tax asset associated with the interest deduction carryforward will not, more likely than not, be realized. Based on our historical taxable income, expectations for the future, and available tax-planning strategies, management expects the remaining net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and the tax consequences of future taxable income.

As of December 31, 2015, we had undistributed earnings related to foreign subsidiaries and foreign corporate joint ventures of approximately $2.8 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.

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
	2015			2014		2013

Balance at January 1	$	142		202		158
Additions based on tax positions related to the current year	—			13		30
Additions for tax positions of prior years	6			14		25
Reductions for tax positions of prior years	(17		)	(68	)	(8	)
Settlements	(49		)	(19	)	(3	)
Lapse of statute	—			—		—
Balance at December 31	$	82		142		202

Included in the balance of unrecognized tax benefits for 2015, 2014 and 2013 were $34 million, $98 million and $161 million, respectively, which, if recognized, would affect our effective tax rate. With respect to various unrecognized tax benefits and the related accrued liability, approximately $20 million may be recognized or paid within the next twelve months due to completion of audits.

At December 31, 2015, 2014 and 2013, accrued liabilities for interest and penalties totaled $19 million, $16 million and $18 million, respectively, net of accrued income taxes. Interest and penalties increased earnings by $3 million in 2015, had no impact on earnings during 2014 and decreased earnings by $3 million in 2013.

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
	2015			2014		2013		2015		2014		2013
Income from continuing operations before income taxes
United States	$	4,983		5,121		5,158		82.4	%	89.1		93.3
Foreign	1,061			624		368		17.6		10.9		6.7
	$	6,044		5,745		5,526		100.0	%	100.0		100.0

Federal statutory income tax	$	2,115		2,011		1,934		35.0	%	35.0		35.0
Goodwill allocated to assets sold	41			18		—		0.7		0.3
Sale of foreign subsidiaries	(125		)	(293	)	—		(2.1	)	(5.1	)
Foreign rate differential	(239		)	(184	)	(198	)	(3.9	)	(3.2	)	(3.6	)
German tax legislation	(103		)	—		—		(1.7	)
Federal manufacturing deduction	(77		)	(81	)	(68	)	(1.3	)	(1.4	)	(1.2	)
State income tax, net of federal benefit	150			180		139		2.5		3.1		2.5
Other	2			3		37				0.1		0.7
	$	1,764		1,654		1,844		29.2	%	28.8		33.4

Included in the line item “Sale of foreign subsidiaries” is a $224 million tax benefit attributable to the realization of excess tax basis during the fourth quarter of 2014 resulting from the sale of MRC and a $72 million benefit realized in 2015 attributable to the nontaxable gain from the sale of ICHP.

Income tax benefits of $34 million, $37 million and $34 million for the years 2015, 2014 and 2013, respectively, are reflected in the “Capital in Excess of Par” column of the consolidated statement of equity.

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Note 22—Accumulated Other Comprehensive Income (Loss)

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



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

December 31, 2012	$	(778	)	466		(2	)	(314	)
Other comprehensive income (loss)	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	)
Other comprehensive income (loss) before reclassifications	(78		)	(156	)	—		(234	)
Amounts reclassified from accumulated other comprehensive income (loss)*
Amortization of defined benefit plan items**
Actuarial losses and settlements	112			—		—		112
Net current period other comprehensive income (loss)	34			(156	)	—		(122	)
December 31, 2015	$	(662	)	11		(2	)	(653	)

*See Consolidated Statement of Changes in Equity.

**Included in the computation of net periodic benefit cost. See Note 20—Employee Benefit Plans, for additional information.

Note 23—Cash Flow Information



	Millions of Dollars
	2015		2014	2013
Noncash Investing and Financing Activities
Increase in net PP&E and debt related to capital lease obligation	$	31	33	177

Cash Payments
Interest	$	275	238	259
Income taxes	1,560		2,185	1,021

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PSPI Noncash Stock Exchange

As discussed more fully in Note 6—Assets Held for Sale or Sold, in February 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.

Note 24—Other Financial Information



	Millions of Dollars
	2015			2014		2013
Interest and Debt Expense
Incurred
Debt	$	389		265		251
Other	27			22		24
	416			287		275
Capitalized	(106		)	(20	)	—
Expensed	$	310		267		275

Other Income
Interest income	$	27		21		20
Other, net*	91			99		65
	$	118		120		85
*Includes derivatives-related activities.

Research and Development Expenditures—expensed	$	65		62		69

Advertising Expenses	$	73		70		68

Foreign Currency Transaction (Gains) Losses—after-tax
Midstream	$	—		—		—
Chemicals	—			—		—
Refining	34			6		(41	)
Marketing and Specialties	4			8		(5	)
Corporate and Other	—			—		2
	$	38		14		(44	)

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Note 25—Related Party Transactions

Significant transactions with related parties were:



	Millions of Dollars
	2015		2014	2013

Operating revenues and other income (a)	$	2,452	6,514	7,907
Purchases (b)	8,142		15,647	18,320
Operating expenses and selling, general and administrative expenses (c)	129		133	109
Net interest expense (d)	6		7	8

In December 2014, we completed the sale of our interest in MRC. Accordingly, sales of crude oil to MRC and purchases of refined products from MRC are only included in the 2014 and 2013 periods in the table above.

(a)

NGL and other petrochemical feedstocks, along with solvents, were sold to CPChem; and gas oil and hydrogen feedstocks were sold to Excel. Certain feedstocks and intermediate products were sold to WRB. We also acted as agent for WRB in supplying crude oil and other feedstocks for a fee. In addition, we charged several of our affiliates, including CPChem and MSLP, for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.

(b)

We purchased crude oil and refined products from WRB. We also acted as agent for WRB in distributing asphalt and solvents for a fee. We purchased natural gas and NGL from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We paid NGL fractionation fees to CPChem. 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 7—Investments, Loans and Long-Term Receivables and Note 13—Debt, for additional information on loans with affiliated companies.

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Note 26—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 terminaling and storage services for crude and petroleum products. The Midstream segment includes our master limited partnership, Phillips 66 Partners LP, as well as our 50 percent equity investment in DCP Midstream.


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.

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Analysis of Results by Operating Segment



	Millions of Dollars
	2015			2014		2013
Sales and Other Operating Revenues
Midstream
Total sales	$	3,676		6,222		6,575
Intersegment eliminations	(1,034		)	(1,104	)	(933	)
Total Midstream	2,642			5,118		5,642
Chemicals	5			7		9
Refining
Total sales	63,470			115,326		124,480
Intersegment eliminations	(40,317		)	(68,263	)	(72,503	)
Total Refining	23,153			47,063		51,977
Marketing and Specialties
Total sales	74,591			110,540		115,405
Intersegment eliminations	(1,446		)	(1,548	)	(1,467	)
Total Marketing and Specialties	73,145			108,992		113,938
Corporate and Other	30			32		30
Consolidated sales and other operating revenues	$	98,975		161,212		171,596

Depreciation, Amortization and Impairments
Midstream	$	128		92		89
Chemicals	—			—		—
Refining	741			850		688
Marketing and Specialties	100			97		119
Corporate and Other	116			106		80
Consolidated depreciation, amortization and impairments	$	1,085		1,145		976

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	Millions of Dollars
	2015			2014		2013
Equity in Earnings of Affiliates
Midstream	$	(268	)	360		436
Chemicals	1,316			1,634		1,362
Refining	325			311		1,107
Marketing and Specialties	207			162		169
Corporate and Other	(7		)	(1	)	(1	)
Consolidated equity in earnings of affiliates	$	1,573		2,466		3,073

Income Taxes from Continuing Operations
Midstream	$	73		310		264
Chemicals	353			495		375
Refining	1,104			696		1,035
Marketing and Specialties	466			440		433
Corporate and Other	(232		)	(287	)	(263	)
Consolidated income taxes from continuing operations	$	1,764		1,654		1,844

Net Income Attributable to Phillips 66
Midstream	$	13		507		469
Chemicals	962			1,137		986
Refining	2,555			1,771		1,747
Marketing and Specialties	1,187			1,034		894
Corporate and Other	(490		)	(393	)	(431	)
Discontinued Operations	—			706		61
Consolidated net income attributable to Phillips 66	$	4,227		4,762		3,726

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	Millions of Dollars
	2015		2014	2013
Investments In and Advances To Affiliates
Midstream	$	4,198	2,461	2,328
Chemicals	5,177		5,183	4,241
Refining	2,262		2,103	4,192
Marketing and Specialties	342		290	318
Corporate and Other	1		1	1
Consolidated investments in and advances to affiliates	$	11,980	10,038	11,080

Total Assets
Midstream	$	11,043	7,295	5,485
Chemicals	5,237		5,209	4,377
Refining	21,993		22,808	26,046
Marketing and Specialties	5,631		7,051	7,331
Corporate and Other*	4,676		6,329	6,319
Discontinued Operations**	—		—	211
Consolidated total assets	$	48,580	48,692	49,769
*Prior period amounts have been retrospectively adjusted for Accounting Standards Update No. 2015-03.
**In December 2013, $117 million of goodwill was allocated to assets held for sale in association with the planned disposition of PSPI.

Capital Expenditures and Investments
Midstream	$	4,457	2,173	597
Chemicals	—		—	—
Refining	1,069		1,038	820
Marketing and Specialties	122		439	226
Corporate and Other	116		123	136
Consolidated capital expenditures and investments	$	5,764	3,773	1,779

Interest Income and Expense
Interest income
Marketing and Specialties	$	2	—	—
Corporate and Other	25		21	20
Consolidated interest income	$	27	21	20

Interest and debt expense
Corporate and Other	$	310	267	275



Sales and Other Operating Revenues by Product Line
Refined products	$	86,249	133,625	140,488
Crude oil resales	8,993		19,832	22,777
NGL	2,998		6,447	7,431
Other	735		1,308	900
Consolidated sales and other operating revenues by product line	$	98,975	161,212	171,596

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Geographic Information



	Millions of Dollars
	Sales and Other Operating Revenues*				Long-Lived Assets**
	2015		2014	2013	2015	2014	2013

United States	$	69,578	110,713	115,378	29,624	25,255	23,641
United Kingdom	12,120		20,131	21,868	1,459	1,469	1,485
Germany	6,584		9,424	9,799	502	534	587
Other foreign countries	10,693		20,944	24,551	116	126	765
Worldwide consolidated	$	98,975	161,212	171,596	31,701	27,384	26,478

*Sales and other operating revenues are attributable to countries based on the location of the operations generating the revenues.

**Defined as net properties, plants and equipment plus investments in and advances to affiliated companies.

Note 27—Phillips 66 Partners LP

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. 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.

Current Year Activities

In February 2015, Phillips 66 Partners completed a public offering of 5,250,000 common units representing limited partner interests, at a public offering price of $75.50 per unit. The net proceeds received at closing were $384 million. Additionally, Phillips 66 Partners closed a public offering of $1.1 billion aggregate principal amount of senior notes. For additional information about the senior notes, see Note 13— Debt.

Effective March 2, 2015, we contributed our equity interests in Explorer (19.5 percent), Sand Hills (33.3 percent) and Southern Hills (33.3 percent) to Phillips 66 Partners. Total consideration paid was $1,010 million, which Phillips 66 Partners financed with $880 million in cash, funded by a portion of their proceeds from the public offering of common units and senior notes discussed above, and the issuance to us of 1,587,376 common units and 139,538 general partner units.

Effective December 1, 2015, we contributed to Phillips 66 Partners our 40 percent interest in Bayou Bridge Pipeline, LLC (Bayou Bridge), a joint venture in which Energy Transfer Partners L.P. and Sunoco Logistics Partners L.P. each hold a 30 percent interest, with Sunoco Logistics serving as the operator. Phillips 66 Partners financed the acquisition with a $35 million note payable to us that was immediately paid in full, and the issuance to us of 606,056 common units and 12,369 general partner units valued at $35 million, for an aggregate consideration of $70 million.

Ownership

At December 31, 2015, we owned a 69 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while the public owned a 29 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 equity investments of $945 million and net PP&E of $492 million at December 31, 2015. See Note 3—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 of $809 million and $415 million in our financial statements as of December 31, 2015, and 2014, respectively. Generally, contributions of assets by us to Phillips 66 Partners will eliminate in consolidation, except

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for third-party debt or equity offerings made by Phillips 66 Partners to finance such transactions. For the first contribution in 2015 together with the public offerings of common units and senior notes discussed above, our consolidated cash increased by $1.5 billion, consolidated debt increased by $1.1 billion and consolidated equity increased by $384 million as a result of the transactions. The Bayou Bridge contribution in 2015 discussed above did not impact our consolidated financial statements.

Recent Transactions

On February 17, 2016, we entered into a contribution agreement with Phillips 66 Partners under which Phillips 66 Partners will acquire a 25 percent interest in our wholly owned subsidiary, Phillips 66 Sweeny Frac LLC, which owns the Sweeny Fractionator One, an NGL fractionator located within our Sweeny Refinery complex in Old Ocean, Texas, and the Clemens Caverns, an NGL salt dome storage facility located near Brazoria, Texas. Total consideration for the transaction is expected to be $236 million, which will consist of Phillips 66 Partners’ issuance of common and general partner units to us, with an aggregate fair value of $24 million, and Phillips 66 Partners’ assumption of $212 million of notes payable to us. The transaction is expected to close in early March 2016.

Note 28—New Accounting Standards

In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments-Overall (Subtopic 825-10),” to meet its objective of providing more decision-useful information about financial instruments. The majority of this ASU’s provisions amend only the presentation or disclosures of financial instruments; however, one provision will also affect net income. Equity investments carried under the cost method or lower of cost or fair value method of accounting, in accordance with current generally accepted accounting principles, will have to be carried at fair value upon adoption of ASU 2016-01, with changes in fair value recorded in net income. For equity investments that do not have readily determinable fair values, a company may elect to carry such investments at cost less impairments, if any, adjusted up or down for price changes in similar financial instruments issued by the investee, when and if observed. Public business entities should apply the guidance in ASU 2016-01 for annual periods beginning after December 15, 2017, and interim periods within those annual periods, with early adoption prohibited. We are currently evaluating the provisions of ASU 2016-01 and assessing the impact, if any, it may have on our financial position and results of operations.

In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes-Balance Sheet Classification of Deferred Taxes.” The new update will simplify the presentation of deferred income taxes and will require deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The classification shall be made at the tax-paying component level of an entity, after reflecting any offset of deferred tax liabilities, deferred tax assets and any related valuation allowances. Public business entities should apply the guidance in ASU 2015-17 for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application for public entities is permitted. The amendments can be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. We are currently evaluating the provisions of ASU 2015-17.

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Date.” The amendment in this ASU defers the effective date of ASU 2014-09 for all entities for one year. Public business entities should apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier adoption is permitted only as of annual reporting periods beginning after December 31, 2016, including interim reporting periods within that reporting period. Retrospective or modified retrospective application of the accounting standard is required. 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. As part of our assessment work to-date, we have formed an implementation work team, completed training of the new ASU’s revenue recognition model and begun contract review and documentation.

Note 29—Condensed Consolidating Financial Information

Our $7.5 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.

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	Millions of Dollars
	Year Ended December 31, 2015
Statement of Income	Phillips 66			Phillips 66 Company		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—		68,478		30,497		—		98,975
Equity in earnings (losses) of affiliates	4,470			2,812		(134	)	(5,575	)	1,573
Net gain (loss) on dispositions	—			(115	)	398		—		283
Other income	—			81		37		—		118
Intercompany revenues	—			1,071		9,845		(10,916	)	—
Total Revenues and Other Income	4,470			72,327		40,643		(16,491	)	100,949

Costs and Expenses
Purchased crude oil and products	—			54,925		29,221		(10,747	)	73,399
Operating expenses	4			3,412		917		(39	)	4,294
Selling, general and administrative expenses	5			1,265		416		(16	)	1,670
Depreciation and amortization	—			818		260		—		1,078
Impairments	—			4		3		—		7
Taxes other than income taxes	—			5,505		8,572		—		14,077
Accretion on discounted liabilities	—			16		5		—		21
Interest and debt expense	365			25		34		(114	)	310
Foreign currency transaction losses	—			1		48		—		49
Total Costs and Expenses	374			65,971		39,476		(10,916	)	94,905
Income from continuing operations before income taxes	4,096			6,356		1,167		(5,575	)	6,044
Provision (benefit) for income taxes	(131		)	1,886		9		—		1,764
Income from Continuing Operations	4,227			4,470		1,158		(5,575	)	4,280
Income from discontinued operations	—			—		—		—		—
Net income	4,227			4,470		1,158		(5,575	)	4,280
Less: net income attributable to noncontrolling interests	—			—		53		—		53
Net Income Attributable to Phillips 66	$	4,227		4,470		1,105		(5,575	)	4,227

Comprehensive Income	$	4,105		4,348		1,032		(5,327	)	4,158

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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	—			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 gains	—			—		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
	At December 31, 2015
Balance Sheet	Phillips 66			Phillips 66 Company		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated
Assets
Cash and cash equivalents	$	—		575		2,499		—		3,074
Accounts and notes receivable	14			3,643		2,217		(701	)	5,173
Inventories	—			2,171		1,306		—		3,477
Prepaid expenses and other current assets	2			382		148		—		532
Total Current Assets	16			6,771		6,170		(701	)	12,256
Investments and long-term receivables	33,315			24,068		7,395		(52,635	)	12,143
Net properties, plants and equipment	—			12,651		7,070		—		19,721
Goodwill	—			3,040		235		—		3,275
Intangibles	—			726		180		—		906
Other assets	16			154		113		(4	)	279
Total Assets	$	33,347		47,410		21,163		(53,340	)	48,580

Liabilities and Equity
Accounts payable	$	—		4,015		2,341		(701	)	5,655
Short-term debt	—			25		19		—		44
Accrued income and other taxes	—			320		558		—		878
Employee benefit obligations	—			528		48		—		576
Other accruals	59			240		79		—		378
Total Current Liabilities	59			5,128		3,045		(701	)	7,531
Long-term debt	7,413			158		1,272		—		8,843
Asset retirement obligations and accrued environmental costs	—			496		169		—		665
Deferred income taxes	—			4,500		1,545		(4	)	6,041
Employee benefit obligations	—			1,094		191		—		1,285
Other liabilities and deferred credits	2,746			2,765		3,734		(8,968	)	277
Total Liabilities	10,218			14,141		9,956		(9,673	)	24,642
Common stock	11,405			25,404		10,688		(36,092	)	11,405
Retained earnings	12,377			8,518		(200	)	(8,347	)	12,348
Accumulated other comprehensive income (loss)	(653		)	(653	)	(119	)	772		(653	)
Noncontrolling interests	—			—		838		—		838
Total Liabilities and Equity	$	33,347		47,410		21,163		(53,340	)	48,580

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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*	5			429		399	—		833
Total Current Assets	19			9,569		8,206	(1,102	)	16,692
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*	16			159		120	(4	)	291
Total Assets	$	30,176		44,625		18,476	(44,585	)	48,692

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*	7,409			159		225	—		7,793
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	8,557			14,537		8,708	(5,147	)	26,655
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	$	30,176		44,625		18,476	(44,585	)	48,692

*Prior period amounts have been retrospectively adjusted for Accounting Standards Update No. 2015-03.

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	Millions of Dollars
	Year Ended December 31, 2015
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	$	1,060		4,879		2,564		(2,790	)	5,713
Net cash provided by discontinued operations	—			—		—		—		—
Net Cash Provided by Operating Activities	1,060			4,879		2,564		(2,790	)	5,713

Cash Flows From Investing Activities
Capital expenditures and investments*	—			(2,815	)	(5,283	)	2,334		(5,764	)
Proceeds from asset dispositions**	—			774		178		(882	)	70
Intercompany lending activities	2,461			(3,153	)	692		—		—
Advances/loans—related parties	—			(50	)	—		—		(50	)
Collection of advances/loans—related parties	—			50		—		—		50
Other	—			6		(50	)	—		(44	)
Net cash provided by (used in) continuing investing activities	2,461			(5,188	)	(4,463	)	1,452		(5,738	)
Net cash provided by (used in) discontinued operations	—			—		—		—		—
Net Cash Provided by (Used in) Investing Activities	2,461			(5,188	)	(4,463	)	1,452		(5,738	)

Cash Flows From Financing Activities
Issuance of debt	—			—		1,169		—		1,169
Repayment of debt	(800		)	(23	)	(103	)	—		(926	)
Issuance of common stock	(19		)	—		—		—		(19	)
Repurchase of common stock	(1,512		)	—		—		—		(1,512	)
Dividends paid on common stock	(1,172		)	(1,172	)	(1,576	)	2,748		(1,172	)
Distributions to controlling interests	—			—		(186	)	186		—
Distributions to noncontrolling interests	—			—		(46	)	—		(46	)
Net proceeds from issuance of Phillips 66 Partners LP common units	—			—		384		—		384
Other*	(18		)	34		1,585		(1,596	)	5
Net cash provided by (used in) continuing financing activities	(3,521		)	(1,161	)	1,227		1,338		(2,117	)
Net cash provided by (used in) discontinued operations	—			—		—		—		—
Net Cash Provided by (Used in) Financing Activities	(3,521		)	(1,161	)	1,227		1,338		(2,117	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents	—			—		9		—		9

Net Change in Cash and Cash Equivalents	—			(1,470	)	(663	)	—		(2,133	)
Cash and cash equivalents at beginning of period	—			2,045		3,162		—		5,207
Cash and Cash Equivalents at End of Period	$	—		575		2,499		—		3,074
* Includes intercompany capital contributions.
** Includes return of investments in equity affiliates and working capital true-ups on dispositions.

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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	)
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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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
2015
First	$	22,778	1,388	997	987	1.80	1.79
Second	28,512		1,465	1,025	1,012	1.85	1.84
Third	25,792		2,359	1,592	1,578	2.92	2.90
Fourth	21,893		832	666	650	1.21	1.20

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

*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, 2015, with the participation of management, our Chairman and Chief Executive Officer and our Executive Vice President 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 and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of December 31, 2015.

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, 2015, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting

This report is included in Item 8 and is incorporated herein by reference.

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

This report is included in Item 8 and is incorporated herein by reference.

Item 9B. OTHER INFORMATION

None.

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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.

Information required by Item 10 of Part III is incorporated herein by reference from our 2016 Definitive Proxy Statement.*

Item 11. EXECUTIVE COMPENSATION

Information required by Item 11 of Part III is incorporated herein by reference from our 2016 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 2016 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 2016 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 2016 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 2016 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 67, 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 137 to 140, 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 December 31, 2015 and 2014, and for the three years ended December 31, 2015, 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
2015
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable	$	71	3		—		(19	)	(b)	55
Deferred tax asset valuation allowance	107		(17	)	70		—			160
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

(a)Represents acquisitions/dispositions/revisions; net transfers associated with the Separation; deferred tax asset reinstatement in conjunction with German tax legislation, the realization of which is not more likely than not; 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-K	10.3	02/20/15	001-35349

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 19, 2016	/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 19, 2016, 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/ Kevin J. Mitchell		Executive Vice President, Finance
Kevin J. Mitchell		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

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