EDGAR 10-K Filing

Company CIK: 1534701
Filing Year: 2021
Filename: 1534701_10-K_2021_0001534701-21-000074.json

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ITEM 1. BUSINESS
Items 1 and 2. BUSINESS AND PROPERTIES
CORPORATE STRUCTURE
Phillips 66, headquartered in Houston, Texas, was incorporated in Delaware in 2011 in connection with, and in anticipation of, a restructuring of ConocoPhillips that separated its downstream businesses into an independent, publicly traded company named Phillips 66. The two companies were separated by ConocoPhillips distributing to its stockholders all the shares of common stock of Phillips 66 after the market closed on April 30, 2012 (the separation). Phillips 66 stock trades on the New York Stock Exchange under the “PSX” stock symbol.
Our business is organized into four operating segments:
1)Midstream-Provides crude oil and refined petroleum product transportation, terminaling and processing services, as well as natural gas and natural gas liquids (NGL) transportation, storage, fractionation, processing and marketing services, mainly in the United States. This segment includes our master limited partnership (MLP), Phillips 66 Partners LP (Phillips 66 Partners), as well as our 50% equity investment in DCP Midstream, LLC (DCP Midstream).
2)Chemicals-Consists of our 50% equity investment in Chevron Phillips Chemical Company LLC (CPChem), which manufactures and markets petrochemicals and plastics on a worldwide basis.
3)Refining-Refines crude oil and other feedstocks into petroleum products, such as gasoline, distillates and aviation fuels, at 13 refineries in the United States and Europe.
4)Marketing and Specialties (M&S)-Purchases for resale and markets refined petroleum products, mainly in the United States and Europe. In addition, this segment includes the manufacturing and marketing of specialty products, such as base oils and lubricants.
Corporate and Other includes general corporate overhead, interest expense, our investment in new technologies and various other corporate activities. Corporate assets include all cash, cash equivalents and income tax-related assets.
SEGMENT AND GEOGRAPHIC INFORMATION
MIDSTREAM
The Midstream segment consists of three business lines:
•Transportation-Transports crude oil and other feedstocks to our refineries and other locations, delivers refined petroleum products to market, and provides terminaling and storage services for crude oil and refined petroleum products.
•NGL and Other-Transports, stores, fractionates, exports and markets NGL and provides other fee-based processing services.
•DCP Midstream-Gathers, processes, transports and markets natural gas and transports, fractionates and markets NGL.
Phillips 66 Partners
Phillips 66 Partners, headquartered in Houston, Texas, is a publicly traded MLP formed in 2013 to own, operate, develop and acquire primarily fee-based midstream assets. At December 31, 2020, we owned 170 million Phillips 66 Partners common units, representing a 74% limited partner interest in Phillips 66 Partners, while the public owned a 26% limited partner interest and 13.8 million perpetual convertible preferred units. We also own a noneconomic general partner interest.
Phillips 66 Partners’ operations consist of crude oil, refined petroleum product and NGL transportation, terminaling, fractionation, processing and storage assets that are geographically dispersed throughout the United States. The majority of Phillips 66 Partners’ assets are associated with, and integral to, Phillips 66 operated refineries.
The results of operations of Phillips 66 Partners are included in Midstream’s Transportation and NGL and Other business lines, based on the nature of the activity within the partnership.
Transportation
We own or lease various assets to provide transportation, terminaling and storage services. These assets include crude oil, refined petroleum product, NGL, and natural gas pipeline systems; crude oil, refined petroleum product and NGL terminals; a petroleum coke handling facility; marine vessels; railcars and trucks.
Pipelines and Terminals
At December 31, 2020, our Transportation business was comprised of over 22,000 miles of crude oil, refined petroleum product, NGL and natural gas pipeline systems in the United States, including those partially owned or operated by our affiliates. We owned or operated 39 refined petroleum product terminals, 20 crude oil terminals, 5 NGL terminals, a petroleum coke exporting facility and various other storage and loading facilities.
The Beaumont Terminal in Nederland, Texas, is the largest terminal in the Phillips 66 portfolio. In the fourth quarter of 2020, we completed construction of a new 200,000 barrels per day (BPD) dock at the Beaumont Terminal, bringing the terminal’s total dock capacity to 800,000 BPD. At December 31, 2020, the terminal had total crude oil and refined petroleum product storage capacity of 16.8 million barrels.
The Gray Oak Pipeline transports up to 900,000 BPD of crude oil from the Permian and Eagle Ford to Texas Gulf Coast destinations that include Corpus Christi, Texas, and the Sweeny area, including our Sweeny Refinery. The pipeline made its first commercial delivery in November 2019 and commenced full operations in the second quarter of 2020. Phillips 66 Partners has a 42.25% effective ownership interest in the pipeline.
Phillips 66 Partners owns a 25% interest in the South Texas Gateway Terminal, which connects to the Gray Oak Pipeline in Corpus Christi, Texas. The first dock of the marine export terminal began crude oil export operations in July 2020. The second dock commenced crude oil export operations in the fourth quarter of 2020. Upon completion in the first quarter of 2021, the marine export terminal will have storage capacity of 8.6 million barrels and up to 800,000 BPD of dock throughput capacity.
Phillips 66 Partners continued construction of a 16 inch ethane pipeline (C2G Pipeline) that will connect its Clemens Caverns storage facility to petrochemical facilities in Gregory, Texas. The project is backed by long-term commitments and is expected to be completed in mid-2021.
The Liberty Pipeline joint venture was formed to transport crude oil from the Rockies and Bakken production areas to Cushing, Oklahoma. Phillips 66 Partners holds a 50% interest in the joint venture. In March 2020, Phillips 66 Partners deferred the Liberty Pipeline system project due to the challenging business environment.
In the third quarter of 2020, the project to develop and construct the Red Oak Pipeline system was canceled. We hold a 50% interest in the joint venture that was pursuing this project.
The Dakota Access Pipeline is currently subject to litigation that could affect operations. See the “Dakota Access, LLC (Dakota Access) and Energy Transfer Crude Oil Company, LLC (ETCO)” section of Note 6-Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for additional information on this litigation.
The following table depicts our ownership interest in major pipeline systems at December 31, 2020:
Name State of
Origination/Terminus Interest Length
(Miles) Gross Capacity
(MBD)
Crude Oil
Bakken Pipeline † North Dakota/Texas 25 % 1,918 570
Bayou Bridge † Texas/Louisiana 40 213 480
Clifton Ridge † Louisiana 100 10 260
CushPo † Oklahoma 100 62 130
Eagle Ford Gathering † Texas 100 28 54
Glacier † Montana 79 825 124
Gray Oak Pipeline* † Texas 42 845 900
Line 100 California 100 79 61
Line 200 California 100 228 100
Line 300 California 100 61 34
Line 400 California 100 153 46
Line O † Oklahoma/Texas 100 276 38
New Mexico Crude † New Mexico/Texas 100 227 106
North Texas Crude † Texas 100 224 34
Oklahoma Crude † Texas/Oklahoma 100 217 100
Sacagawea † North Dakota 50 95 183
STACK PL † Oklahoma 50 149 250
Sweeny Crude Texas 100 56 617
West Texas Crude † Texas 100 1,079 140
Refined Petroleum Products
ATA Line † Texas/New Mexico 50 293 34
Borger to Amarillo † Texas 100 93 74
Borger-Denver Texas 100 38 39
Borger-Denver Texas/Colorado 65 207 39
Borger-Denver Colorado 70 152 39
Cherokee East † Oklahoma/Missouri 100 287 59
Cherokee North † Oklahoma/Kansas 100 29 55
Cherokee South † Oklahoma 100 98 47
Cross Channel Connector † Texas 100 5 184
Explorer † Texas/Indiana 22 1,830 660
Gold Line † Texas/Illinois 100 686 120
Heartland** Kansas/Iowa 50 49 30
LAX Jet Line California 50 19 25
Los Angeles Products California 100 22 132
Paola Products † Kansas 100 106 120
Pioneer Wyoming/Utah 50 562 63
Richmond California 100 14 31
SAAL † Texas 33 102 32
SAAL † Texas 54 19 30
Seminoe † Montana/Wyoming 100 342 44
Standish † Oklahoma/Kansas 100 92 77
Sweeny to Pasadena † Texas 100 120 335
Torrance Products California 100 8 279
Watson Products California 100 9 238
Yellowstone Montana/Washington 46 710 68
Name State of
Origination/Terminus Interest Length
(Miles) Gross Capacity
(MBD)
NGL
Blue Line Texas/Illinois 100 % 688 26
Brown Line † Oklahoma/Kansas 100 76 26
Chisholm Oklahoma/Kansas 50 202 42
Conway to Wichita Kansas 100 55 26
Medford † Oklahoma 100 42 25
Powder River Wyoming/Texas 100 716 16
River Parish NGL † Louisiana 100 499 104
Sand Hills † New Mexico/Texas 33 1,400 500
Skelly-Belvieu Texas 50 571 47
Southern Hills † Kansas/Texas 33 981 192
Sweeny LPG Texas 100 260 942
Sweeny NGL Texas 100 18 204
TX Panhandle Y1/Y2 Texas 100 289 78
Natural Gas
Rockies Express***
East to West Ohio/Illinois 25 661 2.6 Bcf/d
West to East Colorado/Ohio 25 1,712 1.8 Bcf/d
Sacagawea Gas † North Dakota 50 24 0.18 Bcf/d
† Owned by Phillips 66 Partners; Phillips 66 held 74% of the limited partner interest in Phillips 66 Partners at December 31, 2020.
* Interest reflects Phillips 66 Partners’ proportionate share of the Gray Oak Pipeline, net of a noncontrolling interest.
** Total pipeline system is 419 miles. Phillips 66 has an ownership interest in multiple segments totaling 49 miles.
*** Total pipeline system consists of three zones for a total of 1,712 miles. The third zone of the pipeline is bidirectional and can transport 2.6 Bcf/d of natural gas from east to west.
The following table depicts our ownership interest in terminal and storage facilities at December 31, 2020:
Facility Name Location Commodity Handled Interest Gross Storage Capacity (MBbl) Gross Rack Capacity (MBD)
Albuquerque † New Mexico Refined Petroleum Products 100 % 274 20
Amarillo † Texas Refined Petroleum Products 100 296 23
Beaumont Texas Crude Oil, Refined Petroleum Products 100 16,800 8
Billings Montana Refined Petroleum Products 100 88 12
Billings Crude † Montana Crude Oil 100 236 N/A
Borger Texas Crude Oil 50 772 N/A
Bozeman Montana Refined Petroleum Products 100 90 5
Buffalo Crude † Montana Crude Oil 100 303 N/A
Casper † Wyoming Refined Petroleum Products 100 365 7
Clemens † Texas NGL 100 16,500 N/A
Clifton Ridge † Louisiana Crude Oil 100 3,800 N/A
Coalinga California Crude Oil 100 817 N/A
Colton California Refined Petroleum Products 100 207 20
Cushing † Oklahoma Crude Oil 100 675 N/A
Cut Bank † Montana Crude Oil 100 315 N/A
Denver Colorado Refined Petroleum Products 100 441 43
Des Moines Iowa Refined Petroleum Products 50 217 12
East St. Louis † Illinois Refined Petroleum Products 100 1,529 55
Freeport Texas Crude Oil, Refined Petroleum Products, NGL 100 3,485 N/A
Glenpool † Oklahoma Refined Petroleum Products 100 571 18
Great Falls Montana Refined Petroleum Products 100 198 6
Hartford † Illinois Refined Petroleum Products 100 1,468 21
Helena Montana Refined Petroleum Products 100 195 5
Jefferson City † Missouri Refined Petroleum Products 100 103 15
Jones Creek Texas Crude Oil 100 2,580 N/A
Junction California Crude Oil, Refined Petroleum Products 100 524 N/A
Kansas City † Kansas Refined Petroleum Products 100 1,410 50
Keene † North Dakota Crude Oil 50 503 N/A
La Junta Colorado Refined Petroleum Products 100 109 5
Lake Charles Pipeline Storage Louisiana Refined Petroleum Products 50 3,143 N/A
Lincoln Nebraska Refined Petroleum Products 100 217 12
Linden † New Jersey Refined Petroleum Products 100 360 95
Los Angeles California Refined Petroleum Products 100 156 80
Lubbock † Texas Refined Petroleum Products 100 182 18
Medford Spheres † Oklahoma NGL 100 70 N/A
Missoula Montana Refined Petroleum Products 50 365 14
Moses Lake Washington Refined Petroleum Products 50 216 10
Mount Vernon † Missouri Refined Petroleum Products 100 365 40
North Salt Lake Utah Refined Petroleum Products 50 755 34
North Spokane Washington Refined Petroleum Products 100 492 N/A
Odessa † Texas Crude Oil 100 521 N/A
Oklahoma City † Oklahoma Crude Oil, Refined Petroleum Products 100 355 42
Facility Name Location Commodity Handled Interest Gross Storage Capacity (MBbl) Gross Rack Capacity (MBD)
Palermo † North Dakota Crude Oil 70 % 235 N/A
Paola † Kansas Refined Petroleum Products 100 978 N/A
Pasadena † Texas Refined Petroleum Products, NGL 100 3,558 65
Pecan Grove † Louisiana Lubricant Base Stocks, Refined Petroleum Products 100 177 N/A
Ponca City † Oklahoma Refined Petroleum Products 100 71 22
Ponca City Crude † Oklahoma Crude Oil 100 1,229 N/A
Portland Oregon Refined Petroleum Products 100 650 38
Renton Washington Refined Petroleum Products 100 243 19
Richmond California Refined Petroleum Products 100 343 28
River Parish † Louisiana NGL 100 1,500 N/A
Rock Springs Wyoming Refined Petroleum Products 100 132 8
Sacramento California Refined Petroleum Products 100 146 12
San Bernard Texas Refined Petroleum Products 100 222 N/A
Santa Margarita California Crude Oil 100 398 N/A
Sheridan † Wyoming Refined Petroleum Products 100 94 6
South Texas Gateway † Texas Crude Oil 25 7,700 N/A
Spokane Washington Refined Petroleum Products 100 351 20
Tacoma Washington Refined Petroleum Products 100 316 19
Torrance California Crude Oil, Refined Petroleum Products 100 2,128 N/A
Tremley Point † New Jersey Refined Petroleum Products 100 1,701 25
Westlake Louisiana Refined Petroleum Products 100 128 10
Wichita Falls † Texas Crude Oil 100 225 N/A
Wichita North † Kansas Refined Petroleum Products 100 769 20
Wichita South † Kansas Refined Petroleum Products 100 272 N/A
† Owned by Phillips 66 Partners; Phillips 66 held 74% of the limited partner interest in Phillips 66 Partners at December 31, 2020.
The following table depicts our ownership interest in marine, rail and petroleum coke loading and offloading facilities at December 31, 2020:
Facility Name Location Commodity Handled Interest Gross Loading Capacity*
Marine
Beaumont Texas Crude Oil, Refined Petroleum Products 100 % 75
Clifton Ridge † Louisiana Crude Oil, Refined Petroleum Products 100 50
Freeport Texas Crude Oil, Refined Petroleum Products, NGL 100 46
Hartford † Illinois Refined Petroleum Products 100 3
Pecan Grove † Louisiana Lubricant Base Stocks, Refined Petroleum Products 100 6
Portland Oregon Crude Oil 100 10
Richmond California Crude Oil 100 3
San Bernard Texas Refined Petroleum Products 100 2
South Texas Gateway † Texas Crude Oil 25 33
Tacoma Washington Crude Oil 100 12
Tremley Point † New Jersey Refined Petroleum Products 100 7
Rail
Bayway † New Jersey Crude Oil 100 75
Beaumont Texas Crude Oil 100 20
Ferndale † Washington Crude Oil 100 30
Missoula Montana Refined Petroleum Products 50 41
Palermo † North Dakota Crude Oil 70 100
Thompson Falls Montana Refined Petroleum Products 50 41
Petroleum Coke
Lake Charles Louisiana Petroleum Coke 50 N/A
† Owned by Phillips 66 Partners; Phillips 66 held 74% of the limited partner interest in Phillips 66 Partners at December 31, 2020.
* Marine facilities in thousands of barrels per hour; Rail in thousands of barrels daily (MBD).
Marine Vessels
At December 31, 2020, we had 12 international-flagged crude oil, refined petroleum product and NGL tankers under time charter contracts, with capacities ranging in size from 300,000 to 2,200,000 barrels. Additionally, we had a variety of inland and offshore tug/barge units. These vessels are used primarily to transport crude oil and other feedstocks, as well as refined petroleum products for our refineries. In addition, the NGL tankers are used to export propane and butane from our fractionation, transportation and storage infrastructure.
Truck and Rail
Our truck and rail fleets support our feedstock and distribution operations. Rail movements are provided via a fleet of approximately 9,700 owned and leased railcars. Truck movements are provided through our wholly owned subsidiary, Sentinel Transportation LLC, and through numerous third-party trucking companies.
NGL and Other
Our NGL and Other business includes the following:
•The Sweeny Hub, a U.S. Gulf Coast NGL market hub with 400,000 BPD of total fractionation capacity, a liquefied petroleum gas (LPG) export terminal and NGL storage caverns.
•A 22.5% interest in Gulf Coast Fractionators, which owns an NGL fractionation plant in Mont Belvieu, Texas. Our net share of its capacity is 32,625 BPD. In December 2020, we began the process to idle this facility and transfer operatorship to a co-venturer.
•A 12.5% undivided interest in a fractionation plant in Mont Belvieu, Texas. Our net share of its capacity is 30,250 BPD.
•A 40% undivided interest in a fractionation plant in Conway, Kansas. Our net share of its capacity is 43,200 BPD.
•Phillips 66 Partners owns the River Parish NGL logistics system in southeast Louisiana, comprising approximately 500 miles of pipeline and a storage cavern connecting multiple fractionation facilities, refineries and a petrochemical facility.
•Phillips 66 Partners owns a direct one-third interest in both the DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC (Southern Hills), which own NGL pipeline systems that connect the Eagle Ford, Permian Basin and Midcontinent production areas to the Mont Belvieu, Texas, market hub.
•Phillips 66 Partners owns a vacuum distillation unit with a capacity of 125,000 BPD and a delayed coker unit with a capacity of 70,000 BPD located at our Sweeny Refinery in Old Ocean, Texas.
•Phillips 66 Partners owns a 25,000 BPD isomerization unit at our Lake Charles Refinery. The isomerization unit increases Phillips 66’s production of higher-octane gasoline blend components.
The Sweeny Hub fractionators are located adjacent to our Sweeny Refinery in Old Ocean, Texas, and supply purity ethane to the petrochemical industry and purity NGL to domestic and global markets. Raw NGL supply to the fractionators is delivered from nearby major pipelines, including the Sand Hills Pipeline. The fractionators are supported by significant infrastructure including connectivity to two NGL supply pipelines, a pipeline connecting to the Mont Belvieu market hub and the Clemens Caverns storage facility with access to our LPG export terminal in Freeport, Texas.
During 2020, Phillips 66 completed two new 150,000 BPD fractionators at the Sweeny Hub, bringing the site’s total fractionation capacity to 400,000 BPD. Frac 2 and Frac 3 commenced commercial operations in September 2020 and October 2020, respectively. The fractionators are supported by long-term customer commitments. The construction and development of Frac 4, a new 150,000 BPD fractionator at the Sweeny Hub, is expected to resume in the second half of 2021, after a temporary deferral announced in March 2020.
During the second quarter of 2020, Phillips 66 Partners completed the expansion of storage capacity at Clemens Caverns from 9 million barrels to 16.5 million barrels.
The Freeport LPG Export Terminal leverages our fractionation, transportation and storage infrastructure to supply petrochemical, heating and transportation markets globally. The terminal can simultaneously load two ships with refrigerated propane and butane at a combined rate of approximately 36,000 barrels per hour. In addition, the terminal has the capability to export natural gasoline (C5+) produced by the Sweeny Hub fractionators.
DCP Midstream
Our Midstream segment includes our 50% equity investment in DCP Midstream, which is headquartered in Denver, Colorado. At December 31, 2020, DCP Midstream, through its subsidiary DCP Midstream, LP (DCP Partners), owned or operated 39 active natural gas processing facilities, with a net processing capacity of approximately 6.0 billion cubic feet per day (Bcf/d), and approximately 57,000 miles of natural gas and NGL pipelines. DCP Midstream’s owned or operated natural gas pipeline systems included gathering services for these facilities and natural gas transmission. DCP Midstream also owned or operated 9 NGL fractionation plants, along with natural gas and NGL storage facilities and NGL pipelines.
The residual natural gas, primarily methane, which results from processing raw natural gas, is sold by DCP Midstream at market-based prices to marketers and end users, including large industrial companies, natural gas distribution companies and electric utilities. DCP Midstream purchases or takes custody of substantially all of its raw natural gas from producers, principally under contractual arrangements that expose DCP Midstream to the prices of NGL, natural gas and condensate. DCP Midstream also has fee-based arrangements with producers to provide midstream services such as gathering and processing. In addition, DCP Midstream markets a portion of its NGL to us and our equity affiliates under existing contracts.
During 2020, DCP Midstream completed the following growth projects:
•The Cheyenne Connector was placed into service in the second quarter of 2020, adding 600 million cubic feet per day (MMcf/d) of residue gas takeaway and easing logistics constraints in the DJ Basin.
•The Front Range pipeline was expanded to a capacity of 260,000 BPD and the Texas Express pipeline was expanded to a capacity of 370,000 BPD in the second quarter of 2020.
•The Latham 2 offload was placed into service in the fourth quarter of 2020, adding up to 225 MMcf/d of incremental DJ Basin processing capacity.
CHEMICALS
The Chemicals segment consists of our 50% equity investment in CPChem, which is headquartered in The Woodlands, Texas. At December 31, 2020, CPChem owned or had joint venture interests in 28 manufacturing facilities located in Belgium, Colombia, Qatar, Saudi Arabia, Singapore and the United States. Additionally, CPChem has two research and development centers in the United States.
We structure our reporting of CPChem’s operations around two primary business lines: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P business line produces and markets ethylene and other olefin products. The ethylene produced is primarily used by CPChem to produce polyethylene, normal alpha olefins (NAO) and polyethylene pipe. The SA&S business line manufactures and markets aromatics and styrenics products, such as benzene, cyclohexane, styrene and polystyrene. SA&S also manufactures and/or markets a variety of specialty chemical products including organosulfur chemicals, solvents, catalysts, and chemicals used in drilling and mining.
The manufacturing of petrochemicals and plastics involves the conversion of hydrocarbon-based raw material feedstocks into higher-value products, often through a thermal process referred to in the industry as “cracking.” For example, ethylene can be produced by cracking ethane, propane, butane, natural gasoline or certain refinery liquids, such as naphtha and gas oil. Ethylene primarily is used as a raw material in the production of plastics, such as polyethylene and polyvinyl chloride (PVC). Plastic resins, such as polyethylene, are manufactured in a thermal/catalyst process, and the produced output is used as a further raw material for various applications, such as packaging and plastic pipe.
The following table reflects CPChem’s petrochemicals and plastics product capacities at December 31, 2020:
Millions of Pounds per Year*
U.S. Worldwide
O&P
Ethylene 11,910 14,385
Propylene 2,675 3,180
High-density polyethylene 5,305 7,470
Low-density polyethylene 620 620
Linear low-density polyethylene 1,590 1,590
Polypropylene - 310
Normal alpha olefins 2,335 2,850
Polyalphaolefins 125 255
Polyethylene pipe 500 500
Total O&P 25,060 31,160
SA&S
Benzene 1,600 2,530
Cyclohexane 1,060 1,455
Styrene 1,050 1,875
Polystyrene 835 915
Specialty chemicals 440 575
Total SA&S 4,985 7,350
Total O&P and SA&S 30,045 38,510
* Capacities include CPChem’s share in equity affiliates and excludes CPChem’s NGL fractionation capacity.
CPChem and a co-venturer are jointly pursuing the development of petrochemical facilities on the U.S. Gulf Coast and in Ras Laffan, Qatar. CPChem is monitoring economic developments and has deferred final investment decision for the U.S. Gulf Coast project until 2022.
In October 2020, CPChem announced its first U.S. commercial-scale production of circular polyethylene from recycled mixed-waste plastics at its Cedar Bayou facility and received International Sustainability and Carbon Certification PLUS (ISCC PLUS) certification for this location in November 2020. CPChem is using advanced recycling technology to convert plastic waste to liquids that can become new petrochemicals. CPChem’s circular polyethylene matches the performance and safety specifications of traditional polymers.
REFINING
Our Refining segment refines crude oil and other feedstocks into petroleum products, such as gasoline, distillates and aviation fuels, at 13 refineries in the United States and Europe.
The table below depicts information for each of our owned and joint venture refineries at December 31, 2020:
Thousands of Barrels Daily
Region/Refinery Location Interest Net Crude Throughput
Capacity Net Clean Product
Capacity** Clean
Product
Yield
Capability
At
December 31 2020 Effective January 1 2021 Gasolines Distillates
Atlantic Basin/Europe
Bayway Linden, NJ 100 % 258 258 155 130 92 %
Humber N. Lincolnshire, United Kingdom 100 221 221 95 115 81
MiRO* Karlsruhe, Germany 19 58 58 25 25 87
537 537
Gulf Coast
Alliance Belle Chasse, LA 100 255 255 130 120 87
Lake Charles Westlake, LA 100 249 264 105 115 70
Sweeny Old Ocean, TX 100 265 265 140 125 86
769 784
Central Corridor
Wood River Roxana, IL 50 173 173 88 70 81
Borger Borger, TX 50 75 75 50 35 91
Ponca City Ponca City, OK 100 217 217 120 100 93
Billings Billings, MT 100 65 66 36 30 90
530 531
West Coast
Ferndale Ferndale, WA 100 105 105 65 37 81
Los Angeles Carson/Wilmington, CA 100 139 139 85 65 90
San Francisco Arroyo Grande/Rodeo, CA 100 120 120 60 65 85
364 364
2,200 2,216
* 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.
Primary crude oil characteristics and sources of crude oil for our owned and joint venture refineries are as follows:
Characteristics Sources
Sweet Medium
Sour Heavy
Sour High
TAN*
United
States Canada South and Central
America Europe**
Middle East
& Africa
Bayway l l l l l
Humber l l l l l l
MiRO l l l l l l
Alliance l l l
Lake Charles l l l l l l l l l
Sweeny l l l l l l l
Wood River l l l l l
Borger l l l l l
Ponca City l l l l l
Billings l l l l l
Ferndale l l l l l
Los Angeles l l l l l l l
San Francisco l l 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.
** Includes Russian crude.
Atlantic Basin/Europe Region
Bayway Refinery
The Bayway Refinery is located on the New York Harbor in Linden, New Jersey. Bayway’s facilities include crude distilling, naphtha reforming, fluid catalytic cracking, solvent deasphalting, hydrodesulfurization and alkylation units. The complex also includes a polypropylene plant with the capacity to produce up to 775 million pounds per year. The refinery produces a high percentage of transportation fuels, as well as petrochemical feedstocks, residual fuel oil and home heating oil. Refined petroleum products are distributed to East Coast customers by pipeline, barge, railcar and truck.
Humber Refinery
The Humber Refinery is located on the east coast of England in North Lincolnshire, United Kingdom, approximately 180 miles north of London. Humber’s facilities include crude distilling, naphtha reforming, fluid catalytic cracking, hydrodesulfurization, thermal cracking and delayed coking units. The refinery has two coking units with associated calcining plants. Humber is the only coking refinery in the United Kingdom, and a producer of high-quality specialty graphite and anode-grade petroleum cokes. The refinery also produces a high percentage of transportation fuels. The majority of the light oils produced by the refinery are distributed to customers in the United Kingdom by pipeline, railcar and truck, while the other refined petroleum products are exported throughout the world.
MiRO Refinery
The MiRO Refinery is located on the Rhine River in Karlsruhe, Germany, approximately 95 miles south of Frankfurt, Germany. MiRO is the largest refinery in Germany and operates as a joint venture in which we own an 18.75% interest. Facilities include crude distilling, naphtha reforming, fluid catalytic cracking, petroleum coking and calcining, hydrodesulfurization, isomerization, ethyl tert-butyl ether and alkylation units. MiRO produces a high percentage of transportation fuels. Other products produced include petrochemical feedstocks, home heating oil, bitumen, and anode- and fuel-grade petroleum cokes. Refined petroleum products are distributed to customers in Germany, Switzerland, France, 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, approximately 25 miles southeast of New Orleans, Louisiana. The single-train facility includes crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrodesulfurization, aromatics and delayed coking units. Alliance produces a high percentage of transportation fuels. Other products produced include petrochemical feedstocks, home heating oil and anode-grade petroleum coke. A majority of the refined petroleum products are distributed to customers in the southeastern and eastern United States through major common carrier pipeline systems and by barge. Additionally, refined petroleum products are exported to customers primarily in Latin America by waterborne cargo.
Lake Charles Refinery
The Lake Charles Refinery is located in Westlake, Louisiana, approximately 150 miles east of Houston, Texas. Refinery facilities include crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrocracking, hydrodesulfurization and delayed coking units. Refinery facilities also include a specialty coker and calciner. The refinery produces a high percentage of transportation fuels. Other products produced include off-road diesel, home heating oil, feedstock for our Excel Paralubes joint venture in our M&S segment, and high-quality specialty graphite and fuel-grade petroleum cokes. A majority of the refined petroleum products are distributed to customers in the southeastern and eastern United States by truck, railcar, barge or major common carrier pipelines. Additionally, refined petroleum products are exported to customers primarily in Latin America and Europe by waterborne cargo.
Sweeny Refinery
The Sweeny Refinery is located in Old Ocean, Texas, approximately 65 miles southwest of Houston, Texas. Refinery facilities include crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrodesulfurization, aromatics units, and a Phillips 66 Partners owned delayed coking unit. The refinery produces a high percentage of transportation fuels. Other products include petrochemical feedstocks, home heating oil and fuel-grade petroleum coke. A majority of the refined petroleum products are distributed to customers throughout the Midcontinent region, southeastern and eastern United States by pipeline, barge and railcar. Additionally, refined petroleum products are exported to customers primarily in Latin America by waterborne cargo.
Central Corridor Region
WRB Refining LP (WRB)
We are the operator and managing partner of WRB, a 50 percent-owned joint venture that owns the Wood River and Borger refineries.
•Wood River Refinery
The Wood River Refinery is located in Roxana, Illinois, about 15 miles northeast of St. Louis, Missouri, at the confluence of the Mississippi and Missouri rivers. Refinery facilities include crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrocracking, hydrodesulfurization and delayed coking units. The refinery produces a high percentage of transportation fuels. Other products produced include petrochemical feedstocks, asphalt and fuel-grade petroleum coke. Refined petroleum products are distributed to customers throughout the Midcontinent region by pipeline, railcar, barge and truck.
•Borger Refinery
The Borger Refinery is located in Borger, Texas, in the Texas Panhandle, approximately 50 miles north of Amarillo, Texas. Refinery facilities include crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrodesulfurization, and delayed coking units. The refinery produces a high percentage of transportation fuels, as well as fuel-grade petroleum coke, NGL and solvents. Refined petroleum products are distributed to customers in West Texas, New Mexico, Colorado and the Midcontinent region by company-owned and common carrier pipelines.
Ponca City Refinery
The Ponca City Refinery is located in Ponca City, Oklahoma, approximately 95 miles northwest of Tulsa, Oklahoma. Refinery facilities include crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrodesulfurization, and delayed coking units. The refinery produces a high percentage of transportation fuels and anode-grade petroleum coke. Refined petroleum products are primarily distributed to customers throughout the Midcontinent region by company-owned and common carrier pipelines.
Billings Refinery
The Billings Refinery is located in Billings, Montana. Refinery facilities include crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrodesulfurization and delayed coking units. The refinery produces a high percentage of transportation fuels and fuel-grade petroleum coke. Refined petroleum products are distributed to customers in Montana, Wyoming, Idaho, Utah, Colorado and Washington by pipeline, railcar and truck.
West Coast Region
Ferndale Refinery
The Ferndale Refinery is located on Puget Sound in Ferndale, Washington, approximately 20 miles south of the U.S.-Canada border. Facilities include crude distillation, naphtha reforming, fluid catalytic cracking, alkylation and hydrodesulfurization units. The refinery produces a high percentage of transportation fuels. Other products produced include residual fuel oil, which is supplied to the northwest marine bunker fuel market. Most of the refined petroleum products are distributed to customers in the northwest United States by pipeline and barge.
Los Angeles Refinery
The Los Angeles Refinery consists of two facilities linked by pipeline located five miles apart in Carson and Wilmington, California, approximately 15 miles southeast of Los Angeles. The Carson facility serves as the front end of the refinery by processing crude oil, and the Wilmington facility serves as the back end of the refinery by upgrading the intermediate products to finished products. Refinery facilities include crude distillation, naphtha reforming, fluid catalytic cracking, alkylation, hydrocracking, and delayed coking units. The refinery produces a high percentage of transportation fuels. The refinery produces California Air Resources Board (CARB)-grade gasoline. Other products produced include fuel-grade petroleum coke. Refined petroleum products are distributed to customers in California, Nevada and Arizona by pipeline and truck.
San Francisco Refinery
The San Francisco Refinery consists of two facilities linked by our pipelines. The Santa Maria facility is located in Arroyo Grande, California, 200 miles south of San Francisco, California, while the Rodeo facility is located in the San Francisco Bay Area. Intermediate refined products from the Santa Maria facility are shipped by pipeline to the Rodeo facility for upgrading into finished petroleum products. Refinery facilities include crude distillation, naphtha reforming, hydrocracking, hydrodesulfurization and delayed coking units, as well as a calciner. The refinery produces a high percentage of transportation fuels, including CARB-grade gasoline. Other products produced include fuel-grade petroleum coke. The majority of the refined petroleum products are distributed to customers in California by pipeline and barge. Additionally, refined petroleum products are exported to customers primarily in Latin America by waterborne cargo.
In the third quarter of 2020, we announced Rodeo Renewed, a project to reconfigure our San Francisco Refinery to produce renewable fuels. The Rodeo facility will no longer produce fuels from crude oil, but instead will make fuels from used cooking oil, fats, greases, soybean oils and other feedstocks. We expect to complete the diesel hydrotreater conversion in mid-2021, which will produce 8,000 BPD (120 million gallons per year) of renewable diesel. Upon expected completion of the full conversion in early 2024, the facility will have a renewable fuel production capacity of over 50,000 BPD, or 800 million gallons per year.
MARKETING AND SPECIALTIES
Our 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.
Marketing
Marketing-United States
We market gasoline, diesel and aviation fuel through marketer and joint venture outlets that utilize the Phillips 66, Conoco or 76 brands. At December 31, 2020, we had approximately 7,590 branded outlets in 48 states and Puerto Rico.
Our wholesale operations utilize a network of marketers operating approximately 5,440 outlets. We place a strong emphasis on the wholesale channel of trade because of its relatively lower capital requirements. In addition, we hold brand-licensing agreements covering approximately 1,370 sites. Our refined petroleum products are marketed on both a branded and unbranded basis. A high percentage of our branded marketing sales are in the Midcontinent, Rockies and West Coast regions, where our wholesale marketing network secures efficient offtake from our refineries. We also utilize consignment fuel arrangements with several marketers whereby we own the fuel inventory and pay the marketers a monthly fee.
In the Gulf Coast and East Coast regions, most sales are conducted via the unbranded channel of trade, which does not require a highly integrated marketing network to secure product placement for refinery pull through. We have export capability at our U.S. coastal refineries to meet international demand.
In addition to automotive gasoline and diesel, we produce and market aviation gasoline and jet fuel. Aviation gasoline and jet fuel are sold through dealers and independent marketers at approximately 780 Phillips 66 branded locations.
We also participate in retail joint ventures to secure long-term placement of our refinery production and extend participation in the retail value chain. At December 31, 2020, our joint ventures had approximately 730 outlets. During the second quarter of 2020, our West Coast retail joint venture completed the acquisition of 95 additional sites. In January 2021, one of our joint ventures in the Central region acquired 106 retail sites.
Marketing-International
We have marketing operations in four European countries. Our European marketing strategy is to sell primarily through owned, leased or joint venture retail sites using a low-cost, high-volume approach. We use the JET brand name to market retail and wholesale products in Austria, Germany and the United Kingdom. In addition, we have an equity interest in a joint venture that markets refined petroleum products in Switzerland under the COOP brand name.
We also market aviation fuels, LPG, heating oils, marine bunker fuels, and other secondary refined products to commercial customers and into the bulk or spot markets in the above countries.
At December 31, 2020, we had approximately 1,280 marketing outlets in Europe, of which approximately 990 were company owned and approximately 290 were dealer owned. We had interests in approximately 330 additional sites through our COOP joint venture operations in Switzerland, and we held brand-licensing agreements covering approximately 90 sites in Mexico.
We continued our program to update signature image designs for JET branded sites in Europe.
Specialties
We manufacture lubricants and sell a variety of specialty products, including petroleum coke products, solvents and polypropylene.
Lubricants
We manufacture and sell automotive, commercial, industrial and specialty lubricants which are marketed worldwide under the Phillips 66, Kendall, Red Line and other private label brands. We also market Group III Ultra-S base oils through an agreement with South Korea’s S-Oil Corporation.
In addition, we own a 50% interest in Excel Paralubes LLC (Excel), an operated joint venture that owns a hydrocracked lubricant base oil manufacturing plant located adjacent to the Lake Charles Refinery. The facility has a nameplate capacity to produce 22,200 BPD of high-quality Group II clear hydrocracked base oils. Excel markets the produced base oil under the Pure Performance brand. The facility’s feedstock is sourced primarily from our Lake Charles Refinery.
Other Specialty Products
We market high-quality specialty graphite and anode-grade petroleum cokes in the United States, Europe and Asia for use in a variety of industries that include steel, aluminum, titanium dioxide and battery manufacturing. We also market polypropylene in North America under the COPYLENE brand name for use in consumer products, and market specialty solvents that include pentane, iso-pentane, hexane, heptane and odorless mineral spirits for use in the petrochemical, agriculture and consumer markets. In addition, we market sulfur for use in agricultural and chemical applications, and fuel-grade petroleum coke for use in the making of cement and glass, and generation of power.
ENERGY RESEARCH & INNOVATION
Our Energy Research & Innovation organization, located in Bartlesville, Oklahoma, consists of approximately 250 scientists and engineers who conduct research to enhance the safety and reliability of our operations and to develop future air, water and energy solutions, including battery technology, organic (carbon-based) photovoltaic materials and solid oxide fuel cells, for the storage or production of electricity. The Energy Research & Innovation organization enhances our business programs and initiatives with research that enables us to improve our operations and provides a science-based approach to supporting our businesses and evaluating new opportunities.
HUMAN CAPITAL
Phillips 66 employees, our human capital, are guided by our values of safety, honor and commitment. Together, we operate as a high-performing organization by building breadth and depth in capabilities, pursuing excellence and doing the right thing. We empower our people to create and innovate, and to work in ways to deliver industry leading performance. At December 31, 2020, we had approximately 14,300 employees working toward our vision of providing energy and improving lives.
We believe maintaining and enhancing a high-performing organization is critical to our success. Our employees promote our culture and are integral to achieving our strategic goals and maximizing long-term shareholder value. We strive for continuous improvement of our high-performing organization, as we believe that our employees differentiate us in the marketplace. Human capital measures and objectives that we focus on in managing our business include:
•Safety-Safety is the cornerstone of our business. 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. We employ rigorous training and audit programs to drive ongoing improvement in personal safety as we strive for zero incidents.
•Culture-Phillips 66 fosters behaviors that promote our culture. “Our Energy in Action” is a set of core behaviors embedded in all of the company’s talent and business processes to drive accountability. Those behaviors include working for the greater good; creating an environment of trust; seeking different perspectives; and achieving excellence.
In addition, we believe a high level of performance can only be achieved through an inclusive culture and diverse workforce. Our inclusion and diversity (I&D) council, chaired by our Chairman and Chief Executive Officer and comprised of executives and business leaders, sets the strategic vision for advancing I&D. We have eight Employee Resource Groups (ERGs) that align with our corporate objective of fostering a diverse workforce. These ERGs are organizations formed around a shared set of experiences and perspectives, and are focused on professional development, networking, recruiting, raising cultural awareness, and community involvement.
We conduct biennial employee engagement surveys to gather employee perspectives on their experience, the results of which are available to employees and our board of directors. Management analyzes findings to identify progress on previous recommendations and areas of continued opportunity.
•Capability-We strive to build depth and breadth in our skills. We drive employee development through technical training and providing opportunities for rotational moves, as well as assisting employees with obtaining and sharpening managerial skills through targeted development programs and promotional moves. Our performance management process identifies coaching and training needs.
We also have a robust succession planning practice and work each year to identify successors for positions within the company. As part of the process, quarterly sessions are held with executives to monitor and guide leadership development for our key corporate positions.
•Performance-We focus on delivering exceptional, sustainable results. We work towards retention of top talent and have advanced the effectiveness of our performance management process by embedding Our Energy in Action into the process to ensure that we drive the desired behaviors.
COMPETITION
In the Midstream segment, our crude oil and products pipelines face competition from other crude oil and products pipeline companies, major integrated oil companies, and independent crude oil gathering and marketing companies. Competition is based primarily on quality of customer service, competitive pricing and proximity to customers and market hubs. In addition, 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 natural gas markets. Principal methods of competing include economically securing the right to purchase raw natural gas for gathering systems, managing the pressure of those systems, operating efficient NGL processing plants and securing markets for the products produced. In the Chemicals segment, CPChem is ranked among the top 10 producers in many of its major product lines according to published industry sources, based on average 2020 production capacity. Petroleum products, petrochemicals and plastics are typically delivered into the worldwide commodity markets. Our Refining and M&S segments compete primarily in the United States and Europe. We are one of the largest refiners of petroleum products in the United States. Elements of competition for both our Chemicals and Refining segments include product improvement, new product development, low-cost structures, ability to run advantaged feedstocks, and efficient manufacturing and distribution systems. In the marketing portion of the business, competitive factors include product properties, 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, 2020, we held a total of 501 active patents in 22 countries worldwide, including 391 active U.S. patents. The overall profitability of any business segment is not dependent on any single patent, trademark, license or franchise.
In support of our goal to attain zero incidents, we have implemented a comprehensive Health, Safety and Environmental (HSE) management system to support consistent management of HSE risks across our enterprise. The management system is designed to ensure that personal safety, process safety, and environmental impact risks are identified, and mitigation steps are taken to reduce the risk. The management system requires periodic audits to ensure compliance with government regulations, as well as our internal requirements. Our commitment to continuous improvement is reflected in annual goal setting and performance measurement.
We are subject to various laws and government regulations concerning environmental matters and employee safety and health in the United States and other countries. In addition, various states have authority under the federal statutes and many state and local governments have adopted environmental and employee safety and health laws and regulations, some of which are similar to federal requirements. State and federal authorities may seek fines and penalties for violating these laws and regulations. The material effects of compliance with these government regulations upon our capital expenditures, earnings and competitive position are primarily associated with environmental regulations. See the environmental information contained in “Item 7. 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 2020 and those expected for 2021 and 2022.
Website Access to SEC Reports
Our Internet website address is http://www.phillips66.com. Information contained on our Internet website is not part of this Annual Report on Form 10-K.
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the U.S. Securities and Exchange Commission (SEC). Alternatively, you may access these reports at the SEC’s website at http://www.sec.gov.

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ITEM 1A. RISK FACTORS
Item 1A. RISK FACTORS
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as the value of an investment in our common stock. These risk factors do not identify all risks that we face; our operations could also be affected by factors, events or uncertainties that are not presently known to us or that we do not currently consider to present significant risks to our operations.
Risks Related to the COVID-19 Pandemic
The Coronavirus Disease 2019 (COVID-19) pandemic has resulted in a significant decrease in demand for many of our products, which has had and is expected to continue to have an adverse, and potentially materially adverse, effect on our results of operations and cash flows.
The economic, business, and oil and gas industry impacts from the COVID-19 pandemic have continued to be far reaching. Within the past year, crude oil prices have fallen dramatically to historic lows, even briefly going negative, due in part to severely reduced demand for crude oil, gasoline, jet fuel, diesel fuel, and other refined products, resulting from government-mandated travel restrictions and the curtailment of economic activity. The reduced demand and resulting oversupply of products continue to negatively impact refinery utilization rates and operating margins in our Refining business. Any prolonged period of economic stagnation, as well as depressed oil prices, may also adversely impact the financial results of our Midstream, Chemicals, and Marketing and Specialties businesses. The company’s equity affiliates, customers and other counterparties, have also been negatively impacted by the COVID-19 pandemic, and they may be unable to fulfill their obligations to us in a timely manner, or at all, which also could negatively affect our financial condition and cash flows.
The extent to which our business and operations, and those of our equity affiliates, customers and counterparties, will continue to be negatively impacted depends on the duration and scope of any existing or new travel restrictions, business and school closures, and stay at home orders. The extent of the negative impact also will depend on how quickly and to what extent economic conditions improve and normal business and operating conditions, including demand for refined petroleum products, resume.
Additionally, depending on future movements of market prices for products held in inventories, we or certain of our equity affiliates could be required to make future inventory valuation adjustments, which could affect our financial results. Any of the foregoing events or conditions, or other consequences of the COVID-19 pandemic, could significantly adversely affect our business and financial condition and the business and financial condition of our equity affiliates, as well as our customers and other counterparties.
Risks Related to Our Manufacturing and Operations
Our financial results are affected by changing commodity prices and margins for refined petroleum, petrochemical and plastics products.
Our financial results are largely affected by the relationship, or margin, between the prices at which we sell refined petroleum, petrochemical and plastics products and the prices for crude oil and other feedstocks used in manufacturing these products. Historically, margins have been volatile, and we expect they will continue to be volatile in the future.
The costs of feedstocks and the prices at which we can ultimately sell our products depend on numerous factors beyond our control, including regional and global supply and demand, which are subject to, among other things, production levels, levels of refined petroleum product inventories, productivity and growth of economies, and governmental regulation. We do not produce crude oil and must purchase all of the crude we process. The prices for crude oil and refined petroleum products can fluctuate based on global, regional and local market conditions, as well as by type and class of products, which can reduce margins and 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-based pricing provisions. We normally purchase our refinery feedstocks weeks before manufacturing and selling the refined petroleum products. We also purchase refined petroleum products produced by others for sale to our customers. Changes in prices that occur between the time we purchase feedstocks or products and when we sell the refined petroleum products could have a significant effect on our financial results.
The price of crude oil also influences prices for petrochemical and plastics products and the feedstocks used to manufacture the products. Our Chemical segment uses feedstocks that are derivatively produced in the refining of crude oil and the processing of natural gas, and those feedstock prices can fluctuate widely for a variety of reasons, including changes in worldwide energy prices and the supply and availability of the feedstocks. Due to the highly competitive nature of most of the products sold by our Chemicals segment, market position cannot necessarily be protected by product differentiation or by passing on cost increases to customers. As a result, price increases in raw materials may not correlate with changes in the prices at which petrochemical and plastics products are sold, thereby negatively affecting margins and the results of operations of our Chemicals segment.
Market conditions, including commodity prices, may impact the earnings, financial condition and cash flows of our Midstream business, including Phillips 66 Partners and DCP Midstream.
Our Midstream business is affected by the price of and demand for crude oil, natural gas and NGL, which have historically been volatile. The prices for oil, natural gas and NGL depend upon factors beyond our control, including global and local demand, production levels, imports and exports, seasonality and weather conditions, economic and political conditions domestically and internationally, and governmental regulations. Decreases in energy prices can decrease drilling activity, production rates and investments by third parties in the development of new oil and natural gas reserves. Sustained periods of low prices can also cause producers to significantly curtail or limit their oil and gas drilling operations, which could substantially delay the production and delivery of volumes of oil, natural gas and NGL.
The volume of crude oil and refined petroleum products transported or stored in our pipelines and terminal facilities depends on the demand for and availability of attractively priced crude oil and products in the areas serviced by our assets. A period of sustained low prices for crude oil or products could lead to a decline in drilling activity, production, and refining of crude oil, which would lead to a decrease in the volumes of crude oil or petroleum products transported in our pipelines and terminal facilities, negatively affecting our earnings and cash flows.
The natural gas gathered, processed, transported, sold and stored by DCP Midstream is delivered into pipelines for further delivery to end-users, including fractionation facilities. Demand for these services may be substantially reduced due to lower rates of natural gas production as a result of declining commodity prices. Commodity prices, including when ethane prices are low relative to natural gas prices, can also negatively impact throughput volumes of NGL transported, fractionated and stored by DCP Midstream. Additionally, DCP Midstream’s revenues and cash flows can increase or decrease as the price of natural gas and NGL fluctuate because of certain contractual arrangements whereby natural gas is purchased for an agreed percentage of proceeds from the sale of the residue gas and/or NGL resulting from its processing activities.
Additionally, the level of production from natural gas wells will naturally 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 level of successful drilling activity and prices of, and demand for, natural gas and crude oil, as well as producers’ desire and ability to obtain necessary permits are some of the factors that may affect new supplies of natural gas and NGL. 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.
Our operations are subject to planned and unplanned downtime, business interruptions, and operational hazards, any of which could adversely impact our ability to operate and could adversely impact our financial condition, results of operations and cash flows.
Our operating results are largely dependent on the continued operation of facilities and assets owned and operated by us and our equity affiliates. Interruptions may materially reduce productivity and thus, the profitability, of operations during and after downtime, including for planned turnarounds and scheduled maintenance activities. In the past, we and certain of our equity affiliates also have temporarily shut down facilities due to the threat of severe weather, such as hurricanes. Although we take precautions to ensure and enhance the safety of our operations and minimize the risk of disruptions, our operations are also subject to hazards inherent in chemicals, refining and midstream businesses, such as explosions, fires, refinery or pipeline releases or other incidents, power outages, labor disputes, or other natural or man-made disasters, such as acts of terrorism, including cyber intrusion. The inability to operate facilities or assets due to any of these events could significantly impair our ability to manufacture, process, store or transport products.
Any casualty occurrence involving our assets or operations could result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations and substantial losses to us. For assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. Damages resulting from an incident involving any of our assets or operations may result in our being named as a defendant in one or more lawsuits asserting potentially substantial claims or in our being assessed potentially substantial fines by governmental authorities. Should any of these risks materialize at any of our equity affiliates, it could have a material adverse effect on the business and financial condition of the equity affiliate and negatively impact their ability to make future distributions to us.
We are subject to interruptions of supply and offtake, as well as increased costs, as a result of our reliance on third-party transportation of crude oil, NGL and refined petroleum products.
We often utilize the services of third parties to transport crude oil, NGL and refined petroleum products to and from our facilities. In addition to our own operational risks, we could experience interruptions of supply or increases in costs to deliver refined petroleum products to market if the ability of the pipelines or vessels to transport crude oil or refined petroleum products is disrupted because of weather events, accidents, governmental regulations or third-party actions. A prolonged disruption of the ability of a pipeline or vessel to transport crude oil, NGL or refined petroleum products to or from one or more of our refineries or other facilities could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Competition Risks
Refining and marketing competitors that produce their own feedstocks, have more extensive retail outlets, or have greater financial resources may have a competitive advantage.
The refining and marketing industry is highly competitive with respect to both feedstock supply and refined petroleum product markets. We compete with many companies for available supplies of crude oil and other feedstocks and for outlets for our refined petroleum products. We do not produce any of our crude oil feedstocks. Some of our competitors, however, obtain a portion of their feedstocks from their own production and some have more extensive retail outlets than we have. Competitors that have their own production or extensive retail outlets (and greater brand-name recognition) are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.
Some of our competitors also have materially greater financial and other resources than we have. Such competitors have a greater ability to bear the economic risks inherent in all aspects 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.
Market demand for transportation and midstream services and the risk of overbuild could negatively impact the results of operations of our Midstream business.
We and our Midstream equity affiliates compete with other pipelines and terminals that provide similar services in the same markets as our assets. We compete on the basis of many factors, including but not limited to rates, service levels and offerings, geographic location, connectivity and reliability. Our competitors could construct new assets or redeploy existing assets in a manner that would result in more intense competition. Additionally, we could be required to increase our costs or reduce the fees we charge in order to retain our customers.
We and our equity affiliates have made and continue to make significant investments in new infrastructure projects to meet market demand. Similar investments have been made, and additional investments may be made in the future, by us, our competitors or by new entrants to the markets we serve. The success of these investments largely depends on the realization of anticipated market demand, and these projects typically require significant development periods, during which time demand for such infrastructure may change, or additional investments by competitors may be made. Any of these or other competitive forces could materially adversely affect our results of operations, financial position or cash flows, as well as our ability to pay cash distributions.
Strategic Performance and Future Growth Risks
Large capital projects can take many years to complete, and market conditions could deteriorate significantly between the project approval date and the project startup date, negatively impacting expected project returns.
Our basis for approving a large-scale capital project is the expectation that it will deliver an acceptable rate of return on the capital invested. We base these forecasted project economics on our best estimate of future market conditions including the regulatory and operating environment. Most large-scale projects take several years to complete. During this multiyear period, market conditions can change from those we forecast, and these changes could be significant. Accordingly, we may not be able to realize our expected returns from a large investment in a capital project, and this could negatively impact our results of operations, cash flows and our return on capital employed.
Plans we may have to expand existing assets or construct new assets, particularly in our Midstream segment, are subject to risks associated with societal and political pressures and other forms of opposition to the future development, transportation and use of carbon-based fuels. Such risks could adversely impact our ability to realize certain growth strategies.
Certain of our planned expenditures are based upon the assumption that societal sentiment will continue to enable, and existing regulations will remain intact to allow for, the future development, transportation and use of carbon-based fuels. A portion of our growth strategy is dependent on our ability to expand existing assets and to construct additional assets. Policy decisions relating to the production, refining, transportation and marketing of carbon-based fuels are subject to political pressures and the influence and protests of environmental and other special interest groups. For example, our Midstream segment’s growth plans include the construction or expansion of pipelines, which can involve numerous regulatory, environmental, political, and legal uncertainties, many of which are beyond our control. Our growth projects may not be completed on schedule or at the budgeted cost. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. Delays or cost increases related to capital spending programs could negatively impact our results of operations, cash flows and our return on capital employed.
Political and economic developments could affect our operations and materially reduce our profitability and cash flows.
Actions of federal, state, local and international governments through legislation or regulation, executive order, permit or other review of infrastructure or facility development, and commercial restrictions could delay projects, increase costs, limit development, or otherwise reduce our profitability both in the United States and abroad. Any such actions may affect many aspects of our operations, including:
•Requiring permits or other approvals that may impose unforeseen or unduly burdensome conditions or potentially cause delays in our operations.
•Further limiting or prohibiting construction or other activities in environmentally sensitive or other areas.
•Requiring increased capital costs to construct, maintain or upgrade equipment, facilities or infrastructure.
•Restricting the locations where we may construct facilities or requiring the relocation of facilities.
In addition, the U.S. government can prevent or restrict us from doing business in foreign countries and from doing business with entities affiliated with foreign governments, which can include state oil companies and U.S. subsidiaries of those companies. The Office of Foreign Assets Control (OFAC) of the U.S. Department of the Treasury administers and enforces economic and trade sanctions based on U.S. foreign policy and national security matters. The effect of any such OFAC sanctions could disrupt transactions with or operations involving entities affiliated with sanctioned countries, and could limit our ability to obtain optimum crude slates and other refinery feedstocks and effectively distribute refined petroleum products.
Other political and economic risks include global pandemics; financial market turmoil; economic volatility and global economic slowdown; currency exchange rate fluctuations and inflationary pressures; import or export restrictions and changes in trade regulations; acts of terrorism, war, civil unrest and other political risks; difficulties in developing, staffing and managing operations; and potentially adverse tax developments. If any of these events occur, our businesses and results of operations may be adversely affected.
Regulatory and Environmental, Climate and Weather Risks
Climate change and severe weather may adversely affect our and our joint ventures’ facilities and ongoing operations.
The potential physical effects of climate change and severe weather on our operations are highly uncertain and depend upon the unique geographic and environmental factors present. We have systems in place to manage potential acute physical risks, including those that may be caused by climate change, but if any such events were to occur, they could have an adverse effect on our assets and operations. Examples of potential physical risks include floods, hurricane-force winds, wildfires, freezing temperatures and snowstorms, as well as rising sea levels at our coastal facilities. We have incurred, and will continue to incur, costs to protect our assets from physical risks and to employ processes, to the extent available, to mitigate such risks.
Many of our facilities are located near coastal areas, as are many of CPChem’s facilities. As a result, extreme weather and rising sea levels may disrupt the ability to operate these facilities or transport crude oil, refined petroleum or petrochemical and plastics products. Extended periods of such disruption could have an adverse effect on our results of operations. We could also incur substantial costs to prevent or repair damage to these facilities. Finally, depending on the severity and duration of any extreme weather events or climate conditions, our operations may need to be modified and material costs incurred, which could materially and adversely affect our business, financial condition and results of operations.
There are certain environmental hazards and risks inherent in our operations that could adversely affect those operations and our financial results.
The operation of refineries, power plants, fractionators, pipelines, terminals and vessels is inherently subject to the risks of spills, discharges or other inadvertent releases of petroleum or hazardous substances. If any of these events had previously occurred or occurs in the future in connection with any of our refineries, pipelines or refined petroleum products terminals, or in connection with any facilities that receive our wastes or byproducts for treatment or disposal, other than events for which we are indemnified, we could be liable for all costs and penalties associated with their remediation under federal, state, local and international environmental laws or common law, and could be liable for property damage to third parties caused by contamination from releases and spills.
We 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.
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 (GHG) emissions, as they are, or may become, regulated.
•The quantity of renewable fuels that must be blended into motor fuels.
•The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous and nonhazardous wastes.
•The dismantlement and abandonment of our facilities and restoration of our properties at the end of their useful lives.
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 adoption of climate change legislation or regulation could result in increased operating costs and reduced demand for the refined petroleum products we produce.
Currently, multiple legislative and regulatory measures to address GHG and other emissions are in various phases of consideration, promulgation or implementation. These include actions to develop international, federal, regional or statewide programs, which could require reductions in our GHG or other emissions, establish a carbon tax and decrease the demand for our refined products. Requiring reductions in these emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any emissions programs, including acquiring emission credits or allotments.
For example, in 2017, the California state legislature adopted Assembly Bill 398, which provides direction and parameters on utilizing cap and trade after 2020 to meet the 40% reduction target from 1990 levels by 2030 specified in Senate Bill 32. Compliance with the cap and trade program is demonstrated through a market-based credit system. Additionally, the California Air Resources Board is now exploring the potential for additional GHG reductions by 2045 via a yet undefined carbon neutrality standard, and California’s governor has issued an Executive Order calling for a ban on the in-state sales of new cars containing internal combustion engines beginning in 2035. Other states are proposing, or have already promulgated, low carbon fuel standards or similar initiatives to reduce emissions from the transportation sector. If we are unable to pass the costs of compliance on to our customers, sufficient credits are unavailable for purchase, we have to pay a significantly higher price for credits, or if we are otherwise unable to meet our compliance obligation, our financial condition and results of operations could be adversely affected.
Regional and state climate change and air emissions goals and regulatory programs are complex, subject to change and considerable uncertainty due to a number of factors including technological feasibility, legal challenges and potential changes in federal policy. Increasing concerns about climate change and carbon intensity have also resulted in societal concerns and a number of international and national measures to limit GHG emissions. Additional stricter measures and investor pressure can be expected in the future and any of these changes may have a material adverse impact on our business or financial condition.
International climate change-related efforts, such as the 2015 United Nations Conference on Climate Change, which led to the creation of the Paris Agreement, may impact the regulatory framework of states whose policies directly influence our present and future operations. Although the United States had previously withdrawn from the Paris Agreement, it has since taken the steps necessary to rejoin, which was effective in February 2021. The U.S. climate change strategy and the impact to our industry and operations due to GHG regulation is unknown at this time.
Increased regulation of hydraulic fracturing could result in reductions or delays in U.S. production of crude oil and natural gas, which could adversely impact our results of operations.
An increasing percentage of crude oil supplied to our refineries and the crude oil and gas production of our Midstream segment’s customers is being produced from unconventional oil shale reservoirs. These reservoirs require hydraulic fracturing completion processes to release the hydrocarbons from the rock so they can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into a formation to stimulate hydrocarbon production. The EPA, as well as several state agencies, have commenced studies and/or convened hearings regarding the potential environmental impacts of hydraulic fracturing activities. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed to provide for such regulation. In addition, some communities have adopted measures to ban hydraulic fracturing in their communities. We cannot predict whether any such legislation will ever be enacted and, if so, what its provisions would be.
Any additional levels of regulation and permits required with the adoption of new laws and regulations at the federal or state level could result in our having to rely on higher priced crude oil for our refineries. The resulting increased operating costs, process prohibitions and delays could also reduce natural gas and NGL supplies, negatively affecting midstream and chemicals operations.
Compliance with the EPA’s Renewable Fuel Standard (RFS) could adversely affect our financial results.
The EPA has implemented the 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.
We are exposed to the volatility in the market price of RINs. We cannot predict the future prices of RINs. RINs prices are dependent upon a variety of factors, including EPA regulations, the availability of RINs for purchase, and levels of transportation fuels produced, which can vary significantly from quarter to quarter. If sufficient RINs are unavailable for purchase, if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA’s RFS mandates, including because the EPA mandates a blending quantity of renewable fuel that exceeds the amount that is commercially feasible to blend into motor fuel (a situation commonly referred to as “the blend wall”), our operations could be materially adversely impacted, up to and including a reduction in produced motor fuel.
Societal, technological, political and scientific developments around emissions and fuel efficiency may decrease demand for transportation fuels.
Developments aimed at reducing GHG emissions may decrease the demand or increase the cost for our transportation fuels. Attitudes toward these products and their relationship to the environment may significantly affect our effectiveness in marketing our products. Government efforts to steer the public toward non-petroleum-based fuel dependent modes of transportation may foster a negative perception toward transportation fuels or increase costs of our products, thus affecting the public’s attitude toward our major product. Advanced technology and increased use of vehicles that do not use petroleum-based transportation fuels or that are powered by hybrid engines would reduce demand for motor fuel. We may also incur increased production costs, which we may not be able to pass along to our customers.
Additionally, renewable fuels, alternative energy mandates and energy conservation efforts could reduce demand for refined petroleum products. Tax incentives and other subsidies can make renewable fuels and alternative energy more competitive with refined petroleum products than they otherwise might be, which may reduce refined petroleum product margins and hinder the ability of refined petroleum products to compete with renewable fuels.
These developments could potentially have a material adverse effect on our business, financial condition, results of operations and cash flows.
Cybersecurity and Data Privacy Risks
Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.
Our information technology and infrastructure, or information technology and infrastructure of our third-party service providers (e.g., cloud-based service providers), may be vulnerable to attacks by malicious actors or breached due to human error, malfeasance or other disruptions. 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 one or more of the following outcomes: (i) a loss of intellectual property, proprietary information, or employee, customer or vendor data; (ii) public disclosure of sensitive information; (iii) increased costs to prevent, respond to, or mitigate cybersecurity events, such as deploying additional personnel and protection technologies, training employees, and engaging third-party experts and consultants; (iv) systems interruption; (v) disruption of our business operations; (vi) remediation costs for repairs of system damage; (vii) reputational damage that adversely affects customer or investor confidence; and (viii) damage to our competitiveness, stock price, and long-term stockholder value. Although we have experienced occasional, actual or attempted breaches of our cybersecurity, we do not believe that any of these breaches has had a material effect on our business, operations or financial condition.
A breach may also result in legal claims or proceedings against us by our shareholders, employees, customers, vendors, and governmental authorities (U.S. and non-U.S.). Our infrastructure protection technologies and disaster recovery plans may not be able to prevent a technology systems breach or systems failure, which could have a material adverse effect on our financial position or results of operations. Furthermore, the continuing and evolving threat of cyberattacks has resulted in increased regulatory focus on prevention. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.
Increasing regulatory focus on privacy and cybersecurity issues and expanding laws could expose us to increased liability, subject us to lawsuits, investigations and other liabilities and restrictions on our operations that could significantly and adversely affect our business.
Along with our own data and information collected in the normal course of our business, we and our partners collect and retain certain data that is subject to specific laws and regulations. The transfer and use of this data both domestically and across international borders is becoming increasingly complex. This data is subject to governmental regulation at the federal, state, international, national, provincial and local levels in many areas of our business, including data privacy and security laws such as the European Union (EU) General Data Protection Regulation (GDPR) and the California Consumer Privacy Act (CCPA).
The GDPR applies to activities related to personal data that are conducted from an establishment in the EU. As interpretation and enforcement of the GDPR evolves, it creates a range of new compliance obligations, which could cause us to incur additional costs. Failure to comply could result in significant penalties that may materially adversely affect our business, reputation, results of operations, and cash flows.
The CCPA, which came into effect on January 1, 2020, gives California residents specific rights in relation to their personal information, requires that companies take certain actions, including notifications for security incidents and may apply to activities regarding personal information that is collected by us, directly or indirectly, from California residents. As interpretation and enforcement of the CCPA evolves, it creates a range of new compliance obligations, with the possibility for significant financial penalties for noncompliance that may materially adversely affect our business, reputation, results of operations, and cash flows.
The GDPR and CCPA, as well as other data privacy laws that may become applicable to our business, pose increasingly complex compliance challenges and potentially elevate our costs. Any failure by us to comply with these laws and regulations, including as a result of a security or privacy breach, could result in significant penalties and liabilities for us. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.
Risks Related to Our Joint Ventures and Our MLP
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 partners. Our joint venture partners may have economic, business or legal interests or goals that are inconsistent with ours or those of the joint venture, or our joint venture participants may be unable to meet their economic or other obligations, and we may be required to fulfill those obligations alone. Failure by us, or an entity in which we have a joint venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.
One of our subsidiaries acts as the general partner of a publicly traded MLP, Phillips 66 Partners, which may involve a greater exposure to legal liability than our historic business operations.
One of our subsidiaries acts as the general partner of Phillips 66 Partners, a publicly traded MLP. 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.
Indebtedness, Capital Markets and Financial Risks
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 transaction counterparties, or our customers, preventing them from meeting their obligations to us.
From time to time, our cash needs may exceed our cash from our consolidated operations and joint venture distributions, 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 that are supported by a broad syndicate of financial institutions. 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.
Investor sentiment towards climate change, fossil fuels and sustainability could adversely affect our business and the market price for our common stock.
There have been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to promote the divestment of shares of energy companies, as well as to pressure lenders and other financial services companies to limit or curtail activities with energy companies. If these efforts are successful, our stock price and our ability to access capital markets may be negatively impacted.
Members of the investment community are also increasing their focus on sustainability practices, including practices related to GHG and climate change, in the energy industry. As a result, we may face increasing pressure regarding our sustainability disclosures and practices. Additionally, members of the investment community may screen companies such as ours for sustainability performance before investing in our stock.
If we are unable to meet the sustainability standards set by these investors, we may lose investors, our stock price may be negatively impacted and our reputation may be negatively affected.
We do not insure against all potential losses, and, therefore, our business, financial condition, results of operations and cash flows could be adversely affected by unexpected liabilities and increased costs.
We maintain insurance coverage in amounts we believe to be prudent against many, but not all, potential liabilities arising from operating hazards. Uninsured liabilities arising from operating hazards, including but not limited to, explosions, fires, refinery or pipeline releases or other incidents involving our assets or operations, could reduce the funds available to us for capital and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Deterioration in our credit profile could increase our costs of borrowing money, 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 Corporation (Chevron) regarding CPChem permits Chevron to buy our 50% interest in CPChem for fair market value if we experience a change in control or if both Standard & Poor’s Financial Services LLC and Moody’s Investors Service, Inc. lower our credit ratings below investment grade and the credit rating from either rating agency remains below investment grade for 365 days thereafter, with fair market value determined by agreement or by nationally recognized investment banks. As a result of these factors, a downgrade of credit ratings could have a material adverse impact on our future operations and financial position.
The level of returns on pension and postretirement plan assets and the actuarial assumptions used for valuation purposes could affect our earnings and cash flows in future periods.
Assumptions used in determining projected benefit obligations and the expected return on plan assets for our pension plans and other postretirement benefit plans are evaluated by us based on a variety of independent sources of market information and in consultation with outside actuaries. If we determine that changes are warranted in the assumptions used, such as the discount rate, expected long-term rate of return, or health care cost trend rate, our future pension and postretirement benefit expenses and funding requirements could increase. In addition, several factors could cause actual results to differ significantly from the actuarial assumptions that we use. Funding obligations are determined based on the value of assets and liabilities on a specific date as required under relevant regulations. Future pension funding requirements, and the timing of funding payments, could be affected by legislation enacted by governmental authorities.
We may incur losses as a result of our forward contracts and derivative transactions.
We currently use commodity derivative instruments, and we expect to use them in the future. If the instruments we utilize to hedge our exposure to various types of risk are not effective, we may incur losses. Derivative transactions involve the risk that counterparties may be unable to satisfy their obligations to us. The risk of counterparty default is heightened in a poor economic environment.
Continuing Risks Related to Spin-Off from ConocoPhillips
We are subject to continuing contingent liabilities of ConocoPhillips following the separation. Further, ConocoPhillips has indemnified us for certain matters, but may not be able to satisfy its obligations to us in the future.
In connection with our separation from ConocoPhillips, we entered into a Tax Sharing Agreement 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. Additionally, the Tax Sharing Agreement provides that if the separation and certain related transactions fail to qualify as tax-free transactions, we may be responsible for any resulting tax liabilities. Our indemnification obligations under the Tax Sharing Agreement are not subject to any cap and could be significant. We also entered into an Indemnification and Release Agreement and certain other agreements in connection with the separation pursuant to which 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 are not subject to any cap and may be significant. 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. Each of these risks could negatively affect our business, results of operations and financial condition.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
Item 3. LEGAL PROCEEDINGS
Item 103 of Regulation S-K promulgated by the U.S. Securities and Exchange Commission (SEC) requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that we reasonably believe will be in excess of $300,000. The following matters are disclosed in accordance with that requirement. We do not currently believe that the eventual outcome of any matters reported, individually or in the aggregate, could have a material adverse effect on our business, financial condition, results of operations or cash flows.
Our U.S. refineries are implementing two separate consent decrees, regarding alleged violations of the Federal Clean Air Act, with the EPA, five states and one local air pollution agency. Some of the requirements and limitations contained in the decrees provide for stipulated penalties for violations. Stipulated penalties under the decrees are not automatic, but must be requested by one of the agency signatories. As part of periodic reports under the decrees or other reports required by permits or regulations, we occasionally report matters that could be subject to a request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth in SEC rules is made pursuant to these decrees based on a given reported exceedance, we will separately report that matter and the amount of the proposed penalty.
New Matters
There are no new matters to report.
Matters Previously Reported
On July 2, 2020, the South Coast Air Quality Management District (SCAQMD) issued a demand for penalties totaling $2,697,575. The penalty demand proposes to resolve 26 Notices of Violation (NOVs) issued between 2017 and 2020 for alleged violations of air permit and air pollution regulatory requirements at the Los Angeles Refinery. The company is working with SCAQMD to resolve these NOVs.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Name Position Held Age*
Greg C. Garland Chairman and Chief Executive Officer 63
Robert A. Herman Executive Vice President, Refining 61
Paula A. Johnson Executive Vice President, Legal and Government Affairs, General Counsel and Corporate Secretary
Brian M. Mandell Executive Vice President, Marketing and Commercial 57
Kevin J. Mitchell Executive Vice President, Finance and Chief Financial Officer 54
Timothy D. Roberts Executive Vice President, Midstream 59
Chukwuemeka A. Oyolu Vice President and Controller 51
* On February 24, 2021.
There are no family relationships among any of the executive officers named above or any member of our Board of Directors. 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 has been the Chairman and Chief Executive Officer of Phillips 66 since April 2012. Previously, Mr. Garland served as ConocoPhillips’ Senior Vice President, Exploration and Production-Americas from October 2010 to April 2012, and as President and Chief Executive Officer of CPChem from 2008 to 2010.
Robert A. Herman is Executive Vice President, Refining of Phillips 66, a position he has held since September 2017. Previously, Mr. Herman served as Executive Vice President, Midstream from June 2014 to September 2017.
Paula A. Johnson is Executive Vice President, Legal and Government Affairs, General Counsel and Corporate Secretary of Phillips 66, a position she has held since October 2016. Ms. Johnson previously served as Executive Vice President, Legal, General Counsel and Corporate Secretary from May 2013 to October 2016.
Brian M. Mandell is Executive Vice President, Marketing and Commercial of Phillips 66, a position he has held since March 2019. Mr. Mandell served as Senior Vice President, Marketing and Commercial from August 2018 to March 2019; Senior Vice President, Commercial from November 2016 to August 2018; and President, Global Marketing from March 2015 to November 2016.
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 Vice President, Investor Relations from September 2014 to January 2016.
Timothy D. Roberts is Executive Vice President, Midstream of Phillips 66, a position he has held since August 2018. Previously, Mr. Roberts served as Executive Vice President, Marketing and Commercial from January 2017 to August 2018 and as Executive Vice President Strategy and Business Development from April 2016 to January 2017.
Chukwuemeka A. Oyolu is Vice President and Controller of Phillips 66, a position he has held since December 2014. Mr. Oyolu previously served as General Manager, Planning and Optimization from February 2014 to December 2014 and General Manager, Finance for Refining, Marketing and Transportation from May 2012 to February 2014.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Phillips 66’s common stock is traded on the New York Stock Exchange under the symbol “PSX.” At January 29, 2021, the number of stockholders of record of our shares was 33,565, including Cede & Co. as nominee of the Depository Trust Company.
Performance Graph
The above performance graph represents cumulative total stockholder return, which assumes reinvestment of dividends, of a $100 investment in the Company’s common stock, the company’s self-constructed peer group for the year ended December 31, 2020 (the New Peer Group), the company’s self-constructed peer group for the year ended December 31, 2019 (the Old Peer Group), and the S&P 500 Index, for the five years ended December 31, 2020. We evaluate our peer group on an annual basis and believe the New Peer Group more closely aligns with the company’s size and lines of business.
The New Peer Group consists of Delek US Holdings, Inc.; Dow Inc.; HollyFrontier Corporation; LyondellBasell Industries N.V.; Magellan Midstream Partners, L.P.; Marathon Petroleum Corporation; MPLX LP; Oneok, Inc.; PBF Energy Inc.; Targa Resources Corp.; Valero Energy Corporation; Westlake Chemical Corporation; and The Williams Companies, Inc. Additionally, Andeavor was included as a peer for periods prior to its acquisition by Marathon Petroleum Corporation in October 2018.
The Old Peer Group was composed of Celanese Corporation; Delek US Holdings, Inc.; Eastman Chemical Co.; Enterprise Products Partners, LP; HollyFrontier Corporation; Huntsman Corporation; LyondellBasell Industries N.V.; Marathon Petroleum Corporation; Oneok, Inc.; PBF Energy Inc.; Targa Resources Corp.; Valero Energy Corporation; and Westlake Chemical Corporation. Additionally, Andeavor was included as a peer for periods prior to its acquisition by Marathon Petroleum Corporation in October 2018.
Issuer Purchases of Equity Securities
In March 2020, we announced that we had temporarily suspended our share repurchases. As of December 31, 2020, we had $2,514 million remaining on our existing share repurchase authorization, which has no expiration date. During 2020, prior to the temporary suspension, we repurchased an aggregate of $443 million of our common stock in open market repurchases, which equated to 5.4 million shares with a weighted average price per share of $82.23. Any future share repurchases will be made at the discretion of management and will depend on various factors including our share price, results of operations, financial condition and cash required for future business plans.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. [REMOVED AND RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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 and financial condition, and of 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.
The terms “earnings” and “loss” refer to net income (loss) attributable to Phillips 66. The terms “before-tax income” or “before-tax loss” refer to income (loss) before income taxes.
EXECUTIVE OVERVIEW AND BUSINESS ENVIRONMENT
Phillips 66 is an energy manufacturing and logistics company with midstream, chemicals, refining, and marketing and specialties businesses. At December 31, 2020, we had total assets of $54.7 billion.
Executive Overview
The COVID-19 pandemic continues to disrupt economic activities globally. Actions taken by governments to prevent the spread of the disease, including travel and business restrictions, have resulted in substantial decreases in the demand for many refined petroleum products, particularly gasoline and jet fuel. The lack of demand for petroleum products has resulted in low crude oil prices and refining margins. Accordingly, crude oil producers have shut in high cost production, and refiners have reduced crude oil processing rates.
During 2020, we took the following significant steps to enhance our liquidity in this challenged margin environment:
•Issued $3.75 billion of senior unsecured notes and borrowed a net $500 million under a term loan facility.
•Temporarily suspended our share repurchase program.
•Reduced consolidated capital spending in 2020 by more than $700 million compared with our original budget.
•Exceeded our $500 million cost reduction target in 2020.
In 2020, we reported a loss of $4.0 billion and generated $2.1 billion in cash from operating activities. We used available cash and the debt financing noted above to fund capital expenditures and investments of $2.9 billion, pay dividends of $1.6 billion, and repurchase $0.4 billion of our common stock. We ended 2020 with $2.5 billion of cash and cash equivalents and approximately $5.3 billion of total committed capacity available under our credit facilities.
Our results in 2020 reflect the adverse effects of the COVID-19 pandemic, including asset and investment impairments. These adverse effects may continue to be significant in the near term. The depth and duration of the economic consequences of the COVID-19 pandemic remain unknown. We continuously monitor our asset and investment portfolio for impairments, as well as optimization opportunities, in this challenging business environment. As such, additional impairments may be required in the future.
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. In 2020, we achieved a 0.11 total recordable incident rate-the lowest since our inception. Since we cannot control commodity prices, controlling operating expenses and overhead costs, within the context of our commitment to safety and environmental stewardship, is a high priority. Senior management actively monitors these costs. We are committed to protecting the environment and strive to reduce our environmental footprint throughout our operations. Optimizing utilization rates at our refineries through reliable and safe operations enables us to capture the value available in the market in terms of prices and margins. During 2020, our worldwide refining crude oil capacity utilization rate was 76%, mainly driven by the decrease in market demand for refined petroleum products due to negative impacts from the COVID-19 pandemic.
•Growth. A disciplined capital allocation process ensures we invest in projects that are expected to generate competitive returns. Our strategy primarily focuses on investing in growth opportunities in the Midstream and Chemicals segments. In response to the challenging market conditions caused by the COVID-19 pandemic, we reduced our 2021 capital budget to $1.7 billion. We are prioritizing sustaining capital spending and completion of in-progress growth projects, as well as advancing our investments in renewable fuels. In the third quarter of 2020, we announced Rodeo Renewed, a project to reconfigure our San Francisco Refinery in Rodeo, California, to produce renewable fuels. In 2021, we have budgeted $615 million for Midstream capital expenditures and investments, including $305 million for Phillips 66 Partners. Capital will be used to complete near-term committed and optimization projects and to maintain our integrated logistics infrastructure network. In Chemicals, our share of expected self-funded capital spending by CPChem is $410 million. CPChem plans to use its growth capital to fund expansion of its normal alpha olefins production, optimization and debottleneck opportunities in the olefins and polyolefins chains, as well as continuing development of petrochemical projects on the U.S. Gulf Coast and in Qatar. We recently formed an Emerging Energy organization. This group is charged with establishing a lower-carbon business platform that delivers attractive returns. It will focus on opportunities within our portfolio, such as Rodeo Renewed, as well as commercializing emerging energy technologies for a sustainable future.
•Returns. We plan to enhance Refining returns by increasing throughput of advantaged feedstocks, improving yields, portfolio optimization and an ongoing commitment to operating excellence. For 2021, capital in Refining will be directed toward high-return projects to enhance the yield of higher-value products and other high-return, quick-payout projects, as well as investments to competitively position the company for a lower-carbon future. M&S will continue to develop and enhance our retail network and brands in the United States and Europe.
•Distributions. We believe shareholder value is enhanced through, among other things, consistent growth of regular dividends, complemented by share repurchases. Regular dividends demonstrate the confidence our Board of Directors and management have in our capital structure and operations’ capability to generate free cash flow throughout the business cycle. In 2020, despite the challenging business environment, we maintained stable quarterly dividend distributions to shareholders and repurchased $443 million of common stock before suspending our share repurchase program in March 2020 to preserve liquidity.
•High-Performing Organization. We strive to attract, develop and retain individuals with the knowledge and skills to implement our business strategy and who support our values and culture. Throughout the company, we focus on getting results in the right way, embrace our values as a common bond, and believe success is both what we do and how we do it. We encourage collaboration throughout our company, while valuing differences, respecting diversity, and creating a great place to work. We foster an environment of learning and development through structured programs focused on enhancing functional and technical skills where employees are engaged in our business and committed to their own, as well as the company’s, success.
Business Environment
The Midstream segment includes our Transportation and NGL businesses. Our Transportation business contains fee-based operations that are not directly exposed to commodity price risk. Our NGL business contains both fee-based operations and operations that are directly impacted by NGL prices. The Midstream segment also includes our 50% equity investment in DCP Midstream. NGL prices were significantly lower in 2020, compared with 2019, due to negative economic impacts caused by the COVID-19 pandemic.
The Chemicals segment consists of our 50% equity investment in CPChem. The chemicals and plastics industry is mainly a commodity-based industry where the margins for key products are based on supply and demand, as well as cost factors. Compared with 2019, the benchmark high-density polyethylene chain margin was lower in the first three quarters of 2020, before rebounding strongly in the fourth quarter of 2020. The lower margin in the first three quarters of 2020 was mainly due to lower polyethylene sales prices. The significant margin increase in the fourth quarter of 2020 was primarily driven by tight supply caused by hurricane impacts in the Gulf Coast region and a strong global market demand.
Our Refining segment results are driven by several factors, including refining margins, refinery throughput, feedstock costs, product yields, turnaround activity, and other operating costs. The price of U.S. benchmark crude oil, West Texas Intermediate (WTI) at Cushing, Oklahoma, decreased to an average of $39.31 per barrel during 2020, compared with an average of $57.02 per barrel in 2019, due to a significant decline in global demand driven by the adverse impacts of the COVID-19 pandemic. Market crack spreads are used as indicators of refining margins and measure the difference between market prices for refined petroleum products and crude oil. During 2020, the worldwide market crack spreads were significantly lower compared with 2019, mainly driven by a sharp decline in demand for refined petroleum products resulting from the COVID-19 global pandemic.
Results for our M&S segment depend largely on marketing fuel and lubricant margins, and sales volumes of our refined petroleum and other specialty products. While M&S margins are primarily driven by market factors, largely determined by the relationship between supply and demand, marketing fuel margins, in particular, are influenced by the trend in spot prices for refined petroleum products. Generally speaking, a downward trend of spot prices has a favorable impact on marketing fuel margins, while an upward trend of spot prices has an unfavorable impact on marketing fuel margins. The global disruption caused by the COVID-19 pandemic significantly reduced demand for our refined petroleum and specialty products in 2020 compared with 2019.
RESULTS OF OPERATIONS
Consolidated Results
A summary of income (loss) before income taxes by business segment with a reconciliation to net income (loss) attributable to Phillips 66 follows:
Millions of Dollars
Year Ended December 31
2020 2019 2018
Midstream $ (9) 684 1,181
Chemicals 635 879 1,025
Refining (6,155) 1,986 4,535
Marketing and Specialties 1,446 1,433 1,557
Corporate and Other (881) (804) (853)
Income (loss) before income taxes (4,964) 4,178 7,445
Income tax expense (benefit) (1,250) 801 1,572
Net income (loss) (3,714) 3,377 5,873
Less: net income attributable to noncontrolling interests 261 301 278
Net income (loss) attributable to Phillips 66 $ (3,975) 3,076 5,595
2020 vs. 2019
Our results decreased $7,051 million in 2020, mainly reflecting:
•Lower realized refining margins and decreased refinery production.
•A goodwill impairment in our Refining segment.
•A long-lived asset impairment associated with our plan to reconfigure the San Francisco Refinery into a renewable fuels facility, which impacted our Refining and Midstream segments.
•Higher impairments of equity investments in our Midstream segment.
These decreases were partially offset by an income tax benefit recognized in 2020, compared with income tax expense recognized in 2019.
2019 vs. 2018
Our earnings decreased $2,519 million in 2019, mainly reflecting:
•Lower realized refining and marketing margins.
•Impairments associated with our equity investment in DCP Midstream.
•Decreased equity in earnings of affiliates in our Refining and Chemicals segments.
These decreases were partially offset by:
•Lower income tax expense.
•Improved results from our NGL and transportation businesses.
See the “Segment Results” section for additional information on our segment results.
Statement of Operations Analysis
2020 vs. 2019
Sales and other operating revenues and purchased crude oil and products both decreased 40% in 2020. The decreases were mainly due to lower prices and volumes for refined petroleum products and crude oil, reflecting the impact of the COVID-19 pandemic.
Equity in earnings of affiliates decreased 44% in 2020. The decrease was primarily due to lower realized refining margins and decreased refinery production at WRB, and lower margins, partially offset by higher sales volumes, at CPChem. See Chemicals segment analysis in the “Segment Results” section for additional information on CPChem.
Net gain on dispositions increased $88 million in 2020. The increase was mainly due to a gain of $84 million associated with a co-venturer’s prior-year acquisition of a 35% interest in Phillips 66 Partners’ consolidated holding company that owns an interest in Gray Oak Pipeline, LLC. See Note 27-Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information.
Operating expenses decreased 10% in 2020, primarily driven by our company-wide cost reduction initiatives in response to the COVID-19 pandemic, lower utility costs, and decreased refinery turnaround activities.
Impairments increased $3,391 million in 2020. See Note 9-Impairments, and Note 16-Fair Value Measurements, in the Notes to Consolidated Financial Statements, for additional information associated with impairments.
We had an income tax benefit of $1,250 million in 2020, compared with income tax expense of $801 million in 2019, primarily due to a net loss in 2020 versus net income in 2019. See Note 21-Income Taxes, in the Notes to Consolidated Financial Statements, for more information regarding our income taxes.
2019 vs. 2018
Sales and other operating revenues and purchased crude oil and products decreased 4% and 2%, respectively, in 2019. The decreases were mainly driven by lower prices for refined petroleum products, crude oil and NGL.
Equity in earnings of affiliates decreased 21% in 2019. The decrease was mainly due to lower margins at WRB and CPChem, partially offset by improved results from our Transportation and NGL joint venture assets. Lower equity earnings in 2019 also reflected higher goodwill and other asset impairments at DCP Midstream. See the “Segment Results” section for additional information.
Other income increased $58 million in 2019. The increase was mainly driven by trading activities not directly related to our physical business. See Note 15-Derivatives and Financial Instruments, in the Notes to Consolidated Financial Statements, for additional information associated with our commodity derivatives.
Impairments increased $853 million in 2019. The increase was driven by an $853 million before-tax impairment associated with our investment in DCP Midstream recognized in the third quarter of 2019. See Note 9-Impairments, and Note 16-Fair Value Measurements, in the Notes to Consolidated Financial Statements, for additional information associated with this impairment.
Income tax expense (benefit) decreased 49% in 2019. The decrease in income tax expense was primarily attributable to lower income before income taxes. See Note 21-Income Taxes, in the Notes to Consolidated Financial Statements, for more information regarding our income taxes.
Segment Results
Midstream
Year Ended December 31
2020 2019 2018
Millions of Dollars
Income (Loss) Before Income Taxes
Transportation $ 508 946 770
NGL and Other 441 522 305
DCP Midstream (958) (784) 106
Total Midstream $ (9) 684 1,181
Thousands of Barrels Daily
Transportation Volumes
Pipelines* 3,005 3,396 3,441
Terminals 2,971 3,315 3,153
Operating Statistics
NGL fractionated** 249 224 216
NGL extracted*** 399 417 413
* Pipelines represent the sum of volumes transported through each separately tariffed consolidated pipeline segment.
** Excludes DCP Midstream.
*** Includes 100% of DCP Midstream’s volumes.
Dollars Per Gallon
Weighted-Average NGL Price*
DCP Midstream $ 0.41 0.51 0.75
* Based on index prices from the Mont Belvieu market hub, which are weighted by NGL component mix.
The Midstream segment provides crude oil and refined petroleum product transportation, terminaling and processing services, as well as natural gas and NGL transportation, storage, fractionation, processing and marketing services, mainly in the United States. This segment includes our MLP, Phillips 66 Partners, as well as our 50% equity investment in DCP Midstream, which includes the operations of its MLP, DCP Partners.
2020 vs. 2019
Midstream’s results decreased $693 million in 2020, compared with 2019.
Results from our Transportation business decreased $438 million in 2020, compared with 2019. The decrease was primarily attributable to before-tax impairments of $300 million, decreased equity earnings, lower pipeline and terminal throughput volumes, and higher operating costs, partially offset by an $84 million before-tax gain recognized in the second quarter of 2020 associated with the Gray Oak Pipeline joint venture.
The $300 million before-tax impairments consisted of a $120 million impairment of the pipeline and terminal assets associated with the planned reconfiguration of our San Francisco Refinery into a renewable fuels facility, a $96 million impairment of Phillips 66 Partners’ equity investments in two crude oil logistics joint ventures, and an $84 million impairment of our equity investment in the canceled Red Oak Pipeline project.
See Note 9-Impairments, and Note 27-Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information regarding the impairments and the $84 million before-tax gain, respectively.
Results from our NGL and Other business decreased $81 million in 2020, compared with 2019. The decrease was mainly due to lower results from our trading activities and decreased margins, partially offset by higher export cargos and increased fractionation volumes from the startup of Frac 2 and Frac 3 in late 2020, as well as the startup of a new isomerization unit at our Lake Charles Refinery in the second half of 2019.
Results from our investment in DCP Midstream decreased $174 million in 2020, compared with 2019. The decrease was primarily due to higher impairment charges, partially offset by the recognition of a larger benefit to our equity earnings from the amortization of the basis difference associated with the impairments and DCP Midstream’s cost reduction initiatives in response to the challenging business environment. See Note 6-Investments, Loans and Long-Term Receivables, and Note 9-Impairments, in the Notes to Consolidated Financial Statements, for additional information regarding the impairments and the associated basis difference amortization related to our investment in DCP Midstream.
See the “Executive Overview and Business Environment” section for information on market factors impacting 2020 results.
2019 vs. 2018
Before-tax income from the Midstream segment decreased $497 million in 2019, compared with 2018, mainly driven by an $853 million before-tax impairment associated with our investment in DCP Midstream and lower equity earnings from DCP Midstream, partially offset by improved results from our Transportation and NGL and Other businesses.
Before-tax income from our Transportation business increased $176 million in 2019, compared with 2018. The increase was mainly driven by higher volumes and pipeline tariffs from our portfolio of consolidated and joint venture assets.
Before-tax income from our NGL and Other business increased $217 million in 2019, compared with 2018. The increase was mainly due to improved margins and volumes, primarily at the Sweeny Hub, and higher equity earnings from certain pipeline affiliates driven by higher volumes.
Before-tax income from our investment in DCP Midstream decreased $890 million in 2019, compared with 2018. The decrease was primarily due to an $853 million before-tax impairment associated with our investment in DCP Midstream and lower equity earnings driven by higher goodwill and other asset impairments at DCP Partners in 2019. See Note 6-Investments, Loans and Long-Term Receivables, Note 9-Impairments, and Note 16-Fair Value Measurements, in the Notes to Consolidated Financial Statements, for additional information regarding our investment in DCP Midstream.
Chemicals
Year Ended December 31
2020 2019 2018
Millions of Dollars
Income Before Income Taxes $ 635 879 1,025
Millions of Pounds
CPChem Externally Marketed Sales Volumes*
Olefins and Polyolefins 20,993 20,237 18,977
Specialties, Aromatics and Styrenics 4,367 4,281 4,931
25,360 24,518 23,908
* Represents 100% of CPChem’s outside sales of produced petrochemical products, as well as commission sales from equity affiliates.
Olefins and Polyolefins Capacity Utilization (percent) 99 % 97 94
The Chemicals segment consists of our 50% interest in CPChem, which we account for under the equity method. CPChem uses NGL and other feedstocks to produce petrochemicals. These products are then marketed and sold or used as feedstocks to produce plastics and other chemicals. We structure our reporting of CPChem’s operations around two primary business lines: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P business line produces and markets ethylene and other olefin products. Ethylene produced is primarily consumed within CPChem for the production of polyethylene, normal alpha olefins and polyethylene pipe. The SA&S business line manufactures and markets aromatics and styrenics products, such as benzene, cyclohexane, styrene and polystyrene. SA&S also manufactures and/or markets a variety of specialty chemical products. Unless otherwise noted, amounts referenced below reflect our net 50% interest in CPChem.
2020 vs. 2019
Before-tax income from the Chemicals segment decreased $244 million in 2020, compared with 2019. The decrease was mainly due to lower margins and decreased earnings from CPChem’s equity affiliates, partially offset by higher sales volumes and a favorable impact from lower-of-cost-or-market adjustments of inventories valued on the last-in-first-out (LIFO) basis attributable to petrochemical product price recovery in 2020.
See the “Executive Overview and Business Environment” section for information on market factors impacting CPChem’s 2020 results.
2019 vs. 2018
Before-tax income from the Chemicals segment decreased $146 million in 2019, compared with 2018. The decrease was mainly due to lower polyethylene margins attributable to additional industry capacity and slower demand growth in Asia. In addition, CPChem recorded lower-of-cost-or-market write-downs of LIFO-valued inventories during 2019, and our portion of the write-downs reduced our equity earnings from CPChem by $65 million, before-tax. The decreases were partially offset by higher polyethylene sales volumes and lower turnaround and maintenance activity during 2019.
Refining
Year Ended December 31
2020 2019 2018
Millions of Dollars
Income (Loss) Before Income Taxes
Atlantic Basin/Europe $ (1,224) 608 567
Gulf Coast (2,077) 364 1,040
Central Corridor (641) 1,338 2,817
West Coast (2,213) (324) 111
Worldwide $ (6,155) 1,986 4,535
Dollars Per Barrel
Income (Loss) Before Income Taxes
Atlantic Basin/Europe $ (7.18) 3.11 3.05
Gulf Coast (9.71) 1.24 3.55
Central Corridor (6.96) 12.95 26.50
West Coast (20.01) (2.49) 0.81
Worldwide (10.48) 2.75 6.29
Realized Refining Margins*
Atlantic Basin/Europe $ 2.17 9.33 10.32
Gulf Coast 1.85 7.42 9.48
Central Corridor 7.17 14.91 22.22
West Coast 3.43 9.18 11.20
Worldwide 3.51 9.91 12.99
* See the “Non-GAAP Reconciliations” section for a reconciliation of this non-GAAP measure to the most directly comparable measure under generally accepted accounting principles in the United States (GAAP), income (loss) before income taxes per barrel.
Thousands of Barrels Daily
Year Ended December 31
2020 2019 2018
Operating Statistics
Refining operations*
Atlantic Basin/Europe
Crude oil capacity 537 537 537
Crude oil processed 434 497 477
Capacity utilization (percent) 81 % 92 89
Refinery production 470 541 514
Gulf Coast
Crude oil capacity 769 764 752
Crude oil processed 533 725 717
Capacity utilization (percent) 69 % 95 95
Refinery production 586 804 808
Central Corridor
Crude oil capacity 530 515 493
Crude oil processed 431 498 507
Capacity utilization (percent) 81 % 97 103
Refinery production 446 518 530
West Coast
Crude oil capacity 364 364 364
Crude oil processed 279 323 343
Capacity utilization (percent) 77 % 89 94
Refinery production 301 354 373
Worldwide
Crude oil capacity 2,200 2,180 2,146
Crude oil processed 1,677 2,043 2,044
Capacity utilization (percent) 76 % 94 95
Refinery production 1,803 2,217 2,225
* Includes our share of equity affiliates.
The Refining segment refines crude oil and other feedstocks into petroleum products, such as gasoline, distillates and aviation fuels, at 13 refineries in the United States and Europe.
2020 vs. 2019
Results from the Refining segment decreased $8,141 million in 2020, compared with 2019. The decreased results in 2020 were due to:
•Lower realized refining margins and decreased refinery production. A sharp decline in demand for refined petroleum products resulting from global economic disruption caused by the COVID-19 pandemic led to lower market crack spreads and reduced refinery production in 2020. In addition, hurricane impacts contributed to the lower refinery production in the Gulf Coast region in 2020.
•A before-tax long-lived asset impairment of $910 million in the third quarter of 2020 associated with our plan to reconfigure the San Francisco Refinery into a renewable fuels facility.
•A before-tax goodwill impairment of $1,845 million in the first quarter of 2020.
Our worldwide refining crude oil capacity utilization rate was 76% and 94% in 2020 and 2019, respectively. The lower utilization rate in 2020 was primarily due to reduced refining runs driven by lower demand for refined petroleum products as a result of the COVID-19 pandemic, as well as hurricane impacts in the Gulf Coast region.
See the “Executive Overview and Business Environment” section for information on industry crack spreads and other market factors impacting this year’s results.
2019 vs. 2018
Before-tax income for the Refining segment decreased $2,549 million in 2019, compared with 2018. The decrease was primarily driven by lower realized refining margins and lower refinery production at certain refineries due to turnaround activities and unplanned downtime. In 2019, the decrease in realized refining margins was primarily due to lower feedstock advantage driven by narrowing heavy crude differentials.
Our worldwide refining crude oil capacity utilization rate was 94% and 95% in 2019 and 2018, respectively.
Marketing and Specialties
Year Ended December 31
2020 2019 2018
Millions of Dollars
Income Before Income Taxes
Marketing and Other $ 1,271 1,199 1,306
Specialties 175 234 251
Total Marketing and Specialties $ 1,446 1,433 1,557
Dollars Per Barrel
Income Before Income Taxes
U.S. $ 1.42 1.22 1.21
International 4.84 3.58 5.00
Realized Marketing Fuel Margins*
U.S. $ 1.87 1.57 1.62
International 6.34 4.90 6.87
* See the “Non-GAAP Reconciliations” section for a reconciliation of this non-GAAP measure to the most directly comparable GAAP measure, income before income taxes per barrel.
Dollars Per Gallon
U.S. Average Wholesale Prices*
Gasoline $ 1.56 2.12 2.20
Distillates 1.47 2.12 2.29
* On third-party branded refined petroleum product sales, excluding excise taxes.
Thousands of Barrels Daily
Marketing Refined Petroleum Product Sales
Gasoline 1,021 1,230 1,195
Distillates 895 1,104 975
Other 17 18 18
1,933 2,352 2,188
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.
2020 vs. 2019
Before-tax income from the M&S segment increased $13 million in 2020, compared with 2019. The increase was primarily attributable to higher realized marketing fuel margins, partially offset by lower sales volumes for refined petroleum and specialty products driven by decreased demand.
See the “Executive Overview and Business Environment” section for information on marketing fuel margins and other market factors impacting 2020 results.
2019 vs. 2018
Before-tax income from the M&S segment decreased $124 million in 2019, compared with 2018. The decrease was primarily due to lower realized marketing fuel margins, mainly driven by international marketing, partially offset by higher sales volumes.
Corporate and Other
Millions of Dollars
Year Ended December 31
2020 2019 2018
Loss Before Income Taxes
Net interest expense $ (485) (415) (459)
Corporate overhead and other (396) (389) (394)
Total Corporate and Other $ (881) (804) (853)
Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Corporate overhead and other includes general and administrative expenses, technology costs, 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.
2020 vs. 2019
Net interest expense increased $70 million in 2020, compared with 2019, primarily due to higher average debt principal balances, reflecting new debt issuances during 2020, along with decreased interest income driven by lower interest rates in 2020. See Note 12-Debt, in the Notes to Consolidated Financial Statements, for additional information on the debt issuances in 2020.
2019 vs. 2018
Net interest expense decreased $44 million in 2019, compared with 2018, mainly due to higher capitalized interest related to capital projects under development in our Midstream segment, partially offset by higher debt balances in 2019.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars, Except as Indicated
2020 2019 2018
Cash and cash equivalents $ 2,514 1,614 3,019
Net cash provided by operating activities 2,111 4,808 7,573
Short-term debt 987 547 67
Total debt 15,893 11,763 11,160
Total equity 21,523 27,169 27,153
Percent of total debt to capital* 42 % 30 29
Percent of floating-rate debt to total debt 12 % 9 11
* Capital includes total debt and total equity.
To meet our short- and long-term liquidity requirements, we use a variety of funding sources but rely primarily on cash generated from operating activities and debt financing. During 2020, we generated $2.1 billion in cash from operations and had net borrowings of $4.1 billion. We used available cash primarily for capital expenditures and investments of $2.9 billion and dividend payments on our common stock of $1.6 billion. During the first quarter of 2020, we repurchased $443 million of common stock before suspending our share repurchase program in March 2020. During 2020, cash and cash equivalents increased $900 million to $2.5 billion.
Significant Sources of Capital
Operating Activities
During 2020, cash generated by operating activities was $2,111 million, a 56% decrease compared with 2019. The decrease was primarily due to lower realized refining margins, driven by the global economic disruption caused by the COVID-19 pandemic, partially offset by lower cash income taxes paid.
During 2019, cash generated by operating activities was $4,808 million, a 37% decrease compared with 2018. The decrease was mainly driven by lower realized refining margins and decreased distributions from our equity affiliates, along with unfavorable working capital impacts, partially offset by improved results from our Transportation and NGL and Other businesses.
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 recent decline in demand for refined petroleum products has led to a decrease in refining margins. If the global economic disruption associated with the COVID-19 pandemic sustains, we expect refining margins to remain challenged in the near term, all of which could have an unfavorable impact on our future 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. However, the recent decline in demand for refined petroleum products has led to a reduction of our refinery production. If the global economic disruption associated with the COVID-19 pandemic sustains, we expect refinery production, along with marketing, transportation and terminaling volumes, to remain challenged in the near term, which could have an unfavorable impact on our future operating cash flows. Our worldwide refining crude oil capacity utilization was 76%, 94% and 95% in 2020, 2019 and 2018, respectively.
Equity Affiliate Operating Distributions
Our operating cash flows are also impacted by distribution decisions made by our equity affiliates, including CPChem, DCP Midstream and WRB. Over the three years ended December 31, 2020, our operating cash flows included aggregate distributions from our equity affiliates of $6,406 million, including $290 million from DCP Midstream, $2,490 million from CPChem and $1,230 million from WRB. We cannot control the amount or timing of future distributions from equity affiliates; therefore, future distributions are not assured.
Tax Refunds
An income tax receivable of $1.5 billion is included in the “Accounts and notes receivable” line item on our consolidated balance sheet as of December 31, 2020, which reflects tax refunds we expect to receive within the next 12 months.
Phillips 66 Partners
In 2013, we formed Phillips 66 Partners, a publicly traded MLP, to own, operate, develop and acquire primarily fee-based midstream assets.
Ownership and Restructuring Transaction
On August 1, 2019, Phillips 66 Partners completed a restructuring transaction to eliminate the incentive distribution rights (IDRs) held by us and to convert our 2% economic general partner interest into a noneconomic general partner interest in exchange for 101 million Phillips 66 Partners common units. No distributions were made for the general partner interest after August 1, 2019. At December 31, 2020, we owned 170 million Phillips 66 Partners common units, representing 74% of Phillips 66 Partners’ limited partner units.
We consolidate Phillips 66 Partners as a variable interest entity for financial reporting purposes. See Note 27-Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on why we consolidate the partnership. As a result of this consolidation, the public common and preferred unitholders’ interests in Phillips 66 Partners are reflected as noncontrolling interests of $2,219 million in our consolidated balance sheet at December 31, 2020.
Debt and Equity Financings
During the three years ended December 31, 2020, Phillips 66 Partners raised net proceeds of approximately $1 billion from the following third-party debt and equity offerings:
•In September 2019, Phillips 66 Partners received net proceeds of $892 million from the issuance of $300 million of 2.450% Senior Notes due December 2024 and $600 million of 3.150% Senior Notes due December 2029.
•In March 2019, Phillips 66 Partners entered into a senior unsecured term loan facility with a borrowing capacity of $400 million due March 20, 2020. Phillips 66 Partners borrowed an aggregate amount of $400 million under the facility during the first half of 2019, which was repaid in full in September 2019.
•Phillips 66 Partners has authorized an aggregate of $750 million under three $250 million continuous offerings of common units, or at-the-market (ATM) programs. Phillips 66 Partners completed the first two programs in June 2018 and December 2019, respectively. For the three years ended December 31, 2020, net proceeds of $303 million have been received under these programs.
Phillips 66 Partners primarily used these net proceeds to fund the cash portion of acquisitions of assets from Phillips 66 and for capital spending and investments. See Note 27-Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information regarding Phillips 66 Partners.
Transfers of Equity Interests
Gray Oak Pipeline, LLC was formed to develop and construct the Gray Oak Pipeline, which transports crude oil from the Permian and Eagle Ford to Texas Gulf Coast destinations that include Corpus Christi, Texas, and the Sweeny area, including our Sweeny Refinery. Phillips 66 Partners has a consolidated holding company that owns 65% of Gray Oak Pipeline, LLC. In December 2018, a third party acquired a 35% interest in the holding company. Because the holding company’s sole asset was its ownership interest in Gray Oak Pipeline, LLC, which was considered a financial asset, and because certain restrictions were placed on the third party’s ability to transfer or sell its interest in the holding company during the construction of the Gray Oak Pipeline, the legal sale of the 35% interest did not qualify as a sale under GAAP at that time. The Gray Oak Pipeline commenced full operations in the second quarter of 2020, and the restrictions placed on the co-venturer were lifted on June 30, 2020, resulting in the recognition of the sale under GAAP. Accordingly, at June 30, 2020, the co-venturer’s 35% interest in the holding company was recharacterized from a long-term obligation to a noncontrolling interest on our consolidated balance sheet, and the premium of $84 million previously paid by the co-venturer in 2019 was recharacterized from a long-term obligation to a gain in our consolidated statement of operations. For the year ended December 31, 2020, the co-venturer contributed an aggregate of $61 million to the holding company to fund its portion of Gray Oak Pipeline, LLC’s cash calls. Phillips 66 Partners’ effective ownership interest in Gray Oak Pipeline, LLC is 42.25% , after considering the co-venturer’s 35% interest in the consolidated holding company. See Note 6-Investments, Loans and Long-Term Receivables, for further discussion regarding Phillips 66 Partners’ investment in Gray Oak Pipeline, LLC.
Revolving Credit Facilities and Commercial Paper
Phillips 66 has a $5 billion revolving credit facility which may be used for direct bank borrowings, as support for issuances of letters of credit, and as support for our commercial paper program. We have an option to increase the overall capacity to $6 billion, subject to certain conditions. We also have the option to extend the scheduled maturity of the facility for up to two additional one-year terms after its July 30, 2024, maturity date, subject to, among other things, the consent of the lenders holding the majority of the commitments and of each lender extending its commitment. The facility is with a broad syndicate of financial institutions and contains covenants that are usual and customary for an agreement of this type, including a maximum consolidated net debt-to-capitalization ratio of 65% as of the last day of each fiscal quarter. The facility has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; and violation of covenants. Outstanding borrowings under the facility bear interest, at our option, at either: (a) the Eurodollar rate in effect from time to time plus the applicable margin; or (b) the reference rate (as described in the facility) plus the applicable margin. The facility also provides for customary fees, including commitment fees. The pricing levels for the commitment fees and interest-rate margins are determined based on the ratings in effect for Phillips 66’s senior unsecured long-term debt from time to time. Phillips 66 may at any time prepay outstanding borrowings under the facility, in whole or in part, without premium or penalty. At December 31, 2020 and 2019, no amount had been drawn under the facility.
Phillips 66 also has a $5 billion uncommitted commercial paper program for short-term working capital needs that is supported by our revolving credit facility. Commercial paper maturities are contractually limited to 365 days. At December 31, 2020 and 2019, no borrowings were outstanding under the program.
Phillips 66 Partners has a $750 million revolving credit facility which may be used for direct bank borrowings and as support for issuances of letters of credit. Phillips 66 Partners has an option to increase the overall capacity to $1 billion, subject to certain conditions. Phillips 66 Partners also has the option to extend the facility for two additional one-year terms after its July 30, 2024, maturity date, subject to, among other things, the consent of the lenders holding the majority of the commitments and of each lender extending its commitment. The facility is with a broad syndicate of financial institutions and contains covenants that are usual and customary for an agreement of this type. The facility has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; and violation of covenants. Outstanding revolving borrowings under the facility bear interest, at Phillips 66 Partners’ option, at either: (a) the Eurodollar rate in effect from time to time plus the applicable margin; or (b) the reference rate (as described in the facility) plus the applicable margin. The facility also provides for customary fees, including commitment fees. The pricing levels for the commitment fees and interest-rate margins are determined based on Phillips 66 Partners’ credit ratings in effect from time to time. Borrowings under this facility may be short-term or long-term in duration, and Phillips 66 Partners may at any time prepay outstanding borrowings under the facility, in whole or in part, without premium or penalty. At December 31, 2020, borrowings of $415 million were outstanding under this facility, compared with no borrowings outstanding at December 31, 2019. At both December 31, 2020 and 2019, $1 million in letters of credit had been issued that were supported by this facility.
We had approximately $5.3 billion and $5.7 billion of total committed capacity available under our revolving credit facilities at December 31, 2020 and 2019, respectively.
Other Debt Issuances and Financings
Senior Unsecured Notes
On November 18, 2020, Phillips 66 closed its public offering of $1.75 billion aggregate principal amount of senior unsecured notes consisting of:
•$450 million aggregate principal amount of Floating Rate Senior Notes due 2024 (the Floating Rate Notes).
•$800 million aggregate principal amount of 0.900% Senior Notes due 2024.
•$500 million aggregate principal amount of 1.300% Senior Notes due 2026.
The Floating Rate Notes will bear interest at a floating rate, reset quarterly, equal to the three-month London Interbank Offered Rate (LIBOR) plus 0.62% per year, subject to adjustment. Interest on the Senior Notes due 2024 and 2026 is payable semiannually on February 15 and August 15 of each year, commencing on February 15, 2021.
Proceeds received from the public offering of senior unsecured notes on November 18, 2020, were $1.74 billion, net of underwriters’ discounts and commissions, as well as debt issuance costs. On November 19, 2020, a portion of these proceeds were used to repay $500 million of outstanding borrowings under the term loan facility that Phillips 66 entered into in March 2020 (see the “Term Loan Facility” section below for a full description of the term loan facility). In addition, a portion of the proceeds will be used to repay the $500 million aggregate principal amount of our outstanding Floating Rate Senior Notes due February 2021. The remainder of the proceeds are being used for general corporate purposes.
On June 10, 2020, Phillips 66 closed its public offering of $1 billion aggregate principal amount of senior unsecured notes consisting of:
•$150 million aggregate principal amount of 3.850% Senior Notes due 2025.
•$850 million aggregate principal amount of 2.150% Senior Notes due 2030.
On April 9, 2020, Phillips 66 closed its public offering of $1 billion aggregate principal amount of senior unsecured notes consisting of:
•$500 million aggregate principal amount of 3.700% Senior Notes due 2023.
•$500 million aggregate principal amount of 3.850% Senior Notes due 2025.
Interest on the Senior Notes due 2023 is payable semiannually on April 6 and October 6 of each year, commencing on October 6, 2020. The Senior Notes due 2025 issued on June 10, 2020, constitute a further issuance of the Senior Notes due 2025 originally issued on April 9, 2020. The $650 million in aggregate principal amount of Senior Notes due 2025 is treated as a single class of debt securities. Interest on the Senior Notes due 2025 is payable semiannually on April 9 and October 9 of each year, commencing on October 9, 2020. Interest on the Senior Notes due 2030 is payable semiannually on June 15 and December 15 of each year, commencing on December 15, 2020.
Proceeds received from the public offerings of senior unsecured notes on June 10, 2020, and April 9, 2020, were $1,008 million and $993 million, respectively, net of underwriters’ discounts or premiums and commissions, as well as debt issuance costs. These proceeds are being used for general corporate purposes.
Term Loan Facility
On March 19, 2020, Phillips 66 entered into a $1 billion 364-day delayed draw term loan agreement (the Facility) and borrowed $1 billion under the Facility shortly thereafter. On April 6, 2020, Phillips 66 increased the size of the Facility to $2 billion, and in June 2020, the Facility was amended to extend the commitment period to September 19, 2020. We did not draw additional amounts under the Facility before the end of the commitment period or further extend the commitment period. In November 2020, we repaid $500 million of borrowings outstanding under the Facility, and the Facility was amended to extend the maturity date of the remaining $500 million outstanding borrowings from March 18, 2021, to November 20, 2023. Borrowings under the Facility bear interest at a floating rate based on either the Eurodollar rate or the reference rate, plus a margin determined by the credit rating of Phillips 66’s senior unsecured long-term debt. Phillips 66 is using the proceeds for general corporate purposes.
Availability of Debt Financing
We have a BBB+ credit rating, with a negative outlook, from Standard & Poor’s and an A3 credit rating, with a negative outlook, from Moody’s Investors Service. These investment grade ratings have served to lower our borrowing costs and facilitate access to a variety of lenders. 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 rating downgrade. Failure to maintain strong investment grade ratings could prohibit us from accessing the commercial paper market, although we would expect to be able to access funds under our liquidity facilities mentioned above.
Off-Balance Sheet Arrangements
Lease Residual Value Guarantees
In September 2020, we amended the operating lease agreement for our headquarters facility in Houston, Texas, and extended the lease term from June 2021 to September 2025. Under this agreement, we have the option, at the end of the lease term, to request to renew the lease, purchase the facility or assist the lessor in marketing it for resale. We have a residual value guarantee associated with the operating lease agreement with a maximum potential future exposure of $514 million at December 31, 2020. We also have residual value guarantees associated with railcar and airplane leases with maximum potential future payments totaling $381 million. These operating leases have remaining terms of up to nine years.
Dakota Access, LLC (Dakota Access) and Energy Transfer Crude Oil Company, LLC (ETCO)
In March 2019, a wholly owned subsidiary of Dakota Access closed an offering of $2.5 billion aggregate principal amount of senior unsecured notes, consisting of:
•$650 million aggregate principal amount of 3.625% Senior Notes due 2022.
•$1.0 billion aggregate principal amount of 3.900% Senior Notes due 2024.
•$850 million aggregate principal amount of 4.625% Senior Notes due 2029.
Dakota Access and ETCO have guaranteed repayment of the notes. In addition, Phillips 66 Partners and its coventurers in Dakota Access provided a Contingent Equity Contribution Undertaking (CECU) in conjunction with the notes offering. Under the CECU, the co-venturers may be severally required to make proportionate equity contributions to Dakota Access if there is an unfavorable final judgment in the ongoing litigation related to an easement granted by the U.S. Army Corps of Engineers (USACE) to allow the pipeline to be constructed under Lake Oahe in North Dakota. Contributions may be required if Dakota Access determines that the issues included in any such final judgment cannot be remediated and Dakota Access has or is projected to have insufficient funds to satisfy repayment of the notes. If Dakota Access undertakes remediation to cure issues raised in a final judgment, contributions may be required if any series of the notes become due, whether by acceleration or at maturity, during such time, to the extent Dakota Access has or is projected to have insufficient funds to pay such amounts. At December 31, 2020, Phillips 66 Partners’ share of the maximum potential equity contributions under the CECU was approximately $631 million and the aggregate book value of Phillips 66 Partners’ investments in Dakota Access and ETCO was $577 million.
In March 2020, the trial court presiding over this litigation ordered the USACE to prepare an Environmental Impact Statement (EIS) and requested additional information to enable a decision on whether the Dakota Access Pipeline should be shut down while the EIS is being prepared. In July 2020, the trial court ordered the Dakota Access Pipeline to be shut down and emptied of crude oil within 30 days and that the pipeline should remain shut down pending the preparation of the EIS by the USACE, which the USACE has indicated is expected to take approximately 13 months. Dakota Access filed an appeal and a request for a stay of the order, which was granted. In January 2021, the appellate court affirmed the trial court’s order that: (1) vacated Dakota Access’s easement under Lake Oahe, and (2) directed the USACE to prepare an EIS. The appellate court did not affirm the trial court’s order that the Dakota Access Pipeline be shut down and emptied of crude oil. However, the appellate court acknowledged the precise consequences of the vacated easement remain uncertain. Since the pipeline is now an encroachment, the USACE could seek a shutdown of the pipeline during the preparation of the EIS. Alternatively, the trial court could again issue an injunction that the pipeline be shut down, assuming it makes all findings necessary for injunctive relief. A status hearing is scheduled for April 9, 2021, at which time the parties will discuss the appellate court’s decision and how the USACE plans to proceed given the vacating of the easement.
If the pipeline is required to cease operations pending the preparation of the EIS, and should Dakota Access and ETCO not have sufficient funds to pay ongoing expenses, Phillips 66 Partners also could be required to support its share of the ongoing expenses, including scheduled interest payments on the notes of approximately $25 million annually, in addition to the potential obligations under the CECU.
Gray Oak Pipeline, LLC
Gray Oak Pipeline, LLC had a third-party term loan facility with a borrowing capacity of $1,379 million, inclusive of accrued interest. Phillips 66 Partners and its co-venturers provided a guarantee through an equity contribution agreement requiring proportionate equity contributions to Gray Oak Pipeline, LLC up to the total outstanding loan amount, plus any additional accrued interest and associated fees, if Gray Oak Pipeline, LLC defaulted on certain of its obligations thereunder. In September 2020, Gray Oak Pipeline, LLC fully repaid the outstanding balance of the term loan facility, and the associated equity contribution agreement was terminated.
See Note 13-Guarantees, in the Notes to Consolidated Financial Statements, for additional information on our guarantees.
Capital Requirements
Capital Expenditures and Investments
For information about our capital expenditures and investments, see the “Capital Spending” section below.
Debt Financing
Our debt balance at December 31, 2020, was $15.9 billion and our total debt-to-capital ratio was 42%.
See Note 12-Debt, in the Notes to Consolidated Financial Statements, for our annual debt maturities over the next five years and more information on debt repayments.
Debt Incurred During 2020
As noted in “Significant Sources of Capital,” Phillips 66 received approximately $4.7 billion in proceeds from debt issuances during 2020, while repaying approximately $1.0 billion of debt. Phillips 66 Partners had net borrowings of $415 million under its revolving credit facility during 2020. The net increase in debt of $4.1 billion reflects our response to the COVID-19 pandemic’s negative impacts on our operating cash flows. As economic conditions improve and our operating cash flows return to more typical levels, we will continue to prioritize funding sustaining capital expenditures and the company’s dividend. After these cash flow needs, we expect to prioritize repayment of debt, with an objective of maintaining our investment grade credit ratings and reducing our debt to pre-pandemic levels. We intentionally structured the maturities and call options of our debt issued in 2020 to facilitate these objectives. Additionally, restarting our share repurchase program remains a priority once operating cash flows exceed amounts needed to fulfill the other priorities stated above and assuming our shares are trading below intrinsic value.
Joint Venture Loans
During 2020, we and our co-venturer provided member loans to WRB. At December 31, 2020, our share of the loan balance was $277 million. The need for additional loans to WRB in 2021, as well as WRB’s repayment schedule, will depend on market conditions.
Dividends
On February 10, 2021, our Board of Directors declared a quarterly cash dividend of $0.90 per common share, payable March 1, 2021, to holders of record at the close of business on February 22, 2021. We expect that our Board of Directors will continue to declare quarterly dividends in 2021.
Share Repurchases
Since July 2012, our Board of Directors has authorized an aggregate of $15 billion of repurchases of our outstanding common stock. The authorizations do not have expiration dates. The share repurchases are expected to be funded primarily through available cash. We are not obligated to repurchase any shares of common stock pursuant to these authorizations and may commence, suspend or terminate repurchases at any time. Since the inception of our share repurchase program in 2012, we have repurchased 159 million shares at an aggregate cost of $12.5 billion. Shares of stock repurchased are held as treasury shares. We suspended share repurchases in mid-March 2020 to preserve liquidity in response to the global economic disruption caused by the COVID-19 pandemic.
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2020:
Millions of Dollars
Payments Due by Period
Total Up to
1 Year Years
2-3 Years
4-5 After
5 Years
Debt obligations (a) $ 15,716 965 3,000 2,700 9,051
Finance lease obligations 264 16 30 32 186
Software obligations 19 6 10 3 -
Total debt 15,999 987 3,040 2,735 9,237
Interest on debt 7,434 568 998 866 5,002
Operating lease obligations 1,372 406 455 240 271
Purchase obligations (b) 76,887 28,946 9,742 8,099 30,100
Other long-term liabilities (c)
Asset retirement obligations 309 9 40 29 231
Accrued environmental costs 427 70 131 65 161
Repatriation income tax liability (d) 88 9 27 52 -
Total $ 102,516 30,995 14,433 12,086 45,002
(a)For additional information, see Note 12-Debt, in the Notes to Consolidated Financial Statements.
(b)Represents any agreement to purchase goods or services that is enforceable, legally binding and specifies all significant terms. We expect these purchase obligations will be fulfilled with operating cash flows in the applicable maturity period. The majority of the purchase obligations are market-based contracts, including exchanges and futures, for the purchase of products such as crude oil and raw NGL. The products are used to supply our refineries and fractionators and optimize our supply chain. Product purchase commitments with third parties totaled $29,551 million. Related party purchase commitments totaled $31,729 million and included purchases from CPChem, DCP Midstream and other equity affiliates.
Purchase obligations of $4,027 million are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and product terminals, to transport, process, treat, and store products. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned facilities where we are the operator.
(c)Excludes pensions and unrecognized income tax benefits. From 2021 through 2025, we expect to contribute an average of $125 million per year to our qualified and nonqualified pension and other postretirement benefit plans in the United States and an average of $30 million per year to our non-U.S. plans. The U.S. five-year average consists of approximately $40 million for 2021 and $145 million per year for the remaining four years. Our minimum funding in 2021 is expected to be $40 million in the United States and $30 million outside the United States.
This amount also excludes unrecognized tax benefits of $56 million because the ultimate disposition and timing of any tax payments to be made with regard to such amounts are not reasonably estimable or the amounts relate to potential refunds. This amount also excludes interest of $5 million. Although unrecognized tax benefits are not a contractual obligation, they represent potential demands on our liquidity.
(d)We elected to pay the one-time deemed repatriation income tax on foreign-sourced earnings, recognized as a result of the Tax Act enacted in December 2017, in installments over eight years beginning in 2018. The amount represents the remaining income tax liability.
Capital Spending
Our capital expenditures and investments represent consolidated capital spending. Our adjusted capital spending is a non-GAAP financial measure that demonstrates our net share of capital spending, and reflects an adjustment for the portion of our consolidated capital spending funded by certain joint venture partners.
Millions of Dollars
Budget 2020 2019 2018
Capital Expenditures and Investments
Midstream $ 615 1,747 2,292 1,548
Chemicals - - - -
Refining 776 816 1,001 826
Marketing and Specialties 116 173 374 125
Corporate and Other 166 184 206 140
Total Capital Expenditures and Investments 1,673 2,920 3,873 2,639
Less: capital spending funded by certain joint venture partners*
5 61 423 -
Adjusted Capital Spending $ 1,668 2,859 3,450 2,639
Selected Equity Affiliates**
DCP Midstream $ 55 119 472 484
CPChem 410 284 382 339
WRB 242 175 175 156
$ 707 578 1,029 979
* Included in the Midstream segment.
** Our share of joint venture’s capital spending.
Midstream
Capital spending in our Midstream segment during the three-year period ended December 31, 2020, included:
•Continued development of additional Gulf Coast fractionation capacity. During 2020, Phillips 66 commenced operations of two new NGL fractionators (Frac 2 and Frac 3) at the Sweeny Hub in Texas.
•Contributions by Phillips 66 Partners to fund the Gray Oak Pipeline project and South Texas Gateway Terminal development activities.
•Construction activities on Phillips 66 Partners’ C2G Pipeline that will connect its Clemens Caverns storage facility to petrochemical facilities in Gregory, Texas.
•Contributions to joint ventures to develop and construct crude oil pipeline systems, including the Liberty Pipeline system.
•Construction activities to increase storage and export capacity at our Beaumont Terminal.
•Construction of Phillips 66 Partners’ Sweeny to Pasadena refined petroleum product pipeline.
•Construction of Phillips 66 Partners’ new isomerization unit at the Lake Charles Refinery.
•Contributions to Bayou Bridge Pipeline, LLC, a Phillips 66 Partners’ 40 percent-owned joint venture, for the construction of a pipeline from Nederland, Texas, to Lake Charles, Louisiana, and a pipeline segment from Lake Charles to St. James, Louisiana.
•Spending associated with other return, reliability and maintenance projects in our Transportation and NGL businesses.
In March 2020, the development and construction of our Red Oak Pipeline system and Sweeny Frac 4, as well as Phillips 66 Partners’ Liberty Pipeline system projects, were deferred as a result of the challenging business environment. In the third quarter of 2020, the Red Oak Pipeline project was canceled. We plan to resume construction of Sweeny Frac 4 in the second half of 2021.
During the three-year period ended December 31, 2020, DCP Midstream’s self-funded capital expenditures and investments were $2.1 billion on a 100% basis. Capital spending during this period was primarily for expansion projects and maintenance capital expenditures for existing assets. Expansion projects included construction of the Latham II offload facilities, the Cheyenne Connector, and the Mewbourn 3 and O’Connor 2 plants, as well as investments in the Sand Hills, Southern Hills and Gulf Coast Express pipeline joint ventures.
Chemicals
During the three-year period ended December 31, 2020, CPChem had a self-funded capital program that totaled $2.0 billion on a 100% basis. The capital spending was primarily for the development of U.S. Gulf Coast petrochemical projects, debottlenecking projects on existing assets, and the development of a petrochemicals complex in Qatar.
Refining
Capital spending for the Refining segment during the three-year period ended December 31, 2020, was $2.6 billion, primarily for refinery upgrade projects to enhance the yield of high-value products, renewable diesel projects, improvements to the operating integrity of key processing units, and safety-related projects.
Key projects completed during the three-year period included:
•Installation of facilities to improve clean product yield at the Bayway and Lake Charles refineries, as well as the jointly owned Borger and Wood River refineries.
•Installation of facilities to improve product value at the Bayway and Sweeny refineries.
•Installation of facilities to improve processing of advantaged crude at the Lake Charles refinery.
•Installation of facilities to comply with the EPA Tier 3 gasoline regulations at the Bayway and Ferndale refineries.
Marketing and Specialties
Capital spending for the M&S segment during the three-year period ended December 31, 2020, was primarily for an investment in a U.S. West Coast retail marketing joint venture, and the acquisition, development and enhancement of retail sites in Europe.
Corporate and Other
Capital spending for Corporate and Other during the three-year period ended December 31, 2020, was primarily for information technology and facilities.
2021 Budget
Our 2021 capital budget is $1.7 billion, including $305 million of Phillips 66 Partners’ planned capital spending. Our projected $1.7 billion capital budget excludes our portion of planned capital spending by our major joint ventures DCP Midstream, CPChem and WRB totaling $707 million. Phillips 66 Partners’ planned capital spending of $305 million includes $5 million of capital expected to be funded by a joint venture partner.
The Midstream capital budget is $615 million, of which $5 million is expected to be funded by a joint venture partner. The Midstream growth capital budget is directed toward completing near-term committed and optimization projects, including the construction of Sweeny Frac 4 and the completion of the C2G Pipeline. Sustaining capital will be used to enhance asset integrity and reliability. Refining’s capital budget of $776 million includes $521 million of sustaining capital for reliability, safety and environmental projects. The Refining budget includes $255 million for high-return, quick-payout projects to enhance margins by improving clean product yields and reducing feedstock costs, as well as investments to competitively position the company for a lower carbon future. The Refining budget also includes pre-construction engineering and design costs related to the company’s plans to reconfigure the San Francisco Refinery in Rodeo, California, to produce renewable fuels. The M&S capital budget of $116 million primarily reflects the development and improvement of our international retail sites. The Corporate and Other capital budget of $166 million will primarily fund digital transformation projects, including a new enterprise resource planning system.
Contingencies
A number of lawsuits involving a variety of claims that arose in the ordinary course of business have been filed against us or are subject to indemnifications provided by us. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for financial recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other potentially responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Legal and Tax Matters
Our legal and tax matters are handled by our legal and tax organizations. These organizations apply their knowledge, experience and professional judgment to the specific characteristics of our cases and uncertain tax positions. We employ a litigation management process to manage and monitor the legal proceedings. 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 international, federal, state and local environmental laws and regulations. Among the most significant of these international and federal environmental laws and regulations are the:
•U.S. Federal Clean Air Act, which governs air emissions.
•U.S. Federal Clean Water Act, which governs discharges into water bodies.
•European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH), which governs production, marketing and use of chemicals.
•U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur.
•U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage and disposal of solid waste.
•U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories to local emergency planning committees and response departments.
•U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines as well as owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States.
•European Union Trading Directive resulting in the European Union Emissions Trading Scheme (EU ETS), which uses a market-based mechanism to incentivize the reduction of greenhouse gas (GHG) emissions, as well as the United Kingdom Emissions Trading Scheme (UK ETS), which will replace the EU ETS in the United Kingdom beginning April 30, 2021.
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.
Other foreign countries and many states where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of developing infrastructure and marketing and transporting products across state and international borders. For example, in California the South Coast Air Quality Management District (SCAQMD) approved amendments to the Regional Clean Air Incentives Market (RECLAIM) that became effective in 2016, which require a phased reduction of nitrogen oxide emissions through 2022, affecting refineries in the Los Angeles metropolitan area. In 2017, SCAQMD required additional nitrogen dioxide emissions reductions through 2025 and is now promulgating new regulations to replace the RECLAIM program with a traditional command and control regulatory regime.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emissions compliance and remediation obligations in the United States.
An example of this in the fuels area is the Energy Independence and Security Act of 2007 (EISA). It requires fuel producers and importers to provide additional renewable fuels for transportation motor fuels and stipulates a mix of various types. RINs form the mechanism used by the EPA to record compliance with the Renewable Fuel Standard. If an obligated party has more RINs than it needs to meet its obligation, it may sell or trade the extra RINs, or instead choose to “bank” them for use the following year. We have met the 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 2020 compliance year, the EPA set volumes of advanced and total renewable fuels required to be blended into transportation fuels at higher levels than in previous years; it is uncertain if these increased obligations will be achievable by fuel producers and shippers without drawing on the RIN bank. Additionally, we may experience a decrease in demand for refined petroleum products due to the regulatory program as currently promulgated. This program continues to be the subject of possible Congressional review and re-promulgation in revised form, and the EPA’s regulations pertaining to the 2019 and 2020 compliance years are subject to legal challenge, further creating uncertainty regarding renewable fuel volume requirements and obligations. Uncertainty also exists surrounding compliance year 2021, as the EPA has not yet promulgated standards for that compliance year, although we expect the EPA to follow its past practice of using its authority to reduce the statutorily required volumes under EISA of advanced and total renewable fuels required to be blended into transportation fuels. Compliance with the regulation has been further complicated as the market for RINs has been the subject of fraudulent third-party activity, and it is possible that some RINs that we have purchased may be determined to be invalid. Should that occur, we could incur costs to replace those fraudulent RINs. Although the cost for replacing any fraudulently marketed RINs is not reasonably estimable at this time, we would not expect such costs to have a material impact on our results of operations or financial condition.
We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous previously and currently owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states have adopted cleanup criteria for methyl tertiary-butyl ether (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, 2019, we reported that we had been notified of potential liability under CERCLA and comparable state laws at 27 sites within the United States. During 2020, we were notified of one previously resolved site that was returned to active status and three sites that were deemed resolved and closed, leaving 25 unresolved sites with potential liability at December 31, 2020.
For the majority of Superfund sites, our potential liability will be 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 the 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 $610 million in 2020 and are expected to be approximately $720 million per year in 2021 and 2022. Capitalized environmental costs were $131 million in 2020 and are expected to be approximately $105 million and $140 million, in 2021 and 2022, respectively. These amounts do not include capital expenditures made for other purposes that have an indirect benefit on environmental compliance.
Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a business combination, which we record on a discounted basis).
Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where our generated waste was disposed. We also have accrued for a number of sites we identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in certain of our operations and products, and there can be no assurance that those costs and liabilities will not be material. However, we currently do not expect any material adverse effect on our results of operations or financial position as a result of compliance with current environmental laws and regulations.
Climate Change
There has been a broad range of proposed or promulgated state, national and international laws focusing on GHG emissions reduction, including various regulations proposed or issued by the EPA. These proposed or promulgated laws apply or could apply in states and/or countries where we have interests or may have interests in the future. Laws regulating GHG emissions continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws potentially could have a material impact on our results of operations and financial condition as a result of increasing costs of compliance, lengthening project implementation and agency reviews, or reducing demand for certain hydrocarbon products. Examples of legislation or precursors for possible regulation that do or could affect our operations include:
•EU ETS, which is part of the European Union’s policy to combat climate change and is a key tool for reducing industrial GHG emissions. EU ETS impacts factories, power stations and other installations across all EU member states. As a result of the United Kingdom’s exit from the European Union (BREXIT), those types of entities in the United Kingdom will be subject to the UK ETS, rather than the EU ETS, beginning April 30, 2021.
•California’s Senate Bill No. 32, which requires reduction of California's GHG emissions to 40% below the 1990 emission level by 2030, and Assembly Bill 398, which extends the California GHG emission cap and trade program through 2030. Other GHG emissions programs in the western U.S. states have been enacted or are under consideration or development, including amendments to California's Low Carbon Fuel Standard, Oregon's Low Carbon Fuel Standard, and Washington's carbon reduction programs.
•The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S. Ct. 1438 (2007), confirming that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under the Federal Clean Air Act.
•The EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that triggers regulation of GHGs under the Clean Air Act. These collectively may lead to more climate-based claims for damages, and may result in longer agency review time for development projects to determine the extent of potential climate change.
•The 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. The EPA commenced rulemaking in 2017 to rescind the Clean Power Plan and, in August 2018, the EPA proposed the Affordable Clean Energy (ACE) rule as its replacement. On January 19, 2021, the U.S. Court of Appeals for the District of Columbia invalidated the ACE rule and remanded the matter to the EPA, essentially restarting this rulemaking process.
•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. Phase II was undertaken from 2008 through 2012, and Phase III ran from 2013 through to 2020. Phase IV runs from January 1, 2021 through 2030 and sectors covered under the ETS must reduce their GHG emissions by 43% compared to 2005 levels. From April 30, 2021, the United Kingdom will no longer be part of the EU ETS and has launched the UK ETS. Phillips 66 has assets that are subject to the EU ETS and assets that will be subject to the UK ETS.
From November 30 to December 12, 2015, more than 190 countries, including the United States, participated in the United Nations Climate Change Conference in Paris, France. The conference culminated in what is known as the “Paris Agreement,” which, upon certain conditions being met, entered into force on November 4, 2016. The Paris Agreement establishes a commitment by signatory parties to pursue domestic GHG emission reductions. In 2017, President Trump announced his intention to withdraw the United States from the Paris Agreement and that withdrawal became effective on November 4, 2020. On January 20, 2021, President Biden signed the “Acceptance on Behalf of the United States of America,” which allows the United States to rejoin the Paris Agreement. The United States officially rejoined the Paris Agreement in February 2021, which could lead to additional GHG emission reduction requirements for sources in the United States.
In the United States, some additional form of regulation is likely to be forthcoming in the future at the state or federal levels with respect to GHG emissions. Such regulation could take any of several forms that may result in additional financial burden 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.
Compliance with changes in laws and regulations that create a GHG emission trading program, GHG reduction requirements or carbon taxes could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources.
An example of one such program is California’s cap and trade program, which was promulgated pursuant to the State’s Global Warming Solutions Act. The program had been limited to certain stationary sources, which include our refineries in California, but beginning in January 2015 was expanded to include emissions from transportation fuels distributed in California. Inclusion of transportation fuels in California’s cap and trade program as currently promulgated has increased our cap and trade program compliance costs. The ultimate impact on our financial performance, either positive or negative, from this and similar programs, will depend on a number of factors, including, but not limited to:
•Whether and to what extent legislation or regulation is enacted.
•The nature of the legislation or regulation, such as a cap and trade system or a tax on emissions.
•The GHG reductions required.
•The price and availability of offsets.
•The demand for, and amount and allocation of allowances.
•Technological and scientific developments leading to new products or services.
•Any potential significant physical effects of climate change, such as increased severe weather events, changes in sea levels and changes in temperature.
•Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products and services.
We consider and take into account anticipated future GHG emissions in designing and developing major facilities and projects, and implement energy efficiency initiatives to reduce GHG emissions. Data on our GHG emissions, legal requirements regulating such emissions, and the possible physical effects of climate change on our coastal assets are incorporated into our planning, investment, and risk management decision-making. We are working to continuously improve operational and energy efficiency through resource and energy conservation throughout our operations.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1-Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Some of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussion of critical accounting estimates, along with the discussion of contingencies in this report, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.
Impairment of Long-Lived Assets and Equity Method Investments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future expected cash flows. If the sum of the undiscounted expected future before-tax cash flows of an asset group is less than the carrying value, including applicable liabilities, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined using one or more of the following methods: the present value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants; a market multiple for similar assets; historical market transactions including similar assets, adjusted using principal market participant assumptions when necessary; or replacement cost adjusted for physical deterioration and economic obsolescence. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments, including future volumes, commodity prices, operating costs, margins, discount rates and capital project decisions, considering all available information at the date of review.
Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment when there are indicators of a loss in value, such as a lack of sustained earnings capacity or a current fair value less than the investment’s carrying amount. When it is determined that an indicated impairment is other than temporary, a charge is recognized for the difference between the investment’s carrying value and its estimated fair value. When determining whether a decline in value is other than temporary, management considers factors such as the duration 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 observed market earnings multiples of comparable companies, if appropriate. Different assumptions could affect the timing and the amount of an impairment of an investment in any period.
See Note 9-Impairments, in the Notes to Consolidated Financial Statements, for information about significant impairments recorded in 2020 and 2019.
Asset Retirement Obligations
Under various contracts, permits and regulations, we have legal obligations to remove tangible equipment and restore the land at the end of operations at certain operational sites. Our largest asset removal obligations involve asbestos abatement at refineries. Estimating the timing and cost of future asset removals is difficult. Most of these removal obligations are many years, or decades, in the future, and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.
Environmental Costs
In addition to asset retirement obligations discussed above, we have certain obligations to complete environmental-related projects. These projects are primarily related to cleanup at domestic refineries, underground storage sites and nonoperated sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, timing and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties.
Intangible Assets and Goodwill
At December 31, 2020, we had $725 million of intangible assets that we have determined to have indefinite useful lives, and therefore do not amortize. The judgmental determination that an intangible asset has an indefinite useful life is continuously evaluated. If, due to changes in facts and circumstances, management determines these intangible assets have finite useful lives, amortization will commence at that time on a prospective basis. As long as these intangible assets are determined to have indefinite lives, they will be subject to at least annual impairment tests that require management’s judgment of their estimated fair value.
At December 31, 2020, we had $1.4 billion of goodwill recorded in conjunction with past business combinations. Goodwill is not amortized. Instead, goodwill is subject to at least annual tests for impairment at a reporting unit level. A reporting unit is an operating segment or a component that is one level below an operating segment, and it is determined primarily based on the manner in which the business is managed.
We perform our annual goodwill impairment test using a qualitative assessment and a quantitative assessment, if one is deemed necessary. As part of our qualitative assessment, we evaluate relevant events and circumstances that could affect the fair value of our reporting units, including macroeconomic conditions, overall industry and market considerations and regulatory changes, as well as company-specific market metrics, performance and events. The evaluation of company-specific events and circumstances includes evaluating changes in our stock price and cost of capital, actual and forecasted financial performance, as well as the effect of significant asset dispositions. If our qualitative assessment indicates it is likely the fair value of a reporting unit has declined below its carrying value (including goodwill), a quantitative assessment is performed.
When a quantitative assessment is performed, management applies judgment in determining the estimated fair values of the reporting units because quoted market prices for our reporting units are not available. Management uses available information to make this fair value determination, including estimated future cash flows, cost of capital, observed market earnings multiples of comparable companies, our common stock price and associated total company market capitalization.
See Note 9-Impairments, and Note 16-Fair Value Measurements, in the Notes to Consolidated Financial Statements, for additional information regarding the goodwill impairment we recorded in the first quarter of 2020.
We completed our annual qualitative assessment of goodwill as of October 1, 2020, and concluded that the fair values of our reporting units exceeded their respective carrying values (including goodwill). A decline in the estimated fair value of one or more of our reporting units in the future could result in an impairment. As such, we continue to monitor for indicators of impairment until our next annual impairment assessment is performed.
Tax Assets and Liabilities
Our operations are subject to various taxes, including federal, state and foreign income taxes, property taxes, and transactional taxes such as excise, sales and use, value-added 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 reasonably estimable. Actual incurred tax liabilities can vary from our estimates for a variety of reasons, including different interpretations of tax laws and regulations and different assessments of the amount of tax due.
In determining our income tax expense (benefit), we assess the likelihood our deferred tax assets will be recovered through future taxable income. Valuation allowances reduce deferred tax assets to an amount that will, more likely than not, be realized. Judgment is required in estimating the amount of valuation allowance, if any, that should be recorded against our deferred tax assets. Based on our historical taxable income, our expectations for the future, and available tax-planning strategies, we expect our net deferred tax assets will more likely than not be realized as offsets to reversing deferred tax liabilities and as reductions to future taxable income. If our actual results of operations differ from such estimates or our estimates of future taxable income change, the valuation allowance may need to be revised.
New tax laws and regulations, as well as changes to existing tax laws and regulations, are continuously being proposed or promulgated. The implementation of future legislative and regulatory tax initiatives could result in increased income tax liabilities that cannot be predicted at this time.
Projected Benefit Obligations
Calculation of the projected benefit obligations for our defined benefit pension and postretirement plans impacts the obligations on the balance sheet and the amount of benefit expense in the statement of operations. The actuarial calculation of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future interest rates, future health care cost-trend rates, and rates of utilization of health care services by retirees. We engage outside actuarial firms to assist in the calculation of these projected benefit obligations and company contribution requirements due to the specialized nature of these calculations. As financial accounting rules and the pension plan funding regulations promulgated by governmental agencies have different objectives and requirements, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A one percentage-point decrease in the discount rate assumption used for the plan obligation would increase annual benefit expense by an estimated $70 million, while a one percentage-point decrease in the return on plan assets assumption would increase annual benefit expense by an estimated $40 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.
The expected weighted-average long-term rate of return for worldwide pension plan assets was approximately 6% for both 2020 and 2019, while the actual weighted-average rate of return was 12% in 2020 and 18% in 2019. For the past ten years, our actual weighted-average rate of return for worldwide pension plan assets was 9%.
GUARANTOR FINANCIAL INFORMATION
At December 31, 2020, Phillips 66 had $11 billion of senior unsecured notes outstanding guaranteed by Phillips 66 Company, a direct, wholly owned operating subsidiary of Phillips 66. Phillips 66 conducts substantially all of its operations through subsidiaries, including Phillips 66 Company, and those subsidiaries generate substantially all of its operating income and cash flow. The guarantees are (1) unsecured obligations of Phillips 66 Company, (2) rank equally with all of Phillips 66 Company’s other unsecured and unsubordinated indebtedness, and (3) are full and unconditional.
Summarized financial information of Phillips 66 and Phillips 66 Company (the Obligor Group) is presented on a combined basis. Intercompany transactions among the members of the Obligor Group have been eliminated. The financial information of non-guarantor subsidiaries has been excluded from the summarized financial information. Significant intercompany transactions and receivable/payable balances between the Obligor Group and non-guarantor subsidiaries are presented separately in the summarized financial information.
The summarized results of operations for the year ended December 31, 2020, and the summarized financial position at December 31, 2020, for the Obligor Group on a combined basis were:
Summarized Combined Statement of Operations Millions of Dollars
Sales and other operating revenues $ 47,950
Revenues and other income-non-guarantor subsidiaries 3,211
Purchased crude oil and products-third parties 32,187
Purchased crude oil and products-related parties 6,433
Purchased crude oil and products-non-guarantor subsidiaries 8,690
Impairments 2,777
Loss before income taxes (5,111)
Net loss (3,882)
Summarized Combined Balance Sheet Millions of Dollars
Accounts and notes receivable-third parties $ 4,060
Accounts and notes receivable-related parties 804
Due from non-guarantor subsidiaries, current 288
Total current assets 8,965
Investments and long-term receivables 9,229
Net properties, plants and equipment 12,815
Goodwill 1,047
Due from non-guarantor subsidiaries, noncurrent 6,173
Other assets associated with non-guarantor subsidiaries 2,870
Total noncurrent assets 34,034
Total assets 42,999
Due to non-guarantor subsidiaries, current $ 2,203
Total current liabilities 7,938
Long-term debt 11,330
Due to non-guarantor subsidiaries, noncurrent 9,316
Total noncurrent liabilities 26,044
Total liabilities 33,982
Total equity 9,017
Total liabilities and equity 42,999
NON-GAAP RECONCILIATIONS
Refining
Our realized refining margins measure the difference between (a) sales and other operating revenues derived from the sale of petroleum products manufactured at our refineries and (b) costs of feedstocks, primarily crude oil, used to produce the petroleum products. The realized refining margins are adjusted to include our proportional share of our joint venture refineries’ realized margins, as well as to exclude those items that are not representative of the underlying operating performance of a period, which we call “special items.” The realized refining margins are converted to a per-barrel basis by dividing them by total refinery processed inputs (primarily crude oil) measured on a barrel basis, including our share of inputs processed by our joint venture refineries. Our realized refining margin per barrel is intended to be comparable with industry refining margins, which are known as “crack spreads.” As discussed in “Business Environment,” industry crack spreads measure the difference between market prices for refined petroleum products and crude oil. We believe realized refining margin per barrel calculated on a similar basis as industry crack spreads provides a useful measure of how well we performed relative to benchmark industry refining margins.
The GAAP performance measure most directly comparable to realized refining margin per barrel is the Refining segment’s “income (loss) before income taxes per barrel.” Realized refining margin per barrel excludes items that are typically included in a manufacturer’s gross margin, such as depreciation and operating expenses, and other items used to determine income (loss) before income taxes, such as general and administrative expenses. It also includes our proportional share of joint venture refineries’ realized refining margins and excludes special items. Because realized refining margin per barrel is calculated in this manner, and because realized refining margin per barrel may be defined differently by other companies in our industry, it has limitations as an analytical tool. Following are reconciliations of income (loss) before income taxes to realized refining margins:
Millions of Dollars, Except as Indicated
Realized Refining Margins Atlantic Basin/Europe Gulf Coast Central Corridor West Coast Worldwide
Year Ended December 31, 2020
Loss before income taxes $ (1,224) (2,077) (641) (2,213) (6,155)
Plus:
Taxes other than income taxes
61 107 51 89 308
Depreciation, amortization and impairments
643 968 571 1,460 3,642
Selling, general and administrative expenses
44 39 28 38 149
Operating expenses
774 1,354 498 1,000 3,626
Equity in losses of affiliates 10 3 363 - 376
Other segment (income) expense, net
1 1 (2) 5 5
Proportional share of refining gross margins contributed by equity affiliates
67 - 298 - 365
Special items:
Certain tax impacts (6) - - - (6)
Realized refining margins
$ 370 395 1,166 379 2,310
Total processed inputs (thousands of barrels)
170,536 213,871 92,050 110,602 587,059
Adjusted total processed inputs (thousands of barrels)*
170,536 213,871 162,693 110,602 657,702
Loss before income taxes per barrel (dollars per barrel)**
$ (7.18) (9.71) (6.96) (20.01) (10.48)
Realized refining margins (dollars per barrel)***
2.17 1.85 7.17 3.43 3.51
Year Ended December 31, 2019
Income (loss) before income taxes $ 608 364 1,338 (324) 1,986
Plus:
Taxes other than income taxes
52 73 40 85 250
Depreciation, amortization and impairments
198 271 135 253 857
Selling, general and administrative expenses
39 23 22 31 115
Operating expenses
863 1,449 550 1,143 4,005
Equity in (earnings) losses of affiliates
11 2 (331) - (318)
Other segment (income) expense, net
(16) (3) - 5 (14)
Proportional share of refining gross margins contributed by equity affiliates
69 - 1,073 - 1,142
Special items:
Pending claims and settlements - - (21) - (21)
Realized refining margins
$ 1,824 2,179 2,806 1,193 8,002
Total processed inputs (thousands of barrels)
195,506 293,666 103,294 130,014 722,480
Adjusted total processed inputs (thousands of barrels)*
195,506 293,666 188,045 130,014 807,231
Income (loss) before income taxes per barrel (dollars per barrel)**
$ 3.11 1.24 12.95 (2.49) 2.75
Realized refining margins (dollars per barrel)***
9.33 7.42 14.91 9.18 9.91
* Adjusted total processed inputs include our proportional share of processed inputs of an equity affiliate.
** Income (loss) before income taxes divided by total processed inputs.
*** Realized refining margins per barrel, as presented, are calculated using the underlying realized refining margin amounts, in dollars, divided by adjusted total processed inputs, in barrels. As such, recalculated per barrel amounts using the rounded margins and barrels presented may differ from the presented per barrel amounts.
Millions of Dollars, Except as Indicated
Realized Refining Margins Atlantic Basin/Europe Gulf Coast Central Corridor West Coast Worldwide
Year Ended December 31, 2018
Income before income taxes
$ 567 1,040 2,817 111 4,535
Plus:
Taxes other than income taxes
56 88 43 100 287
Depreciation, amortization and impairments
201 268 135 237 841
Selling, general and administrative expenses
63 57 34 50 204
Operating expenses
950 1,312 488 1,040 3,790
Equity in (earnings) losses of affiliates
10 6 (812) - (796)
Other segment (income) expense, net
(11) 3 (13) (9) (30)
Proportional share of refining gross margins contributed by equity affiliates
87 - 1,565 - 1,652
Special items:
Certain tax impacts
(5) - - - (5)
Realized refining margins
$ 1,918 2,774 4,257 1,529 10,478
Total processed inputs (thousands of barrels)
186,042 292,665 106,299 136,332 721,338
Adjusted total processed inputs (thousands of barrels)*
186,042 292,665 191,561 136,332 806,600
Income before income taxes per barrel (dollars per barrel)**
$ 3.05 3.55 26.50 0.81 6.29
Realized refining margins (dollars per barrel)***
10.32 9.48 22.22 11.20 12.99
* Adjusted total processed inputs include our proportional share of processed inputs of an equity affiliate.
** Income before income taxes divided by total processed inputs.
*** Realized refining margins per barrel, as presented, are calculated using the underlying realized refining margin amounts, in dollars, divided by adjusted total processed inputs, in barrels. As such, recalculated per barrel amounts using the rounded margins and barrels presented may differ from the presented per barrel amounts.
Marketing
Our realized marketing fuel margins measure the difference between (a) sales and other operating revenues derived from the sale of fuels in our M&S segment and (b) costs of those fuels. The realized marketing fuel margins are adjusted to exclude those items that are not representative of the underlying operating performance of a period, which we call “special items.” The realized marketing fuel margins are converted to a per-barrel basis by dividing them by sales volumes measured on a barrel basis. We believe realized marketing fuel margin per barrel demonstrates the value uplift our marketing operations provide by optimizing the placement and ultimate sale of our refineries’ fuel production.
Within the M&S segment, the GAAP performance measure most directly comparable to realized marketing fuel margin per barrel is the marketing business’ “income before income taxes per barrel.” Realized marketing fuel margin per barrel excludes items that are typically included in gross margin, such as depreciation and operating expenses, and other items used to determine income before income taxes, such as general and administrative expenses. Because realized marketing fuel margin per barrel excludes these items, and because realized marketing fuel margin per barrel may be defined differently by other companies in our industry, it has limitations as an analytical tool. Following are reconciliations of income before income taxes to realized marketing fuel margins:
Millions of Dollars, Except as Indicated
U.S. International
2020 2019 2018 2020 2019 2018
Realized Marketing Fuel Margins
Income before income taxes $ 870 916 843 454 380 505
Plus:
Taxes other than income taxes 1 5 (2) 5 6 2
Depreciation, amortization and impairment
12 10 13 70 65 71
Selling, general and administrative expenses
623 743 763 246 249 280
Equity in earnings of affiliates
(31) (27) (8) (108) (99) (91)
Other operating revenues*
(327) (379) (379) (27) (37) (32)
Other segment expense, net - - - 1 1 2
Special items:
Certain tax impacts
- (90) (100) - - -
Marketing margins
1,148 1,178 1,130 641 565 737
Less: margin for nonfuel related sales
- - - 46 44 44
Realized marketing fuel margins
$ 1,148 1,178 1,130 595 521 693
Total fuel sales volumes (thousands of barrels)
613,869 752,064 697,696 93,773 106,263 100,949
Income before income taxes per barrel (dollars per barrel)
$ 1.42 1.22 1.21 4.84 3.58 5.00
Realized marketing fuel margins (dollars per barrel)**
1.87 1.57 1.62 6.34 4.90 6.87
* Includes other nonfuel revenues.
** Realized marketing fuel margins per barrel, as presented, are calculated using the underlying realized marketing fuel margin amounts, in dollars, divided by sales volumes, in barrels. As such, recalculated per barrel amounts using the rounded margins and barrels presented may differ from the presented per barrel amounts.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Financial Instrument Market Risk
We and certain of our subsidiaries are exposed to market risks produced by changes in the prices of crude oil, refined petroleum products, natural gas, NGL and electric power, as well as fluctuations in interest rates and foreign currency exchange rates. We and certain of our subsidiaries may hold and use derivative contracts to manage these risks.
Commodity Price Risk
Generally, our policy is to remain exposed to the market prices of commodities. Consistent with this policy, we use derivative contracts to convert our exposure from fixed-price sales or purchase contracts, often specified in contracts with refined petroleum product customers, back to floating market prices. We also use futures, forwards, swaps and options in various markets to accomplish the following objectives:
•Balance physical systems or meet our refinery requirements and market demand. In addition to cash settlement prior to contract expiration, certain exchange-traded futures may be settled by physical delivery of the underlying commodity.
•Enable us to use the market knowledge gained from our physical commodity market 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.
•Manage the risk to our cash flows from price exposures on specific crude oil, refined petroleum product, natural gas and NGL transactions.
These objectives optimize the value of our supply chain and may reduce our exposure to fluctuations in market prices.
Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board of Directors. This document prohibits the use of highly leveraged derivatives or derivative instruments without sufficient market liquidity for comparable valuations, and establishes Value at Risk (VaR) limits. Compliance with these limits is monitored daily by our global risk group.
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 commodity instruments held or issued. Using Monte Carlo simulation, a 95% confidence level and a one-day holding period, the VaR for derivative commodity instruments issued or held at December 31, 2020 and 2019, was immaterial to our cash flows and results of operations.
Interest Rate Risk
Our use of fixed- or variable-rate debt directly exposes us to interest rate risk. Fixed-rate debt, such as our senior notes, exposes us to changes in the fair value of our debt due to changes in market interest rates. Fixed-rate debt also exposes us to the risk that we may need to refinance maturing debt with new debt at higher rates, or that we may be obligated to pay rates higher than the current market. Variable-rate debt, such as our floating-rate notes or borrowings under our revolving credit facility, exposes us to short-term changes in market rates that impact our interest expense. The following tables provide information about our debt instruments that are sensitive to changes in U.S. interest rates. These tables present principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on effective rates at each reporting date. The carrying amount of our floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on observable market prices.
Millions of Dollars, Except as Indicated
Expected Maturity Date Fixed Rate Maturity Average Interest Rate Floating Rate Maturity Average Interest Rate
Year-End 2020
2021 $ - - % $ 965 1.05 %
2022 2,000 4.30 - -
2023 500 3.70 500 1.40
2024 1,100 1.32 450 0.84
2025 1,150 3.74 - -
Remaining years 9,026 4.22 25 0.76
Total $ 13,776 $ 1,940
Fair value $ 15,597 $ 1,940
Millions of Dollars, Except as Indicated
Expected Maturity Date Fixed Rate Maturity Average Interest Rate Floating Rate Maturity Average Interest Rate
Year-End 2019
2020 $ - - % $ 525 2.69 %
2021 - - 550 2.46
2022 2,000 4.30 - -
2023 - - - -
2024 300 2.45 - -
Remaining years 8,176 4.57 25 2.39
Total $ 10,476 $ 1,100
Fair value $ 11,813 $ 1,100
Our Chief Executive Officer and Chief Financial Officer monitor risks resulting from commodity prices, interest rates and foreign currency exchange rates.
For additional information about our use of derivative instruments, see Note 15-Derivatives and Financial Instruments, in the Notes to Consolidated Financial Statements.
CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can normally 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, but the absence of such words does not mean a statement is not forward-looking.
We based the forward-looking statements on our current expectations, estimates and projections about us, our operations, our joint ventures and entities in which we have equity interests, as well as the industries in which we and they 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:
•The continuing effects of the COVID-19 pandemic and its negative impact on commercial activity and demand for refined petroleum products, as well as the extent and duration of recovery of economies and demand for our products after the pandemic subsides.
•Fluctuations in NGL, crude oil, refined petroleum product and natural gas prices and refining, marketing and petrochemical margins.
•Changes in governmental policies relating to NGL, crude oil, natural gas or refined petroleum products pricing, regulation or taxation, including exports.
•Actions taken by the Organization of the Petroleum Exporting Countries (OPEC) and other countries impacting supply and demand and correspondingly, commodity prices.
•Unexpected changes in costs or technical requirements for constructing, modifying or operating our facilities or transporting our products.
•Unexpected technological or commercial difficulties in manufacturing, refining or transporting our products, including chemical products.
•Lack of, or disruptions in, adequate and reliable transportation for our NGL, crude oil, natural gas and refined petroleum products.
•The level and success of drilling and quality of production volumes around our Midstream assets.
•The inability to timely obtain or maintain permits, including those necessary for capital projects.
•The inability to comply with government regulations or make capital expenditures required to maintain compliance.
•Changes to worldwide government policies relating to renewable fuels and greenhouse gas emissions that adversely affect programs like the renewable fuel standards program, low carbon fuel standards and tax credits for biofuels.
•Failure to complete definitive agreements and feasibility studies for, and to complete construction of, announced and future capital projects on time and within budget.
•Potential disruption or interruption of our operations due to accidents, weather events (including as a result of climate change), civil unrest, insurrections, political events, terrorism or cyberattacks.
•General domestic and international economic and political developments including armed hostilities, expropriation of assets, and other political, economic or diplomatic developments, including those caused by public health issues, outbreaks of diseases and pandemics.
•Failure of new products and services to achieve market acceptance.
•International monetary conditions and exchange controls.
•Substantial investments required, or reduced demand for products, as a result of existing or future environmental rules and regulations, including reduced consumer demand for refined petroleum products.
•Liability resulting from litigation or for remedial actions, including removal and reclamation obligations under environmental regulations.
•Changes in tax, environmental and other laws and regulations (including alternative energy mandates) applicable to our business.
•Changes in estimates or projections used to assess fair value of intangible assets, goodwill and property and equipment and/or strategic decisions with respect to our asset portfolio that cause impairment charges.
•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 that we do not control.
•The factors generally described in “Item 1A. Risk Factors” in this report.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PHILLIPS 66
Page
Report of Management
Reports of Independent Registered Public Accounting Firm
Consolidated Financial Statements of Phillips 66:
Consolidated Statement of Operations for the years ended December 31, 2020, 2019 and 2018
Consolidated Statement of Comprehensive Income (Loss) for the years ended December 31, 2020, 2019 and 2018
Consolidated Balance Sheet at December 31, 2020 and 2019
Consolidated Statement of Cash Flows for the years ended December 31, 2020, 2019 and 2018
Consolidated Statement of Changes in Equity for the years ended December 31, 2020, 2019 and 2018
Notes to Consolidated Financial Statements
Supplementary Information
Selected Quarterly Financial Data (Unaudited)
Report of Management
Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this Annual Report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with generally accepted accounting principles in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments management believes are reasonable under the circumstances. The company’s financial statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors. Management has made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.
Assessment of Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Phillips 66’s internal control system was designed to provide reasonable assurance to the company’s management and directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2020. 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, 2020.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2020, and their report is included herein.
/s/ Greg C. Garland /s/ Kevin J. Mitchell
Greg C. Garland Kevin J. Mitchell
Chairman of the Board of Directors and Executive Vice President, Finance and
Chief Executive Officer Chief Financial Officer
Date: February 24, 2021
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Phillips 66
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Phillips 66 (the Company) as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows, for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2020 and 2019, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, 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 24, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) related to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.
Assessment of Equity Method Investment Impairment
Description of the Matter
As discussed in Note 6 to the consolidated financial statements, the Company has investments in nonconsolidated entities accounted for using the equity method, totaling $13.0 billion as of December 31, 2020. The carrying value of each equity method investment is evaluated for impairment when indicators of a loss in value below the carrying value exist, including a lack of sustained earnings or a deterioration of market conditions, among others. When there are indicators of impairment, the Company estimates the fair value of the equity method investment. Fair value is determined using various methods including the present value of expected cash flows using weighted average cost of capital (“discount rate”) and other assumptions. When the estimated fair value is lower than carrying value, the Company considers whether that impairment is other-than-temporary.
Auditing the Company’s impairment assessments was complex and judgmental due to the estimation required in determining whether an investment had an indicator of impairment, the determination of fair value of the investment if an impairment was indicated, and to the extent that the estimated fair value is lower than carrying value, whether that impairment was other-than-temporary.
How We Addressed the Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s equity method impairment review process, including controls over the identification of factors that may indicate an equity method investment is impaired, and as necessary, the subsequent determination of fair value and assessment of whether indicated impairments are other-than-temporary.
In order to test whether an impairment was indicated, we tested the Company’s evaluation of quoted market prices, if available, and the investments’ earnings history and sustainability under current and expected market conditions. When impairment indicators were present, we performed audit procedures that included, among others, assessing the methodologies used by management to determine fair value, testing the significant assumptions, including projected revenues, operating expenses and discount rate, and the underlying data used by the Company in its analyses. For example, we compared the estimated cash flows used within the assessment to current operating results and future expected economic trends. We also performed sensitivity analyses of significant assumptions to evaluate the impact of changes in significant assumptions to management’s fair value estimate and recalculated management’s estimate. Lastly, we evaluated management’s determination as to whether an indicated impairment was other than temporary, considering factors such as the duration and magnitude of the decline in value.
Assessment of Goodwill Impairment
Description of the Matter
As discussed in Note 9 of the consolidated financial statements, goodwill is tested for impairment at least annually at the reporting unit level or more frequently if events or changes in circumstances indicate the asset might be impaired. During the first quarter of 2020, due to the impacts of the COVID-19 pandemic, the Company identified a triggering event and performed an interim quantitative goodwill impairment test for all its reporting units. The fair value of the reporting units was determined using various methods including quoted market prices, the present value of expected cash flows using weighted average cost of capital (“discount rate”) and other assumptions, as well as market multiples based on comparable entities applied to forecasted earnings. As a result of the Company’s test, it was determined that the refining reporting unit goodwill was fully impaired and an impairment charge of $1.8 billion was recorded.
Auditing management’s goodwill impairment tests was complex and highly judgmental due to the significant estimation required to determine the fair value of the Company’s reporting units. In particular, the fair value estimates were sensitive to significant assumptions, including projected gross margins, operating expenses, capital expenditures and discount rate which are affected by expectations about future market, industry and economic conditions.
How We Addressed the Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s goodwill impairment process, including controls over management’s review of the significant assumptions described above.
To test the estimated fair value of the Company’s reporting units, we performed audit procedures that included, among others, assessing the valuation methodologies and testing the significant assumptions discussed above and the completeness and accuracy of the underlying data used by the Company in its analyses. We compared the significant assumptions used by management to current industry and economic trends and evaluated whether changes to the Company’s business environment would affect the significant assumptions. For example, we compared the significant assumptions used in the expected cash flows to recent operating results and expected economic trends. We performed sensitivity analyses of certain significant assumptions to evaluate the changes in the fair value of the reporting units that would result from changes in the assumptions. We also involved our internal valuation specialists to assist in our evaluation of the significant assumptions and methodologies used by the Company in developing the fair value estimates. In addition, we tested management’s reconciliation of the fair value of the reporting units to the market capitalization of the Company.
Impairment of Certain Long-Lived Assets
Description of the Matter
As discussed in Note 9 to the consolidated financial statements, in connection with the Company’s announcement to reconfigure the San Francisco Refinery to produce renewable fuels, the Company assessed the recoverability of the San Francisco Refinery asset group and concluded that the carrying value of the asset group was not recoverable. The Company determined the fair value of these assets, utilizing a combination of replacement cost estimates and comparable market transactions, and recorded a $1.0 billion impairment charge.
Auditing management’s impairment measurement was complex and judgmental due to the significant estimation required in determining the fair value of the asset group. In particular, judgment is required in order to assess significant assumptions including replacement cost as adjusted for physical deterioration and economic obsolescence, as well as the determination of comparable market transactions.
How We Addressed the Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s long-lived asset impairment process, including controls over management’s review of the significant assumptions described above.
To test the estimated fair value of the Company’s San Francisco Refinery asset group, we performed audit procedures that included, among others, assessing the appropriateness of the valuation methodologies utilized and testing the key assumptions discussed above and the underlying data used by the Company in its analysis. We compared the significant assumptions used by management to industry data, economic trends, and comparable market information. We also involved our internal valuation specialists to assist in our evaluation of the significant assumptions and methodologies used by the Company in developing the fair value estimates.
/s/ Ernst & Young LLP
Houston, Texas
February 24, 2021
We have served as the Company’s auditor since 2011.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Phillips 66
Opinion on Internal Control over Financial Reporting
We have audited Phillips 66’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Phillips 66 (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and our report dated February 24, 2021, expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Report of Management.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Houston, Texas
February 24, 2021
Consolidated Statement of Operations Phillips 66
Millions of Dollars
Years Ended December 31 2020 2019 2018
Revenues and Other Income
Sales and other operating revenues $ 64,129 107,293 111,461
Equity in earnings of affiliates 1,191 2,127 2,676
Net gain on dispositions 108 20 19
Other income 66 119 61
Total Revenues and Other Income 65,494 109,559 114,217
Costs and Expenses
Purchased crude oil and products 57,707 95,529 97,930
Operating expenses 4,563 5,074 4,880
Selling, general and administrative expenses 1,544 1,681 1,677
Depreciation and amortization 1,395 1,341 1,356
Impairments 4,252 861 8
Taxes other than income taxes 464 409 425
Accretion on discounted liabilities 22 23 23
Interest and debt expense 499 458 504
Foreign currency transaction (gains) losses 12 5 (31)
Total Costs and Expenses 70,458 105,381 106,772
Income (loss) before income taxes (4,964) 4,178 7,445
Income tax expense (benefit) (1,250) 801 1,572
Net Income (Loss) (3,714) 3,377 5,873
Less: net income attributable to noncontrolling interests 261 301 278
Net Income (Loss) Attributable to Phillips 66 $ (3,975) 3,076 5,595
Net Income (Loss) Attributable to Phillips 66 Per Share of Common Stock (dollars)
Basic $ (9.06) 6.80 11.87
Diluted (9.06) 6.77 11.80
Weighted-Average Common Shares Outstanding (thousands)
Basic 439,530 451,364 470,708
Diluted 439,530 453,888 474,047
See Notes to Consolidated Financial Statements.
Consolidated Statement of Comprehensive Income (Loss) Phillips 66
Millions of Dollars
Years Ended December 31 2020 2019 2018
Net Income (Loss) $ (3,714) 3,377 5,873
Other comprehensive income (loss)
Defined benefit plans
Net actuarial loss arising during the period (261) (156) (16)
Prior service credit arising during the period - 2 -
Amortization of net actuarial loss, prior service credit and settlements 144 63 148
Curtailment gain - - 5
Plans sponsored by equity affiliates (77) (21) 22
Income taxes on defined benefit plans 41 21 (33)
Defined benefit plans, net of income taxes (153) (91) 126
Foreign currency translation adjustments 156 94 (205)
Income taxes on foreign currency translation adjustments (5) 1 3
Foreign currency translation adjustments, net of income taxes 151 95 (202)
Cash flow hedges (5) (15) 1
Income taxes on hedging activities 1 4 -
Hedging activities, net of income taxes (4) (11) 1
Other Comprehensive Loss, Net of Income Taxes (6) (7) (75)
Comprehensive Income (Loss) (3,720) 3,370 5,798
Less: comprehensive income attributable to noncontrolling interests 261 301 278
Comprehensive Income (Loss) Attributable to Phillips 66 $ (3,981) 3,069 5,520
See Notes to Consolidated Financial Statements.
Consolidated Balance Sheet Phillips 66
Millions of Dollars
At December 31 2020 2019
Assets
Cash and cash equivalents $ 2,514 1,614
Accounts and notes receivable (net of allowances of $37 million in 2020 and $41 million in 2019)
5,688 7,376
Accounts and notes receivable-related parties 834 1,134
Inventories 3,893 3,776
Prepaid expenses and other current assets 347 495
Total Current Assets 13,276 14,395
Investments and long-term receivables 13,624 14,571
Net properties, plants and equipment 23,716 23,786
Goodwill 1,425 3,270
Intangibles 843 869
Other assets 1,837 1,829
Total Assets $ 54,721 58,720
Liabilities
Accounts payable $ 5,171 8,043
Accounts payable-related parties 378 532
Short-term debt 987 547
Accrued income and other taxes 1,351 979
Employee benefit obligations 573 710
Other accruals 1,058 835
Total Current Liabilities 9,518 11,646
Long-term debt 14,906 11,216
Asset retirement obligations and accrued environmental costs 657 638
Deferred income taxes 5,644 5,553
Employee benefit obligations 1,341 1,044
Other liabilities and deferred credits 1,132 1,454
Total Liabilities 33,198 31,551
Equity
Common stock (2,500,000,000 shares authorized at $0.01 par value)
Issued (2020-648,643,223 shares; 2019-647,416,633 shares)
Par value 6 6
Capital in excess of par 20,383 20,301
Treasury stock (at cost: 2020-211,771,827 shares; 2019-206,390,806 shares)
(17,116) (16,673)
Retained earnings 16,500 22,064
Accumulated other comprehensive loss (789) (788)
Total Stockholders’ Equity 18,984 24,910
Noncontrolling interests 2,539 2,259
Total Equity 21,523 27,169
Total Liabilities and Equity $ 54,721 58,720
See Notes to Consolidated Financial Statements.
Consolidated Statement of Cash Flows Phillips 66
Millions of Dollars
Years Ended December 31 2020 2019 2018
Cash Flows From Operating Activities
Net income (loss) $ (3,714) 3,377 5,873
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation and amortization 1,395 1,341 1,356
Impairments 4,252 861 8
Accretion on discounted liabilities 22 23 23
Deferred income taxes 126 183 252
Undistributed equity earnings 334 (143) 221
Net gain on dispositions (108) (20) (19)
Other 130 16 132
Working capital adjustments
Accounts and notes receivable 2,023 (2,308) 1,320
Inventories (71) (204) (202)
Prepaid expenses and other current assets
92 (14) (113)
Accounts payable (2,887) 1,941 (1,546)
Taxes and other accruals 517 (245) 268
Net Cash Provided by Operating Activities 2,111 4,808 7,573
Cash Flows From Investing Activities
Capital expenditures and investments (2,920) (3,873) (2,639)
Return of investments in equity affiliates 192 71 45
Proceeds from asset dispositions 51 86 12
Advances/loans-related parties (316) (98) (1)
Collection of advances/loans-related parties 44 95 -
Other (130) 31 112
Net Cash Used in Investing Activities (3,079) (3,688) (2,471)
Cash Flows From Financing Activities
Issuance of debt 5,178 1,783 2,184
Repayment of debt (1,051) (1,307) (1,144)
Issuance of common stock 8 32 39
Repurchase of common stock (443) (1,650) (4,645)
Dividends paid on common stock (1,575) (1,570) (1,436)
Distributions to noncontrolling interests (289) (241) (207)
Net proceeds from issuance of Phillips 66 Partners LP common and preferred units
2 173 128
Other (39) 269 (86)
Net Cash Provided by (Used in) Financing Activities 1,791 (2,511) (5,167)
Effect of Exchange Rate Changes on Cash and Cash Equivalents 77 (14) (35)
Net Change in Cash and Cash Equivalents 900 (1,405) (100)
Cash and cash equivalents at beginning of year 1,614 3,019 3,119
Cash and Cash Equivalents at End of Year $ 2,514 1,614 3,019
See Notes to Consolidated Financial Statements.
Consolidated Statement of Changes in Equity Phillips 66
Millions of Dollars
Attributable to Phillips 66
Common Stock
Par Value Capital in Excess of Par Treasury Stock Retained Earnings Accum. Other
Comprehensive
Loss Noncontrolling
Interests Total
December 31, 2017 $ 6 19,768 (10,378) 16,306 (617) 2,343 27,428
Cumulative effect of accounting changes
- - - 36 - 13 49
Net income - - - 5,595 - 278 5,873
Other comprehensive loss - - - - (75) - (75)
Dividends paid on common stock - - - (1,436) - - (1,436)
Repurchase of common stock - - (4,645) - - - (4,645)
Benefit plan activity - 63 - (12) - - 51
Issuance of Phillips 66 Partners LP common units - 42 - - - 73 115
Distributions to noncontrolling interests
- - - - - (207) (207)
December 31, 2018 6 19,873 (15,023) 20,489 (692) 2,500 27,153
Cumulative effect of accounting changes
- - - 81 (89) (1) (9)
Net income - - - 3,076 - 301 3,377
Other comprehensive loss - - - - (7) - (7)
Dividends paid on common stock - - - (1,570) - - (1,570)
Repurchase of common stock - - (1,650) - - - (1,650)
Benefit plan activity - 85 - (12) - - 73
Issuance of Phillips 66 Partners LP common units
- 68 - - - 73 141
Impacts from Phillips 66 Partners LP GP/IDR restructuring transaction - 275 - - - (373) (98)
Distributions to noncontrolling interests
- - - - - (241) (241)
December 31, 2019 6 20,301 (16,673) 22,064 (788) 2,259 27,169
Net income (loss) - - - (3,975) - 261 (3,714)
Other comprehensive loss - - - - (6) - (6)
Dividends paid on common stock - - - (1,575) - - (1,575)
Repurchase of common stock - - (443) - - - (443)
Benefit plan activity - 80 - (12) - - 68
Transfer of equity interest - 2 - - - 305 307
Net distributions to noncontrolling interests - - - - - (285) (285)
Other - - - (2) 5 (1) 2
December 31, 2020 $ 6 20,383 (17,116) 16,500 (789) 2,539 21,523
Shares
Common Stock Issued Treasury Stock
December 31, 2017 643,835,464 141,565,145
Repurchase of common stock - 47,961,186
Shares issued-share-based compensation 1,856,297 -
December 31, 2018 645,691,761 189,526,331
Repurchase of common stock - 16,864,475
Shares issued-share-based compensation 1,724,872 -
December 31, 2019 647,416,633 206,390,806
Repurchase of common stock - 5,381,021
Shares issued-share-based compensation 1,226,590 -
December 31, 2020 648,643,223 211,771,827
Dollars
Years Ended December 31 Dividends Paid Per
Share of Common Stock
2018 $ 3.10
2019 3.50
2020 3.60
See Notes to Consolidated Financial Statements.
Notes to Consolidated Financial Statements Phillips 66
Note 1-Summary of Significant Accounting Policies
Consolidation Principles and Investments
Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and variable interest entities (VIEs) where we are the primary beneficiary. Undivided interests in pipelines, natural gas plants and terminals are consolidated on a proportionate basis. See Note 27-Phillips 66 Partners LP, for further discussion on our significant consolidated VIE.
The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies, including VIEs, of which we are not the primary beneficiary. Other securities and investments are generally carried at fair value, or cost less impairments, if any, adjusted up or down for price changes in similar financial instruments issued by the investee, when and if observed. See Note 6-Investments, Loans and Long-Term Receivables, for further discussion on our significant unconsolidated VIEs.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles in the United States (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.
Foreign Currency Translation
Adjustments resulting from the process of translating financial statements with foreign functional currencies into U.S. dollars are included in accumulated other comprehensive income (loss) in stockholders’ equity. Foreign currency transaction gains and losses result from remeasuring monetary assets and liabilities denominated in a foreign currency into the functional currency of our subsidiary holding the asset or liability. We include these transaction gains and losses in current earnings (loss). Most of our foreign operations use their local currency as the functional currency.
Cash Equivalents
Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and will mature within 90 days or less from the date of acquisition. We carry these investments at cost plus accrued interest.
Inventories
We have several valuation methods for our various types of inventories and consistently use the following methods for each type of inventory. Crude oil and refined petroleum products inventories are valued at the lower of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Any necessary lower-of-cost-or-market write-downs at year end are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues and to meet tax-conformity requirements. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location. Materials and supplies inventories are valued using the weighted-average-cost method.
Fair Value Measurements
We categorize assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability that are used to measure fair value to the extent that relevant observable inputs are not available, and that reflect the assumptions we believe market participants would use when pricing an asset or liability for which there is little, if any, market activity at the measurement date.
Derivative Instruments
Derivative instruments are recorded on the balance sheet at fair value. We have master netting agreements with our exchange-cleared instrument counterparties and certain of our counterparties to other commodity instrument contracts (e.g., physical commodity forward contracts). We have elected to net derivative assets and liabilities with the same counterparty on the balance sheet if the legal right of offset exists and certain other criteria are met. We also net collateral payables and receivables against derivative assets and derivative liabilities, respectively.
Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. All realized and unrealized gains and losses from derivative instruments for which we do not apply hedge accounting are immediately recognized in our consolidated statement of operations. Unrealized gains or losses from derivative instruments that qualify for and are designated as cash flow hedges are recognized in other comprehensive income (loss) and appear on the balance sheet in accumulated other comprehensive income (loss) until the hedged transactions are recognized in earnings. However, to the extent the change in the fair value of a derivative instrument exceeds the change in the anticipated cash flows of the hedged transaction, the excess gain or loss is recognized immediately in earnings.
Loans and Long-Term Receivables
We enter into agreements with other parties to pursue business opportunities, which may require us to provide loans or advances to certain affiliated and nonaffiliated companies. Loans are recorded when cash is transferred or seller financing is provided to the affiliated or nonaffiliated company pursuant to a loan agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will decrease as interest and principal payments are received. Interest is earned at the loan agreement’s stated interest rate. Loans and long-term receivables are evaluated for impairment based on an expected credit loss assessment.
Impairment of Investments in Nonconsolidated Entities
Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. When indicators exist, the fair value is estimated and compared to the investment carrying value. If any impairment is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. The fair value of the impaired investment is determined based on quoted market prices, if available, or upon the present value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants and observed market earnings multiples of comparable companies.
Depreciation and Amortization
Depreciation and amortization of properties, plants and equipment (PP&E) are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units).
Capitalized Interest
A portion of interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the related asset, and is amortized over the useful life of the related asset.
Impairment of Properties, Plants and Equipment
PP&E used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If indicators of potential impairment exist, an undiscounted cash flow test is performed. If the sum of the undiscounted expected future before-tax cash flows of an asset group is less than the carrying value of the asset group, including applicable liabilities, the carrying value of the PP&E included in the asset group is written down to estimated fair value and the write down is reported in the “Impairments” line item on our consolidated statement of operations in the period in which the impairment determination is made. Individual assets are grouped for impairment purposes at the lowest level for which identifiable cash flows are available. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined using one or more of the following methods: the present values of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants; a market multiple of earnings for similar assets; historical market transactions including similar assets, adjusted using principal market participant assumptions when necessary; or replacement cost adjusted for physical deterioration and economic obsolescence. 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, estimated replacement cost, or present value of expected future cash flows as previously described.
The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future volumes, prices, costs, margins and capital project decisions, considering all available evidence at the date of review.
Property Dispositions
When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the “Net gain on dispositions” line item on our consolidated statement of operations. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.
Goodwill
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination. Goodwill is not amortized, but is assessed for impairment annually and when events or changes in circumstance indicate that the fair value of a reporting unit with goodwill is below its carrying value. The impairment assessment requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, an impairment is recognized for the amount by which the book value exceeds the reporting unit’s fair value. A goodwill loss cannot exceed the total amount of goodwill allocated to that reporting unit. For purposes of assessing goodwill for impairment, we have two reporting units with goodwill balances at the 2020 testing date: Transportation and Marketing and Specialties.
Intangible Assets Other Than Goodwill
Intangible assets with finite useful lives are amortized using the straight-line method over their useful lives. Intangible assets with indefinite useful lives are not amortized, but are tested at least annually for impairment. Each reporting period, we evaluate intangible assets with indefinite useful lives to determine whether events and circumstances continue to support this classification. Indefinite-lived intangible assets are considered impaired if their fair value is lower than their net book value. The fair value of intangible assets is determined based on quoted market prices in active markets, if available. If quoted market prices are not available, the fair value of intangible assets is determined based upon the present values of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable.
Asset Retirement Obligations and Environmental Costs
The fair values of legal obligations to retire and remove long-lived assets are recorded in the period in which the obligations arise. When the liabilities are initially recorded, we capitalize these costs by increasing the carrying amount of the related PP&E. Over time, the liabilities are increased for the change in present value, and the capitalized costs in PP&E are depreciated over the useful life of the related assets. If our estimate of the liability changes after initial recognition, we record an adjustment to the liabilities 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. When environmental assessments or cleanups are probable and the costs can be reasonably estimated, environmental expenditures are accrued on an undiscounted basis (unless acquired in a business combination). Recoveries of environmental remediation costs from other parties, such as state reimbursement funds, are recorded as a reduction to environmental expenditures.
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. We amortize the guarantee liability to the related statement of operations line item based on the nature of the guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we have information to support the reversal. When the performance on the guarantee becomes probable and the liability can be reasonably estimated, we accrue a separate liability for the excess amount above the guarantee’s book value based on the facts and circumstances at that time. We reverse the fair value liability only when there is no further exposure under the guarantee.
Treasury Stock
We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions of stockholders’ equity on the consolidated balance sheet.
Revenue Recognition
Our revenues are primarily associated with sales of refined petroleum products, crude oil and natural gas liquids (NGL). Each gallon, or other unit of measure of product, is separately identifiable and represents a distinct performance obligation to which a transaction price is allocated. The transaction prices of our contracts with customers are either fixed or variable, with variable pricing based upon various market indices. For our contracts that include variable consideration, we utilize the variable consideration allocation exception, whereby the variable consideration is only allocated to the performance obligations that are satisfied during the period. The related revenue is recognized at a point in time when control passes to the customer, which is when title and the risk of ownership passes to the customer and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry. The payment terms with our customers vary based on the product or service provided, but usually are 30 days or less.
Revenues associated with pipeline transportation services are recognized at a point in time when the volumes are delivered based on contractual rates. Revenues associated with terminaling and storage services are recognized over time as the services are performed based on throughput volume or capacity utilization at contractual rates.
Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into in contemplation of one another, are combined and reported in the “Purchased crude oil and products” line item on our consolidated statement of operations (i.e., these transactions are recorded net).
Taxes Collected from Customers and Remitted to Governmental Authorities
Excise taxes on sales of refined petroleum products charged to our customers are presented net of taxes on sales of refined petroleum products payable to governmental authorities in the “Taxes other than income taxes” line item on our consolidated statement of operations. Other sales and value-added taxes are recorded net in the “Taxes other than income taxes” line item on our consolidated statement of operations.
Shipping and Handling Costs
We have elected to account for shipping and handling costs as fulfillment activities and include these activities in the “Purchased crude oil and products” line item on our consolidated statement of operations. Freight costs billed to customers are recorded in “Sales and other operating revenues.”
Maintenance and Repairs
Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Major refinery maintenance turnarounds are expensed as incurred.
Share-Based Compensation
We recognize share-based compensation expense over the shorter of: (1) the service period (i.e., the stated period of time required to earn the award); or (2) the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months as this is the minimum period of time required for an award not to be subject to forfeiture. Our equity-classified programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for awards held by employees at the time they become eligible for retirement (at age 55 with 5 years of service). We have elected to recognize expense on a straight-line basis over the service period for the entire award, irrespective of whether the award was granted with ratable or cliff vesting, and have elected to recognize forfeitures of awards when they occur.
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 temporary 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 (loss) in the period that includes the enactment date. Interest related to unrecognized income tax benefits is reflected in the “Interest and debt expense” line item, and penalties in the “Operating expenses” or “Selling, general and administrative expenses” line items on our consolidated statement of operations.
Note 2-Changes in Accounting Principles
Effective January 1, 2019, we elected to adopt ASU No. 2018-02, “Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU permits the deferred income tax effects stranded in accumulated other comprehensive income (AOCI) resulting from the U.S. Tax Cuts and Jobs Act (the Tax Act) enacted in December 2017 to be reclassified to retained earnings. As of January 1, 2019, we recorded a cumulative effect adjustment to our opening consolidated balance sheet to reclassify an aggregate income tax benefit of $89 million, primarily related to our pension plans, from accumulated other comprehensive loss to retained earnings.
Effective January 1, 2019, we early adopted ASU 2016-13, “Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” using the modified retrospective transition method. This ASU amends the impairment model to utilize an expected loss methodology in place of the incurred loss methodology for financial instruments, including trade receivables, and off-balance sheet credit exposures. The amendment requires entities to consider a broader range of information to estimate expected credit losses, which may result in earlier recognition of losses. We recorded a noncash cumulative effect adjustment to retained earnings of $9 million, net of $3 million of income taxes, on our opening consolidated balance sheet as of January 1, 2019. See Note 4-Credit Losses, for more information on our presentation of credit losses.
Effective January 1, 2019, we adopted ASU No. 2016-02, “Leases (Topic 842),” using the modified retrospective transition method. The new standard establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the consolidated balance sheet for all leases with terms longer than 12 months. Leases will continue to be classified as either finance or operating, with classification affecting the pattern of expense recognition in the consolidated statement of operations.
We elected the package of practical expedients that allowed us to carry forward our determination of whether an arrangement contained a lease and lease classification, as well as our accounting for initial direct costs for existing contracts. We recorded a noncash cumulative effect adjustment, reflecting an aggregate operating lease ROU asset and corresponding lease liability of $1,415 million and immaterial adjustments to retained earnings and noncontrolling interests, on our opening consolidated balance sheet as of January 1, 2019. See Note 18-Leases, for the new lease disclosures required by this ASU.
Note 3-Sales and Other Operating Revenues
Disaggregated Revenues
The following tables present our disaggregated sales and other operating revenues:
Millions of Dollars
2020 2019 2018
Product Line and Services
Refined petroleum products $ 49,768 87,902 87,967
Crude oil resales 9,114 14,125 16,419
NGL 4,084 4,814 6,161
Services and other* 1,163 452 914
Consolidated sales and other operating revenues
$ 64,129 107,293 111,461
Geographic Location**
United States $ 48,711 83,512 86,401
United Kingdom 7,031 9,863 11,054
Germany 3,034 4,053 4,352
Other foreign countries 5,353 9,865 9,654
Consolidated sales and other operating revenues
$ 64,129 107,293 111,461
* Includes derivatives-related activities. See Note 15-Derivatives and Financial Instruments, for additional information.
** Sales and other operating revenues are attributable to countries based on the location of the operations generating the revenues.
Contract-Related Assets and Liabilities
At December 31, 2020 and 2019, receivables from contracts with customers were $3,911 million and $6,902 million, respectively. Significant noncustomer balances, such as buy/sell receivables and excise tax receivables, were excluded from these amounts.
Our contract-related assets also include payments we make to our marketing customers related to incentive programs. An incentive payment is initially recognized as an asset and subsequently amortized as a reduction to revenue over the contract term, which generally ranges from 5 to 15 years. At December 31, 2020 and 2019, our asset balances related to such payments were $404 million and $336 million, respectively.
Our contract liabilities represent advances from our customers prior to product or service delivery. At December 31, 2020 and 2019, contract liabilities were not material.
Remaining Performance Obligations
Most of our contracts with customers are spot contracts or term contracts with only variable consideration. We do not disclose remaining performance obligations for these contracts as the expected duration is one year or less or because the variable consideration has been allocated entirely to an unsatisfied performance obligation. We also have certain contracts in our Midstream segment that include minimum volume commitments with fixed pricing, which mostly expire by 2022. At December 31, 2020, the remaining performance obligations related to these minimum volume commitment contracts were not material.
Note 4-Credit Losses
We are exposed to credit losses primarily through our sales of refined petroleum products, crude oil and NGL. We assess each counterparty’s ability to pay for the products we sell by conducting a credit review. The credit review considers our expected billing exposure and timing for payment and the counterparty’s established credit rating or our assessment of the counterparty’s creditworthiness based on our analysis of their financial statements when a credit rating is not available. We also consider contract terms and conditions, country and political risk, and business strategy in our evaluation. A credit limit is established for each counterparty based on the outcome of this review. We may require collateralized asset support or a prepayment to mitigate credit risk.
We monitor our ongoing credit exposure through active review of counterparty balances against contract terms and due dates. Our activities include timely account reconciliations, dispute resolution and payment confirmations. We may employ collection agencies and legal counsel to pursue recovery of defaulted receivables.
The negative economic impacts associated with Coronavirus Disease 2019 (COVID-19) increase the probability that certain of our counterparties may not be able to completely fulfill their obligations in a timely manner. In response, we have enhanced our credit monitoring, sought collateral to support some transactions, and required prepayments from higher-risk counterparties.
At December 31, 2020 and 2019, we reported $6,522 million and $8,510 million of accounts and notes receivable, net of allowances of $37 million and $41 million, respectively. Based on an aging analysis at December 31, 2020, 99% of our accounts receivable were outstanding less than 60 days.
We are also exposed to credit losses from off-balance sheet exposures, such as guarantees of joint venture debt and standby letters of credit. See Note 13-Guarantees, and Note 14-Contingencies and Commitments, for more information on these off-balance sheet exposures.
Note 5-Inventories
Inventories at December 31 consisted of the following:
Millions of Dollars
2020 2019
Crude oil and petroleum products $ 3,536 3,452
Materials and supplies 357 324
$ 3,893 3,776
Inventories valued on the LIFO basis totaled $3,368 million and $3,331 million at December 31, 2020 and 2019, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $2.7 billion and $4.3 billion at December 31, 2020 and 2019, respectively.
During each of the three years ended December 31, 2020, certain volume reductions in inventory caused liquidations of LIFO inventory values. These liquidations did not have a material impact on our results for the years ended December 31, 2020, 2019 and 2018.
Note 6-Investments, Loans and Long-Term Receivables
Components of investments and long-term receivables at December 31 were:
Millions of Dollars
2020 2019
Equity investments $ 13,037 14,284
Other investments 145 130
Loans and long-term receivables 442 157
$ 13,624 14,571
Equity Investments
Significant affiliated companies accounted for under the equity method, including nonconsolidated VIEs, at December 31, 2020 and 2019, included:
•Chevron Phillips Chemical Company LLC (CPChem)-50 percent-owned joint venture that manufactures and markets petrochemicals and plastics. We have multiple long-term supply and purchase agreements in place with CPChem with extension options. These agreements cover sales and purchases of refined petroleum products, solvents, fuel gas, natural gas, NGL, and other petrochemical feedstocks. All products are purchased and sold under specified pricing formulas based on various published pricing indices. At December 31, 2020 and 2019, the book value of our investment in CPChem was $6,126 million and $6,229 million, respectively.
•WRB Refining LP (WRB)-50 percent-owned joint venture that owns the Wood River and Borger refineries located in Roxana, Illinois, and Borger, Texas, respectively, for which we are the operator and managing partner. We have a basis difference for our investment in WRB because the carrying value of our investment is lower than our share of WRB’s recorded net assets. This basis difference was primarily the result of our contribution of these refineries to WRB. On the contribution closing date, a basis difference was created because the fair value of the contributed assets recorded by WRB exceeded our historical book value. The contribution-related basis difference is primarily being amortized and recognized as a benefit to equity earnings over a period of 26 years, which was the estimated remaining useful life of the refineries’ PP&E at the contribution closing date. At December 31, 2020, the aggregate remaining basis difference for this investment was $2,248 million. Equity earnings for the years ended December 31, 2020, 2019 and 2018, were increased by $180 million, $182 million and $177 million, respectively, due to the amortization of our aggregate basis difference. At December 31, 2020 and 2019, the book value of our investment in WRB was $1,819 million and $2,183 million, respectively.
During 2020, we and our co-venturer provided member loans to WRB. The outstanding member loan balance at December 31, 2020, was approximately $554 million, of which our share was approximately $277 million.
•Gray Oak Pipeline, LLC-Phillips 66 Partners LP (Phillips 66 Partners) has a consolidated holding company that owns 65% of Gray Oak Pipeline, LLC. Phillips 66 Partners’ effective ownership interest in Gray Oak Pipeline, LLC is 42.25%, after considering a co-venturer’s 35% interest in the consolidated holding company. The Gray Oak Pipeline transports crude oil from the Permian and Eagle Ford to Texas Gulf Coast destinations that include Corpus Christi, Texas, and the Sweeny area, including our Sweeny Refinery. The pipeline commenced full operations in the second quarter of 2020.
In September 2020, Gray Oak Pipeline, LLC closed its offering of $1.4 billion aggregate principal amount of senior unsecured notes with maturities ranging from 2023 to 2027. These senior notes are not guaranteed by Phillips 66 Partners or any of its co-venturers. Net proceeds from the offering were used to repay a third-party term loan of $1,379 million, and for general company purposes. Concurrent with the full repayment of the third-party term loan facility, the associated equity contribution agreement was terminated and Phillips 66 Partners no longer has its proportionate exposure under this equity contribution agreement.
During its development phase, Gray Oak Pipeline, LLC was considered a VIE because it did not have sufficient equity at risk to fully fund the construction of all assets required for principal operations. We determined we were not the primary beneficiary because we and our co-venturers jointly directed the activities of Gray Oak Pipeline, LLC that most significantly impacted economic performance. Gray Oak Pipeline, LLC ceased being a VIE after the commencement of full operations in the second quarter of 2020.
At December 31, 2020 and 2019, Phillips 66 Partners’ investment in the Gray Oak Pipeline had a book value of $860 million and $759 million, respectively. See Note 27-Phillips 66 Partners LP, for additional information regarding Phillips 66 Partners’ ownership in the consolidated holding company and Gray Oak Pipeline, LLC.
•DCP Sand Hills Pipeline, LLC (Sand Hills)-Phillips 66 Partners’ 33 percent-owned joint venture that owns an NGL pipeline system that extends from the Permian Basin and Eagle Ford to facilities on the Texas Gulf Coast and to the Mont Belvieu, Texas, market hub. The Sand Hills Pipeline system is operated by DCP Midstream, LP (DCP Partners). At December 31, 2020 and 2019, the book value of Phillips 66 Partners’ investment in Sand Hills was $582 million and $595 million, respectively.
•Dakota Access, LLC (Dakota Access) and Energy Transfer Crude Oil Company, LLC (ETCO)-Two Phillips 66 Partners 25 percent-owned joint ventures. Dakota Access owns a pipeline system that transports crude oil from the Bakken/Three Forks production area in North Dakota to Patoka, Illinois, and ETCO owns a connecting crude oil pipeline system from Patoka to Nederland, Texas. These two pipeline systems collectively form the Bakken Pipeline system, which is operated by a co-venturer.
In March 2019, a wholly owned subsidiary of Dakota Access closed an offering of $2.5 billion aggregate principal amount of senior unsecured notes, consisting of:
•$650 million aggregate principal amount of 3.625% Senior Notes due 2022.
•$1.0 billion aggregate principal amount of 3.900% Senior Notes due 2024.
•$850 million aggregate principal amount of 4.625% Senior Notes due 2029.
Dakota Access and ETCO have guaranteed repayment of the notes. In addition, Phillips 66 Partners and its co-venturers in Dakota Access provided a Contingent Equity Contribution Undertaking (CECU) in conjunction with the notes offering. Under the CECU, the co-venturers may be severally required to make proportionate equity contributions to Dakota Access if there is an unfavorable final judgment in the ongoing litigation related to an easement granted by the U.S. Army Corps of Engineers (USACE) to allow the pipeline to be constructed under Lake Oahe in North Dakota. Contributions may be required if Dakota Access determines that the issues included in any such final judgment cannot be remediated and Dakota Access has or is projected to have insufficient funds to satisfy repayment of the notes. If Dakota Access undertakes remediation to cure issues raised in a final judgment, contributions may be required if any series of the notes become due, whether by acceleration or at maturity, during such time, to the extent Dakota Access has or is projected to have insufficient funds to pay such amounts. At December 31, 2020, Phillips 66 Partners’ share of the maximum potential equity contributions under the CECU was approximately $631 million.
In March 2020, the trial court presiding over this litigation ordered the USACE to prepare an Environmental Impact Statement (EIS) and requested additional information to enable a decision on whether the Dakota Access Pipeline should be shut down while the EIS is being prepared. In July 2020, the trial court ordered the Dakota Access Pipeline to be shut down and emptied of crude oil within 30 days and that the pipeline should remain shut down pending the preparation of the EIS by the USACE, which the USACE has indicated is expected to take approximately 13 months. Dakota Access filed an appeal and a request for a stay of the order, which was granted. In January 2021, the appellate court affirmed the trial court’s order that: (1) vacated Dakota Access’s easement under Lake Oahe, and (2) directed the USACE to prepare an EIS. The appellate court did not affirm the trial court’s order that the Dakota Access Pipeline be shut down and emptied of crude oil. However, the appellate court acknowledged the precise consequences of the vacated easement remain uncertain. Since the pipeline is now an encroachment, the USACE could seek a shutdown of the pipeline during the preparation of the EIS. Alternatively, the trial court could again issue an injunction that the pipeline be shut down, assuming it makes all findings necessary for injunctive relief. A status hearing is scheduled for April 9, 2021, at which time the parties will discuss the appellate court’s decision and how the USACE plans to proceed given the vacating of the easement.
If the pipeline is required to cease operations pending the preparation of the EIS, and should Dakota Access and ETCO not have sufficient funds to pay ongoing expenses, Phillips 66 Partners also could be required to support its share of the ongoing expenses, including scheduled interest payments on the notes of approximately $25 million annually, in addition to the potential obligations under the CECU.
At December 31, 2020 and 2019, the aggregate book value of Phillips 66 Partners’ investments in Dakota Access and ETCO was $577 million and $592 million, respectively.
•Rockies Express Pipeline LLC (REX)-25 percent-owned joint venture that owns a natural gas pipeline system that extends from Wyoming and Colorado to Ohio with a bidirectional section that extends from Ohio to Illinois. The REX Pipeline system is operated by our co-venturer. In July 2018, we contributed $138 million to REX to cover our 25% share of a $550 million debt repayment. Our capital contribution was included in the “Capital expenditures and investments” line item on our consolidated statement of cash flows.
We have a basis difference for our investment in REX because the carrying value of our investment is lower than our share of REX’s recorded net assets. This basis difference was created by historical impairment charges we recorded for this investment and is being amortized and recognized as a benefit to equity earnings over a period of 25 years, which was the estimated remaining useful life of REX’s PP&E when the impairment charges were recorded. At December 31, 2020, the remaining basis difference for this investment was $319 million. Equity earnings for each of the years ended December 31, 2020, 2019 and 2018, were increased by $19 million due to the amortization of our basis difference. At December 31, 2020 and 2019, the book value of our investment in REX was $547 million and $590 million, respectively.
•CF United LLC (CF United)-In the fourth quarter of 2019, we acquired a 50% voting interest and a 48% economic interest in CF United, a retail marketing joint venture with operations primarily on the U.S. West Coast. CF United is considered a VIE, because our co-venturer has an option to sell its interest to us based on a fixed multiple. The put option becomes effective July 1, 2023, and expires on March 31, 2024. The put option is viewed as a variable interest as the purchase price on the exercise date may not represent the then-current fair value of CF United. We have determined that we are not the primary beneficiary because we and our co-venturer jointly direct the activities of CF United that most significantly impact economic performance. At December 31, 2020, our maximum exposure was comprised of our $332 million investment in CF United and any potential future loss resulting from the put option, if the purchase price based on a fixed multiple exceeds the then-current fair value of CF United. At December 31, 2019, the book value of our investment in CF United was $265 million.
•DCP Midstream, LLC (DCP Midstream)-50 percent-owned joint venture that owns and operates NGL and gas pipelines, gas plants, gathering systems, storage facilities and fractionation plants, through its subsidiary DCP Partners. DCP Midstream markets a portion of its NGL to us and our equity affiliates. On November 6, 2019, DCP Partners completed a transaction to eliminate all general partner economic interests in DCP Partners and incentive distribution rights (IDRs) in exchange for 65 million newly issued DCP Partners common units. At the completion of the transaction, DCP Midstream held a noneconomic general partner interest and approximately 118 million common units, representing approximately 57% of DCP Partners’ outstanding common units.
For the years ended December 31, 2020 and 2019, we recorded a before-tax impairment of $1,161 million and $853 million, respectively, on our investment in DCP Midstream. These impairments increased the difference between the carrying value of our investment in DCP Midstream and our share of DCP Midstream’s net assets at March 31, 2020, to $1.8 billion. This basis difference is being amortized and recognized as a benefit to equity earnings over a period of 22 years, which was the estimated remaining useful life of DCP Midstream’s PP&E at March 31, 2020. Equity earnings for the years ended December 31, 2020 and 2019, were increased by $71 million and $10 million, respectively, due to the amortization of our basis difference. At December 31, 2020, the aggregate remaining basis difference for this investment was $1.7 billion. See Note 9-Impairments and Note 16-Fair Value Measurements for additional information regarding the impairments and the techniques used to determine the fair value of our investment in DCP Midstream. At December 31, 2020 and 2019, the book value of our investment in DCP Midstream was $297 million and $1,374 million, respectively.
•Bayou Bridge Pipeline, LLC (Bayou Bridge)-Phillips 66 Partners’ 40 percent-owned joint venture that owns a pipeline that transports crude oil from Nederland, Texas, to St. James, Louisiana. A segment of the pipeline from Lake Charles to St. James, Louisiana, was completed on April 1, 2019. The Bayou Bridge Pipeline is operated by Phillips 66 Partners’ co-venturer. At December 31, 2020 and 2019, the book value of Phillips 66 Partners’ investment in Bayou Bridge was $288 million and $294 million, respectively.
•Liberty Pipeline LLC (Liberty)-Phillips 66 Partners’ 50 percent-owned joint venture that was formed to develop and construct the Liberty Pipeline system. Upon completion, this pipeline system will transport crude oil from the Rockies and Bakken production areas to Cushing, Oklahoma. Liberty is considered a VIE because it does not have sufficient equity at risk to fully fund the construction of all assets required for principal operations. We have determined we are not the primary beneficiary because we and our co-venturer jointly direct the activities of Liberty that most significantly impact economic performance. The development and construction of the Liberty Pipeline system have been deferred as a result of the current challenging business environment. At December 31, 2020, the book value of Phillips 66 Partners’ investment in Liberty was $241 million.
•DCP Southern Hills Pipeline, LLC (Southern Hills)-Phillips 66 Partners’ 33 percent-owned joint venture that owns an NGL pipeline system that extends from the Midcontinent region to the Mont Belvieu, Texas market hub. The Southern Hills Pipeline system is operated by DCP Partners. At December 31, 2020 and 2019, the book value of Phillips 66 Partners’ investment in Southern Hills was $217 million and $215 million, respectively.
•OnCue Holdings, LLC (OnCue)-50 percent-owned joint venture that owns and operates retail convenience stores. We fully guaranteed various debt agreements of OnCue, and our co-venturer did not participate in the guarantees. This entity is considered a VIE because our debt guarantees resulted in OnCue not being exposed to all potential losses. We have determined we are not the primary beneficiary because we do not have the power to direct the activities that most significantly impact economic performance. At December 31, 2020, our maximum exposure to loss was $172 million, which represented the book value of our investment in OnCue of $96 million and guaranteed debt obligations of $76 million. At December 31, 2019, the book value of our investment in OnCue was $77 million.
Total distributions received from affiliates were $1,717 million, $2,055 million, and $2,942 million for the years ended December 31, 2020, 2019 and 2018, respectively. In addition, at December 31, 2020, retained earnings included approximately $2.4 billion related to the undistributed earnings of affiliated companies.
Summarized 100% financial information for all affiliated companies accounted for under the equity method, on a combined basis, was:
Millions of Dollars
2020 2019 2018
Revenues $ 30,531 38,156 43,627
Income before income taxes 2,104 4,976 6,066
Net income 1,990 4,787 5,926
Current assets 6,210 6,654 6,791
Noncurrent assets 55,806 56,163 52,649
Current liabilities 5,391 6,094 8,047
Noncurrent liabilities 16,887 15,740 10,695
Noncontrolling interests 2,997 2,145 2,550
Note 7-Properties, Plants and Equipment
Our investment in PP&E is recorded at cost. Investments in refining and processing facilities are generally depreciated on a straight-line basis over a 25-year life, pipeline assets over a 45-year life and terminal assets over a 33-year life. The company’s investment in PP&E, with the associated accumulated depreciation and amortization (Accum. D&A), at December 31 was:
Millions of Dollars
2020 2019
Gross
PP&E Accum.
D&A Net
PP&E Gross
PP&E Accum.
D&A Net
PP&E
Midstream $ 12,313 2,815 9,498 11,221 2,391 8,830
Chemicals - - - - - -
Refining
24,647 12,019 12,628 23,692 10,336 13,356
Marketing and Specialties 1,815 1,007 808 1,847 959 888
Corporate and Other 1,448 666 782 1,311 599 712
$ 40,223 16,507 23,716 38,071 14,285 23,786
See Note 9-Impairments, for information regarding the PP&E impairment of our San Francisco Refinery asset group.
Note 8-Goodwill and Intangibles
The carrying amount of goodwill by segment at December 31 was:
Millions of Dollars
Midstream Refining Marketing and Specialties Total
Balance at January 1, 2019 $ 626 1,805 839 3,270
Adjustments - - - -
Balance at December 31, 2019 626 1,805 839 3,270
Asset transfer - 40 (40) -
Impairments* - (1,845) - (1,845)
Balance at December 31, 2020 $ 626 - 799 1,425
* Represents accumulated impairment losses at December 31, 2020.
See Note 9-Impairments, for information regarding the goodwill impairment in the Refining reporting unit.
Intangible Assets
The gross carrying value of indefinite-lived intangible assets at December 31 consisted of the following:
Millions of Dollars
2020 2019
Trade names and trademarks $ 503 503
Refinery air and operating permits 222 249
$ 725 752
The net book value of our amortized intangible assets was $118 million and $117 million at December 31, 2020 and 2019, respectively. Acquisitions of amortized intangible assets were not material in 2020 and 2019. For the years ended December 31, 2020, 2019 and 2018, amortization expense was $27 million, $17 million and $14 million, respectively, and is expected to be less than $20 million per year in future years.
See Note 9-Impairments, for information regarding the intangible asset impairment of our San Francisco Refinery assets group.
Note 9-Impairments
Millions of Dollars
2020 2019 2018
Midstream $ 1,464 858 6
Refining 2,763 3 1
Corporate and Other 25 - 1
Total impairments $ 4,252 861 8
Equity Investments
DCP Midstream
At September 30, 2019, we estimated the fair value of our investment in DCP Midstream was below our book value due to a decline in the market values of DCP Partners common units and its then general partner interest. We concluded this difference was not temporary due to its duration and magnitude, and we recorded an $853 million before-tax impairment in the third quarter of 2019. After the elimination of its general partner economic interests in November 2019, the fair value of our investment in DCP Midstream depends solely on the market value of DCP Partners common units. In the first quarter of 2020, the market value of DCP Partners common units further declined by approximately 85%. As a result, at March 31, 2020, the fair value of our investment in DCP Midstream was significantly lower than its book value. We concluded this difference was not temporary primarily due to its magnitude, and we recorded a $1,161 million before-tax impairment of our investment in the first quarter of 2020.
Red Oak Pipeline LLC (Red Oak)
In the third quarter of 2020, the Red Oak Pipeline project was canceled. As a result, we recorded an $84 million before-tax impairment to reduce the carrying value of our investment to our share of the estimated salvage value of the joint venture’s assets at September 30, 2020.
Other
In the fourth quarter of 2020, Phillips 66 Partners assessed for impairment its equity method investments in two crude oil transportation and terminaling joint ventures, and concluded that the carrying values of these investments at December 31, 2020, were greater than their fair values. Phillips 66 Partners concluded these differences were not temporary, based on its projections of future crude oil production. As a result, Phillips 66 Partners recorded before-tax impairments totaling $96 million.
PP&E and Intangible Assets
In the third quarter of 2020, we announced a plan to reconfigure our San Francisco Refinery to produce renewable fuels at the Rodeo refining facility in Rodeo, California, starting in early 2024. Consequently, we plan to cease operation of the Santa Maria refining facility in Arroyo Grande, California, certain assets at the Rodeo refining facility, and associated Midstream assets in 2023. We assessed the San Francisco Refinery asset group for impairment and concluded that the carrying value of the asset group was not recoverable. As a result, we recorded a $1,030 million before-tax impairment to reduce the carrying value of the net PP&E and intangible assets in this asset group to its fair value of $940 million. The impairment resulted in a reduction of net PP&E totaling $1,009 million and intangible assets of $21 million. This impairment was primarily related to our Refining segment, with the exception of $120 million that was related to PP&E in our Midstream segment.
Goodwill
Our stock price declined significantly in the first quarter of 2020, mainly due to the disruption in global commodity and equity markets related to the COVID-19 pandemic. We assessed our goodwill for impairment due to the decline in our market capitalization and concluded that the carrying value of our Refining reporting unit at March 31, 2020, was greater than its fair value by an amount in excess of its goodwill balance. Accordingly, we recorded a before-tax goodwill impairment charge of $1,845 million in our Refining segment during the first quarter of 2020.
These impairment charges are included within the “Impairments” line item on our consolidated statement of operations. See Note 16-Fair Value Measurements for additional information on the determination of fair value used to record these impairments.
Outlook
The COVID-19 pandemic continues to disrupt economic activities globally. Reduced demand for petroleum products has resulted in low crude oil prices and refining margins, as well as decreased volumes through refineries and logistics infrastructure. The depth and duration of the economic consequences of the COVID-19 pandemic remain unknown. We continuously monitor our asset and investment portfolio for impairments, as well as optimization opportunities, in this challenging business environment. As such, additional impairments may be required in the future.
Note 10-Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
Millions of Dollars
2020 2019
Asset retirement obligations $ 309 280
Accrued environmental costs 427 441
Total asset retirement obligations and accrued environmental costs 736 721
Asset retirement obligations and accrued environmental costs due within one year*
(79) (83)
Long-term asset retirement obligations and accrued environmental costs $ 657 638
* Classified as a current liability on the consolidated balance sheet, under the caption “Other accruals.”
Asset Retirement Obligations
We have asset retirement obligations that we are required to perform under law or contract once an asset is permanently taken out of service. Most of these obligations are not expected to be paid until many years in the future and are expected to be funded from general company resources at the time of removal. Our largest individual obligations involve asbestos abatement at refineries.
During the years ended December 31, 2020 and 2019, our overall asset retirement obligation changed as follows:
Millions of Dollars
2020 2019
Balance at January 1 $ 280 261
Accretion of discount 15 10
New obligations 10 -
Changes in estimates of existing obligations 14 31
Spending on existing obligations (11) (22)
Foreign currency translation 1 -
Balance at December 31 $ 309 280
Accrued Environmental Costs
For the year ended December 31, 2020, the $14 million decrease in total accrued environmental costs was due to payments and settlements during the year, which exceeded new accruals, accrual adjustments and accretion.
Of our total accrued environmental costs at December 31, 2020, $245 million was primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations; $130 million was associated with nonoperator sites; and $52 million was related to sites at which we have been named a potentially responsible party under federal or state laws. A large portion of our expected environmental expenditures have been discounted as these obligations were acquired in various business combinations. Expected expenditures for acquired environmental obligations were discounted using a weighted-average discount rate of approximately 5%. At December 31, 2020, the accrued balance for acquired environmental liabilities was $238 million. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $18 million in 2021, $27 million in 2022, $21 million in 2023, $21 million in 2024, $16 million in 2025, and $199 million in the aggregate for all years after 2025.
Note 11-Earnings (Loss) Per Share
The numerator of basic earnings (loss) per share (EPS) is net income (loss) attributable to Phillips 66, adjusted for 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 (loss) 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 (loss) 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.
2020 2019 2018
Basic Diluted Basic Diluted Basic Diluted
Amounts Attributed to Phillips 66 Common Stockholders (millions):
Net income (loss) attributable to Phillips 66 $ (3,975) (3,975) 3,076 3,076 5,595 5,595
Income allocated to participating securities (8) (8) (6) (2) (6) -
Net income (loss) available to common stockholders $ (3,983) (3,983) 3,070 3,074 5,589 5,595
Weighted-average common shares outstanding (thousands):
437,327 439,530 448,787 451,364 467,483 470,708
Effect of share-based compensation 2,203 - 2,577 2,524 3,225 3,339
Weighted-average common shares outstanding-EPS
439,530 439,530 451,364 453,888 470,708 474,047
Earnings (Loss) Per Share of Common Stock (dollars)
$ (9.06) (9.06) 6.80 6.77 11.87 11.80
Note 12-Debt
Short-term and long-term debt at December 31 was:
Millions of Dollars
2020 2019
Phillips 66
4.300% Senior Notes due April 2022
$ 2,000 2,000
3.700% Senior Notes due April 2023
500 -
0.900% Senior Notes due February 2024
800 -
3.850% Senior Notes due April 2025
650 -
1.300% Senior Notes due February 2026
500 -
3.900% Senior Notes due March 2028
800 800
2.150% Senior Notes due December 2030
850 -
4.650% Senior Notes due November 2034
1,000 1,000
5.875% Senior Notes due May 2042
1,500 1,500
4.875% Senior Notes due November 2044
1,700 1,700
Floating Rate Notes due April 2020 at 2.751% at year-end 2019
- 300
Term Loan due April 2020 at 2.699% at year-end 2019
- 200
Term Loan due November 2023 at 1.397% at year-end 2020
500 -
Floating Rate Senior Notes due February 2021 at 0.833% and 2.517% at year-end 2020 and 2019, respectively
500 500
Floating Rate Senior Notes due February 2024 at 0.840% at year-end 2020
450 -
Floating Rate Advance Term Loan due December 2034 at 0.755% and 2.392% at year-end 2020 and 2019, respectively-related party
25 25
Other 1 1
Phillips 66 Partners
2.450% Senior Notes due December 2024
300 300
3.605% Senior Notes due February 2025
500 500
3.550% Senior Notes due October 2026
500 500
3.750% Senior Notes due March 2028
500 500
3.150% Senior Notes due December 2029
600 600
4.680% Senior Notes due February 2045
450 450
4.900% Senior Notes due October 2046
625 625
Tax-Exempt Bonds due April 2020 and April 2021 at weighted-average rates of 0.360% and 1.850% at year-end 2020 and 2019, respectively
50 75
Revolving Credit Facility due January 2021 at weighted-average rate of 1.397% at year-end 2020
415 -
Debt at face value
15,716 11,576
Finance leases
264 277
Software obligations
19 10
Net unamortized discounts and debt issuance costs
(106) (100)
Total debt
15,893 11,763
Short-term debt
(987) (547)
Long-term debt
$ 14,906 11,216
Maturities of borrowings outstanding at December 31, 2020, inclusive of net unamortized discounts and debt issuance costs, for each of the years from 2021 through 2025 are $987 million, $2,017 million, $1,015 million, $1,560 million and $1,176 million, respectively.
2020 Debt Issuances and Repayments
Senior Unsecured Notes
On November 18, 2020, Phillips 66 closed its public offering of $1.75 billion aggregate principal amount of senior unsecured notes consisting of:
•$450 million aggregate principal amount of Floating Rate Senior Notes due 2024 (the Floating Rate Notes).
•$800 million aggregate principal amount of 0.900% Senior Notes due 2024.
•$500 million aggregate principal amount of 1.300% Senior Notes due 2026.
The Floating Rate Notes will bear interest at a floating rate, reset quarterly, equal to the three-month London Interbank Offered Rate (LIBOR) plus 0.62% per year, subject to adjustment. Interest on the Senior Notes due 2024 and 2026 is payable semiannually on February 15 and August 15 of each year, commencing on February 15, 2021.
Proceeds received from the public offering of senior unsecured notes on November 18, 2020, were $1.74 billion, net of underwriters’ discounts and commissions, as well as debt issuance costs. On November 19, 2020, a portion of these proceeds were used to repay $500 million of outstanding borrowings under the term loan facility that Phillips 66 entered into in March 2020 (see the “Term Loan Facility” section below for a full description of the term loan facility). In addition, a portion of the proceeds will be used to repay the $500 million aggregate principal amount of our outstanding Floating Rate Senior Notes due February 2021. The remainder of the proceeds are being used for general corporate purposes.
On June 10, 2020, Phillips 66 closed its public offering of $1 billion aggregate principal amount of senior unsecured notes consisting of:
•$150 million aggregate principal amount of 3.850% Senior Notes due 2025.
•$850 million aggregate principal amount of 2.150% Senior Notes due 2030.
On April 9, 2020, Phillips 66 closed its public offering of $1 billion aggregate principal amount of senior unsecured notes consisting of:
•$500 million aggregate principal amount of 3.700% Senior Notes due 2023.
•$500 million aggregate principal amount of 3.850% Senior Notes due 2025.
Interest on the Senior Notes due 2023 is payable semiannually on April 6 and October 6 of each year, commencing on October 6, 2020. The Senior Notes due 2025 issued on June 10, 2020, constitute a further issuance of the Senior Notes due 2025 originally issued on April 9, 2020. The $650 million in aggregate principal amount of Senior Notes due 2025 is treated as a single class of debt securities. Interest on the Senior Notes due 2025 is payable semiannually on April 9 and October 9 of each year, commencing on October 9, 2020. Interest on the Senior Notes due 2030 is payable semiannually on June 15 and December 15 of each year, commencing on December 15, 2020.
Proceeds received from the public offerings of senior unsecured notes on June 10, 2020, and April 9, 2020, were $1,008 million and $993 million, respectively, net of underwriters’ discounts or premiums and commissions, as well as debt issuance costs. These proceeds are being used for general corporate purposes.
Term Loan Facility
On March 19, 2020, Phillips 66 entered into a $1 billion 364-day delayed draw term loan agreement (the Facility) and borrowed $1 billion under the Facility shortly thereafter. On April 6, 2020, Phillips 66 increased the size of the Facility to $2 billion, and in June 2020, the Facility was amended to extend the commitment period to September 19, 2020. We did not draw additional amounts under the Facility before the end of the commitment period or further extend the commitment period. In November 2020, we repaid $500 million of borrowings outstanding under the Facility, and the Facility was amended to extend the maturity date of the remaining $500 million outstanding borrowings from March 18, 2021, to November 20, 2023. Borrowings under the Facility bear interest at a floating rate based on either the Eurodollar rate or the reference rate, plus a margin determined by the credit rating of Phillips 66’s senior unsecured long-term debt. Phillips 66 is using the proceeds for general corporate purposes.
Other Debt Repayments
In April 2020, Phillips 66 repaid $300 million outstanding principal balance of its floating-rate notes due April 2020 and $200 million outstanding principal balance under the term loan facility due April 2020. Also in April 2020, Phillips 66 Partners repaid a $25 million tranche of its tax-exempt bonds due April 2020.
2019 Debt Issuances and Repayments
On October 15, 2019, Phillips 66 Partners repaid the aggregate $300 million outstanding principal balance of its 2.646% Senior Notes due February 2020.
On September 13, 2019, Phillips 66 Partners repaid the aggregate $400 million outstanding principal balance of the senior unsecured term loan facility that was drawn during the first half of 2019.
On September 6, 2019, Phillips 66 Partners closed on a public offering of $900 million aggregate principal amount of unsecured notes consisting of:
•$300 million aggregate principal amount of 2.450% Senior Notes due December 15, 2024.
•$600 million aggregate principal amount of 3.150% Senior Notes due December 15, 2029.
Interest on each series of senior notes is payable semiannually in arrears on June 15 and December 15 of each year, commencing on June 15, 2020. Net proceeds from the Senior Notes offering were used for the September 13, 2019 and October 15, 2019 debt repayments noted above and general business purposes.
On March 22, 2019, Phillips 66 Partners entered into a senior unsecured term loan facility with a borrowing capacity of $400 million due March 20, 2020. Phillips 66 Partners borrowed an aggregate amount of $400 million under the facility during the first half of 2019, which was repaid in full in September 2019.
Revolving Credit Facilities and Commercial Paper
Phillips 66 has a $5 billion revolving credit facility which may be used for direct bank borrowings, as support for issuances of letters of credit, and as support for our commercial paper program. We have an option to increase the overall capacity to $6 billion, subject to certain conditions. We also have the option to extend the scheduled maturity of the facility for up to two additional one-year terms after its July 30, 2024, maturity date, subject to, among other things, the consent of the lenders holding the majority of the commitments and of each lender extending its commitment. The facility is with a broad syndicate of financial institutions and contains covenants that are usual and customary for an agreement of this type, including a maximum consolidated net debt-to-capitalization ratio of 65% as of the last day of each fiscal quarter. The facility has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; and violation of covenants. Outstanding borrowings under the facility bear interest, at our option, at either: (a) the Eurodollar rate in effect from time to time plus the applicable margin; or (b) the reference rate (as described in the facility) plus the applicable margin. The facility also provides for customary fees, including commitment fees. The pricing levels for the commitment fees and interest-rate margins are determined based on the ratings in effect for Phillips 66’s senior unsecured long-term debt from time to time. Phillips 66 may at any time prepay outstanding borrowings under the facility, in whole or in part, without premium or penalty. At December 31, 2020 and 2019, no amount had been drawn under the facility.
Phillips 66 also has a $5 billion uncommitted commercial paper program for short-term working capital needs that is supported by our revolving credit facility. Commercial paper maturities are contractually limited to 365 days. At December 31, 2020 and 2019, no borrowings were outstanding under the program.
Phillips 66 Partners has a $750 million revolving credit facility which may be used for direct bank borrowings and as support for issuances of letters of credit. Phillips 66 Partners has an option to increase the overall capacity to $1 billion, subject to certain conditions. Phillips 66 Partners also has the option to extend the facility for two additional one-year terms after its July 30, 2024, maturity date, subject to, among other things, the consent of the lenders holding the majority of the commitments and of each lender extending its commitment. The facility is with a broad syndicate of financial institutions and contains covenants that are usual and customary for an agreement of this type. The facility has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; and violation of covenants. Outstanding revolving borrowings under the facility bear interest, at Phillips 66 Partners’ option, at either: (a) the Eurodollar rate in effect from time to time plus the applicable margin; or (b) the reference rate (as described in the facility) plus the applicable margin. The facility also provides for customary fees, including commitment fees. The pricing levels for the commitment fees and interest-rate margins are determined based on Phillips 66 Partners’ credit ratings in effect from time to time. Borrowings under the facility may be short-term or long-term in duration, and Phillips 66 Partners may at any time prepay outstanding borrowings under the facility, in whole or in part, without premium or penalty. At December 31, 2020, borrowings of $415 million were outstanding under this facility, compared with no borrowings outstanding at December 31, 2019. At both December 31, 2020 and 2019, $1 million in letters of credit had been issued that were supported by this facility.
We had approximately $5.3 billion and $5.7 billion of total committed capacity available under our revolving credit facilities at December 31, 2020 and 2019, respectively.
Note 13-Guarantees
At December 31, 2020, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantees and expect future performance to be either immaterial or have only a remote chance of occurrence.
Lease Residual Value Guarantees
In September 2020, we amended the operating lease agreement for our headquarters facility in Houston, Texas, and extended the lease term from June 2021 to September 2025. Under this agreement, we have the option, at the end of the lease term, to request to renew the lease, purchase the facility or assist the lessor in marketing it for resale. We have a residual value guarantee associated with the operating lease agreement with a maximum potential future exposure of $514 million at December 31, 2020. We also have residual value guarantees associated with railcar and airplane leases with maximum potential future payments totaling $381 million. These operating leases have remaining terms of up to nine years.
Guarantees of Joint Venture and Other Obligations
In March 2019, Phillips 66 Partners and its co-venturers in Dakota Access provided a CECU in conjunction with a senior unsecured notes offering. See Note 6-Investments, Loans and Long-Term Receivables, for additional information on Dakota Access and the CECU.
Gray Oak Pipeline, LLC had a third-party term loan facility with a borrowing capacity of $1,379 million, inclusive of accrued interest. Phillips 66 Partners and its co-venturers provided a guarantee through an equity contribution agreement requiring proportionate equity contributions to Gray Oak Pipeline, LLC up to the total outstanding loan amount, plus any additional accrued interest and associated fees, if Gray Oak Pipeline, LLC defaulted on certain of its obligations thereunder. In September 2020, concurrent with the full repayment of a third-party term loan facility by Gray Oak Pipeline, LLC, the associated guarantee issued by Phillips 66 Partners through an equity contribution agreement was terminated. See Note 6-Investments, Loans and Long-Term Receivables, for additional information on Gray Oak Pipeline, LLC.
At December 31, 2020, we also had other guarantees outstanding for our portion of certain joint venture debt obligations and purchase obligations, which have remaining terms of up to seven years. The maximum potential amount of future payments to third parties under these guarantees was approximately $191 million. Payment would be required if a joint venture defaults on its obligations.
Indemnifications
Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to indemnification. Agreements associated with these sales include indemnifications for taxes, litigation, environmental liabilities, permits and licenses, employee claims, and real estate tenant defaults. The provisions of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, which generally have indefinite terms and potentially unlimited exposure. At December 31, 2020 and 2019, the carrying amount of recorded indemnifications was $145 million and $153 million, respectively.
We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information to support the reversal. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. At December 31, 2020 and 2019, environmental accruals for known contamination of $104 million and $105 million, respectively, were included in the carrying amount of the recorded indemnifications noted above. These environmental accruals were primarily included in the “Asset retirement obligations and accrued environmental costs” line item on our consolidated balance sheet. For additional information about environmental liabilities, see Note 10-Asset Retirement Obligations and Accrued Environmental Costs and Note 14-Contingencies and Commitments.
Indemnification and Release Agreement
In 2012, in connection with our separation from ConocoPhillips, we entered into an Indemnification and Release Agreement. This agreement governs the treatment between ConocoPhillips and us of matters relating to indemnification, insurance, litigation responsibility and management, and litigation document sharing and cooperation arising in connection with the separation. Generally, the agreement provides for cross-indemnities principally designed to place financial responsibility for the obligations and liabilities of our business with us and financial responsibility for the obligations and liabilities of ConocoPhillips’ business with ConocoPhillips. The agreement also establishes procedures for handling claims subject to indemnification and related matters.
Note 14-Contingencies and Commitments
A number of lawsuits involving a variety of claims that arose in the ordinary course of business have been filed against us or are subject to indemnifications provided by us. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for financial recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. See Note 21-Income Taxes, for additional information about income-tax-related contingencies.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other potentially responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Environmental
We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using information available at the time. We measure estimates and base contingent liabilities on currently available facts, existing technology and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring contingent environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the EPA or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.
Although liability for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies alleged to have liability at a particular site. Due to such joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites 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 the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit, although some of the indemnifications are subject to dollar and time limits.
We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those pertaining to sites acquired in a business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings. See Note 10-Asset Retirement Obligations and Accrued Environmental Costs, for a summary of our accrued environmental liabilities.
Legal Proceedings
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases and enables the tracking of those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.
Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized.
At December 31, 2020, we had performance obligations secured by letters of credit and bank guarantees of $538 million related to various purchase and other commitments incident to the ordinary conduct of business.
Long-Term Throughput Agreements and Take-or-Pay Agreements
We have certain throughput agreements and take-or-pay agreements in support of third-party financing arrangements. The agreements typically provide for crude oil transportation to be used in the ordinary course of our business. At December 31, 2020, the estimated aggregate future payments under these agreements were $324 million per year for each year from 2021 through 2025 and $1,676 million in aggregate for all years after 2025. For the years ended December 31, 2020, 2019 and 2018, total payments under these agreements were $320 million, $321 million and $323 million, respectively.
Note 15-Derivatives and Financial Instruments
Derivative Instruments
We use financial and commodity-based derivative contracts to manage exposures to fluctuations in commodity prices, interest rates and foreign currency exchange rates, or to capture market opportunities. Because we do not apply hedge accounting for commodity derivative contracts, all realized and unrealized gains and losses from commodity derivative contracts are recognized in our consolidated statement of operations. Gains and losses from derivative contracts held for trading not directly related to our physical business are reported net in the “Other income” line item on our consolidated statement of operations. Cash flows from all our derivative activity for the periods presented appear in the operating section on our consolidated statement of cash flows.
Purchase and sales contracts with firm minimum notional volumes for commodities that are readily convertible to cash are recorded on our consolidated balance sheet as derivatives unless the contracts are eligible for, and we elect, the normal purchases and normal sales exception, whereby the contracts are recorded on an accrual basis. We generally apply the normal purchases and normal sales exception to eligible crude oil, refined petroleum product, NGL, natural gas and power commodity contracts to purchase or sell quantities we expect to use or sell in the normal course of business. All other derivative instruments are recorded at fair value on our consolidated balance sheet. For further information on the fair value of derivatives, see Note 16-Fair Value Measurements.
Commodity Derivative Contracts-We sell into or receive supply from the worldwide crude oil, refined petroleum product, NGL, natural gas and electric power markets, exposing our revenues, purchases, cost of operating activities and cash flows to fluctuations in the prices for these commodities. Generally, our policy is to remain exposed to the market prices of commodities; however, we use futures, forwards, swaps and options in various markets to balance physical systems, meet customer needs, manage price exposures on specific transactions, and do a limited amount of trading not directly related to our physical business, all of which may reduce our exposure to fluctuations in market prices. We also use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades.
The following table indicates the consolidated balance sheet line items that include the fair values of commodity derivative assets and liabilities. The balances in the following table are presented on a gross basis, before the effects of counterparty and collateral netting. However, we have elected to present our commodity derivative assets and liabilities with the same counterparty on a net basis on our consolidated balance sheet when the legal right of offset exists.
Millions of Dollars
December 31, 2020 December 31, 2019
Commodity Derivatives Effect of Collateral Netting Net Carrying Value Presented on the Balance Sheet Commodity Derivatives Effect of Collateral Netting Net Carrying Value Presented on the Balance Sheet
Assets Liabilities Assets Liabilities
Assets
Prepaid expenses and other current assets $ 13 - - 13 23 - - 23
Other assets 5 (4) - 1 3 - - 3
Liabilities
Other accruals 665 (721) 46 (10) 1,188 (1,281) 80 (13)
Other liabilities and deferred credits - - - - - (1) - (1)
Total $ 683 (725) 46 4 1,214 (1,282) 80 12
At December 31, 2020 and 2019, there was no material cash collateral received or paid that was not offset on our consolidated balance sheet.
The realized and unrealized gains (losses) incurred from commodity derivatives, and the line items where they appear on our consolidated statement of operations, were:
Millions of Dollars
2020 2019 2018
Sales and other operating revenues $ 436 (150) 192
Other income 10 33 (15)
Purchased crude oil and products 174 (161) (64)
Net gain (loss) from commodity derivative activity $ 620 (278) 113
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 nonderivative positions such as inventory volumes. Financial derivative contracts may also offset physical derivative contracts, such as forward purchase and sales contracts. The percentage of our derivative contract volumes expiring within the next 12 months was at least 98% at December 31, 2020 and 2019.
Open Position
Long / (Short)
2020 2019
Commodity
Crude oil, refined petroleum products and NGL (millions of barrels)
(13) (16)
Interest Rate Derivative Contracts-In 2016, we entered into interest rate swaps to hedge the variability of lease payments on our headquarters facility. These monthly lease payments vary based on monthly changes in the one-month LIBOR and changes, if any, in our credit rating over the five-year term of the lease. The pay-fixed, receive-floating interest rate swaps have an aggregate notional value of $650 million and end in April 2021. We have designated these swaps as cash flow hedges.
The aggregate net fair value of these swaps was immaterial at December 31, 2020 and 2019.
We report the mark-to-market gains or losses on our interest rate swaps designated as highly effective cash flow hedges as a component of other comprehensive income (loss), and reclassify such gains and losses into earnings in the same period during which the hedged transaction affects earnings. Net realized gains and losses from settlements of the swaps were immaterial for the years ended December 31, 2020 and 2019.
We currently estimate that before-tax losses of $3 million will be reclassified from accumulated other comprehensive loss into general and administrative expenses during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will vary based on changes in interest rates.
Credit Risk from Derivative Instruments
Financial instruments potentially exposed to concentrations of credit risk consist primarily of trade receivables and derivative contracts.
Our trade receivables result primarily from the sale of products from, or related to, our refinery operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less. We continually monitor this exposure and the creditworthiness of the counterparties and recognize bad debt expense based on a probability assessment of credit loss. Generally, we do not require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments or master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us to others to be offset against amounts owed to us.
The credit risk from our derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements, typically on a daily basis, until settled.
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if our credit ratings fall below investment grade. Cash is the primary collateral in all contracts; however, many contracts also permit us to post letters of credit as collateral.
The aggregate fair values of all derivative instruments with such credit-risk-related contingent features that were in a liability position were immaterial at December 31, 2020 and 2019.
Note 16-Fair Value Measurements
Recurring Fair Value Measurements
We carry certain assets and liabilities at fair value, which we measure at the reporting date using the price that would be received to sell an asset or paid to transfer a liability (i.e., an exit price), and disclose the quality of these fair values based on the valuation inputs used in these measurements under the following hierarchy:
•Level 1: Fair value measured with unadjusted quoted prices from an active market for identical assets or liabilities.
•Level 2: Fair value measured either with: (1) adjusted quoted prices from an active market for similar assets or liabilities; or (2) other valuation inputs that are directly or indirectly observable.
•Level 3: Fair value measured with unobservable inputs that are significant to the measurement.
We classify the fair value of an asset or liability based on the significance of its observable or unobservable inputs to the measurement. However, the fair value of an asset or liability initially reported as Level 3 will be subsequently reported as Level 2 if the unobservable inputs become inconsequential to its measurement or corroborating market data becomes available. Conversely, an asset or liability initially reported as Level 2 will be subsequently reported as Level 3 if corroborating market data becomes unavailable.
We used the following methods and assumptions to estimate the fair value of financial instruments:
•Cash and cash equivalents-The carrying amount reported on our consolidated balance sheet approximates fair value.
•Accounts and notes receivable-The carrying amount reported on our consolidated balance sheet approximates fair value.
•Derivative instruments-We fair value our exchange-traded contracts based on quoted market prices obtained from the New York Mercantile Exchange, the Intercontinental Exchange or other exchanges, and classify them as Level 1 in the fair value hierarchy. When exchange-cleared contracts lack sufficient liquidity, or are valued using either adjusted exchange-provided prices or nonexchange quotes, we classify those contracts as Level 2.
Physical commodity forward purchase and sales contracts and over-the-counter (OTC) financial swaps are generally valued using forward quotes provided by brokers and price index developers, such as Platts and Oil Price Information Service. We corroborate these quotes with market data and classify the resulting fair values as Level 2. When forward market prices are not available, we estimate fair value using the forward price of a similar commodity, adjusted for the difference in quality or location. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, physical commodity purchase and sales contracts and OTC swaps are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. We classify these contracts as Level 3. Physical and OTC commodity options are valued using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines whether the options are classified as Level 2 or 3. We use a midmarket pricing convention (the midpoint between bid and ask prices). When appropriate, valuations are adjusted to reflect credit considerations, generally based on available market evidence.
We determine the fair value of our interest rate swaps based on observable market valuations for interest rate swaps that have notional amounts, terms and pay and reset frequencies similar to ours.
•Rabbi trust assets-These deferred compensation investments are measured at fair value using unadjusted quoted prices available from national securities exchanges and are therefore categorized as Level 1 in the fair value hierarchy.
•Debt-The carrying amount of our floating-rate debt approximates fair value. The fair value of our fixed-rate debt is estimated based on observable market prices.
The following tables display the fair value hierarchy for our financial assets and liabilities either accounted for or disclosed at fair value on a recurring basis. These values are determined by treating each contract as the fundamental unit of account; therefore, derivative assets and liabilities with the same counterparty are shown on a gross basis in the hierarchy sections of these tables, before the effects of counterparty and collateral netting. The following tables also reflect the effect of netting derivative assets and liabilities with the same counterparty for which we have the legal right of offset and collateral netting.
The carrying values and fair values by hierarchy of our financial assets and liabilities, either carried or disclosed at fair value, including any effects of counterparty and collateral netting, were:
Millions of Dollars
December 31, 2020
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
Level 1 Level 2 Level 3
Commodity Derivative Assets
Exchange-cleared instruments $ 314 356 - 670 (669) - - 1
Physical forward contracts - 13 - 13 - - - 13
Rabbi trust assets 143 - - 143 N/A N/A - 143
$ 457 369 - 826 (669) - - 157
Commodity Derivative Liabilities
Exchange-cleared instruments $ 351 364 - 715 (669) (46) - -
Physical forward contracts - 10 - 10 - - - 10
Interest-rate derivatives - 3 - 3 - - - 3
Floating-rate debt - 1,940 - 1,940 N/A N/A - 1,940
Fixed-rate debt, excluding finance leases - 15,597 - 15,597 N/A N/A (1,927) 13,670
$ 351 17,914 - 18,265 (669) (46) (1,927) 15,623
Millions of Dollars
December 31, 2019
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
Level 1 Level 2 Level 3
Commodity Derivative Assets
Exchange-cleared instruments $ 820 368 - 1,188 (1,188) - - -
Physical forward contracts - 26 - 26 - - - 26
Interest rate derivatives - 1 - 1 - - - 1
Rabbi trust assets 127 - - 127 N/A N/A - 127
$ 947 395 - 1,342 (1,188) - - 154
Commodity Derivative Liabilities
Exchange-cleared instruments $ 884 385 - 1,269 (1,188) (80) - 1
OTC instruments - 1 - 1 - - - 1
Physical forward contracts - 12 - 12 - - - 12
Floating-rate debt - 1,100 - 1,100 N/A N/A - 1,100
Fixed-rate debt, excluding finance leases
- 11,813 - 11,813 N/A N/A (1,438) 10,375
$ 884 13,311 - 14,195 (1,188) (80) (1,438) 11,489
The rabbi trust assets are recorded in the “Investments and long-term receivables” line item, and floating-rate and fixed-rate debt are recorded in the “Short-term debt” and “Long-term debt” line items on our consolidated balance sheet. See Note 15-Derivatives and Financial Instruments, for information regarding where the assets and liabilities related to our commodity and interest rate derivatives are recorded on our consolidated balance sheet.
Nonrecurring Fair Value Measurements
Equity Investments
In the first quarter of 2020, the nonrecurring fair value measurement used to record an impairment of our DCP Midstream investment was the fair value of our share of DCP Midstream’s limited partner interest in DCP Partners, which was estimated based on average market prices of DCP Partners common units for a multi-day trading period encompassing March 31, 2020. This valuation resulted in a Level 2 nonrecurring fair value measurement.
In the third quarter of 2019, the nonrecurring fair value measurement used to record an impairment of our DCP Midstream investment consisted of:
•The fair value of our share of DCP Midstream’s limited partner interest in DCP Partners, which was estimated based on an average market price of DCP Partners common units for a multi-day trading period encompassing September 30, 2019.
•The fair value of our share of DCP Midstream’s general partner interest in DCP Partners, which was estimated using two primary inputs: 1) estimated future cash flows of distributions attributable to the incentive distribution rights from DCP Partners, and 2) a multiple of those cash flows based on internal estimates and observation of IDR conversion transactions by other master limited partnerships.
Overall, we concluded the third-quarter 2019 valuation resulted in a Level 3 nonrecurring fair value measurement.
In the fourth quarter of 2020, the nonrecurring fair value measurements used by Phillips 66 Partners to impair its equity method investments in two crude oil transportation and terminaling joint ventures were calculated by weighting the results of different economic scenarios using the income approach. The income approach uses a discounted cash flow model that requires various observable and nonobservable inputs, including volumes, rates/tariffs, expenses and discount rates. These valuations resulted in a Level 3 nonrecurring fair value measurement.
PP&E and Intangible Assets
In the third quarter of 2020, we remeasured the carrying value of the net PP&E and intangible assets of our San Francisco Refinery asset group to fair value. The estimated fair value of the plants, equipment and intangible assets was determined using a replacement cost approach adjusted, as applicable, for physical deterioration, functional obsolescence and economic obsolescence. The estimated fair value of the properties was determined using a sales comparison approach. This valuation resulted in a Level 3 nonrecurring fair value measurement.
Goodwill
The carrying value of the Refining reporting unit’s goodwill was remeasured to fair value on a nonrecurring basis in the first quarter of 2020. The fair value of the Refining reporting unit was calculated by weighting the results from the income approach and the market approach. The income approach uses a discounted cash flow model that requires various observable and nonobservable inputs, such as prices, volumes, expenses, capital expenditures, discount rates and projected long-term growth rates and terminal values. The market approach uses peer company enterprise values relative to current and future net income (loss) before net interest expense, income taxes, depreciation and amortization (EBITDA) projections to arrive at an average multiple. This multiple was applied to the reporting unit’s current and projected EBITDA, with consideration for an estimated market participant acquisition premium. The resulting fair value Level 3 estimate was less than the Refining reporting unit’s carrying value by an amount that exceeded the existing goodwill balance of the reporting unit. As a result, the Refining reporting unit’s goodwill was impaired to zero. As part of our impairment analysis, the fair value of all reporting units was reconciled to the company’s market capitalization.
See Note 9-Impairments, for additional information on the above impairments.
Note 17-Equity
Preferred Stock
We have 500 million shares of preferred stock authorized, with a par value of $0.01 per share, none of which have been issued.
Treasury Stock
Since July 2012, our Board of Directors has authorized an aggregate of $15 billion of repurchases of our outstanding common stock. The authorizations do not have expiration dates. The share repurchases are expected to be funded primarily through available cash. We are not obligated to repurchase any shares of common stock pursuant to these authorizations and may commence, suspend or terminate repurchases at any time. Since the inception of our share repurchase program in 2012 through December 31, 2020, we have repurchased a total of 159,349,212 shares at an aggregate cost of $12.5 billion. Shares of stock repurchased are held as treasury shares. We suspended share repurchases in mid-March 2020 to preserve liquidity in response to the global economic disruption caused by the COVID-19 pandemic.
In February 2018, we entered into a Stock Purchase and Sale Agreement (Purchase Agreement) with Berkshire Hathaway Inc. and National Indemnity Company, a wholly owned subsidiary of Berkshire Hathaway, to repurchase 35,000,000 shares of Phillips 66 common stock for an aggregate purchase price of $3,280 million. Pursuant to the Purchase Agreement, the purchase price per share of $93.725 was based on the volume-weighted-average price of our common stock on the New York Stock Exchange on February 13, 2018. The transaction closed in February 2018. We funded the repurchase with cash of $1,880 million and borrowings of $1,400 million under our commercial paper program. These borrowings were subsequently refinanced through a public offering of senior notes. This specific share repurchase transaction was separately authorized by our Board of Directors and therefore did not impact previously announced authorizations under our share repurchase program.
In 2014, we completed the exchange of our flow improver business for shares of Phillips 66 common stock owned by the other party to the transaction. We received 17,422,615 shares of our common stock with a fair value at the time of the exchange of $1,350 million. This specific share repurchase transaction was also separately authorized by our Board of Directors and therefore did not impact previously announced authorizations under our share repurchase program.
Common Stock Dividends
On February 10, 2021, our Board of Directors declared a quarterly cash dividend of $0.90 per common share, payable March 1, 2021, to holders of record at the close of business on February 22, 2021.
Noncontrolling Interests
Our noncontrolling interests primarily represent issuances of common and preferred units to the public by Phillips 66 Partners. See Note 27-Phillips 66 Partners LP, for information on Phillips 66 Partners.
Note 18-Leases
We lease marine vessels, pipelines, storage tanks, railcars, service station sites, office buildings, corporate aircraft, land and other facilities and equipment. In determining whether an agreement contains a lease, we consider our ability to control the asset and whether third-party participation or vendor substitution rights limit our control. 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. Renewal options have been included only when reasonably certain of exercise. There are no significant restrictions imposed on us in our lease agreements with regards to dividend payments, asset dispositions or borrowing ability. Certain leases have residual value guarantees, which may require additional payments at the end of the lease term if future fair values decline below contractual lease balances.
In our implementation of ASU No. 2016-02, we elected to discount lease obligations using our incremental borrowing rate. Furthermore, we elected to separate costs for lease and service components for contracts involving marine vessels and consignment service stations. For these contracts, we allocate the consideration payable between the lease and service components using the relative standalone prices of each component. For contracts involving all other asset types, we elected the practical expedient to account for the lease and service components on a combined basis. Our right of way agreements in effect prior to January 1, 2019, were not accounted for as leases as they were not initially determined to be leases at their commencement dates. However, modifications to these agreements or new agreements will be assessed and accounted for accordingly under ASU No. 2016-02. For short-term leases, which are leases that, at the commencement date, have a lease term of 12 months or less and do not include an option to purchase the underlying asset that is reasonably certain to be exercised, we elected to not recognize the ROU asset and corresponding lease liability on our consolidated balance sheet.
The following table indicates the consolidated balance sheet line items that include the ROU assets and lease liabilities for our finance and operating leases at December 31:
Millions of Dollars
2020 2019
Finance
Leases Operating
Leases Finance
Leases Operating
Leases
Right-of-Use Assets
Net properties, plants and equipment $ 264 - 284 -
Other assets - 1,211 - 1,312
Total right-of-use assets $ 264 1,211 284 1,312
Lease Liabilities
Short-term debt $ 16 - 18 -
Other accruals - 369 - 455
Long-term debt 248 - 259 -
Other liabilities and deferred credits - 853 - 806
Total lease liabilities $ 264 1,222 277 1,261
Future minimum lease payments at December 31, 2020, for finance and operating lease liabilities were:
Millions of Dollars
Finance
Leases Operating
Leases
2021 $ 25 406
2022 23 273
2023 23 182
2024 23 138
2025 23 102
Remaining years 224 271
Future minimum lease payments 341 1,372
Amount representing interest or discounts (77) (150)
Total lease liabilities $ 264 1,222
Our finance lease liabilities relate primarily to service station consignment agreements with a marketing joint venture and an oil terminal in the United Kingdom. The lease liability for the oil terminal finance lease is subject to foreign currency translation adjustments each reporting period.
Components of net lease cost for the years ended December 31, 2020 and 2019, were:
Millions of Dollars
2020 2019
Finance lease cost
Amortization of right-of-use assets $ 21 20
Interest on lease liabilities 10 6
Total finance lease cost 31 26
Operating lease cost 527 531
Short-term lease cost 108 118
Variable lease cost 39 12
Sublease income (22) (16)
Total net lease cost $ 683 671
For the year ended December 31, 2018, operating lease rental expense was $603 million, including minimum rentals of $669 million and contingent rentals of $5 million, partially offset by sublease rental income of $71 million.
Cash paid for amounts included in the measurement of our lease liabilities for the years ended December 31, 2020 and 2019, was:
Millions of Dollars
2020 2019
Operating cash outflows-finance leases $ 10 6
Operating cash outflows-operating leases 521 553
Financing cash outflows-finance leases 17 21
During the years ended December 31, 2020 and 2019, we recorded additional noncash ROU assets and corresponding operating lease liabilities totaling $363 million and $342 million, respectively, related to new and modified lease agreements.
At December 31, 2020 and 2019, the weighted-average remaining lease terms and discount rates for our lease liabilities were:
2020 2019
Weighted-average remaining lease term-finance leases (years) 15.1 11.1
Weighted-average remaining lease term-operating leases (years) 5.7 5.6
Weighted-average discount rate-finance leases 3.6 % 3.1
Weighted-average discount rate-operating leases 3.6 % 3.8
Note 19-Pension and Postretirement Plans
The following table provides a reconciliation of the projected benefit obligations and plan assets for our pension plans and accumulated benefit obligations for our other postretirement benefit plans:
Millions of Dollars
Pension Benefits Other Benefits
2020 2019 2020 2019
U.S. Int’l. U.S. Int’l.
Change in Benefit Obligations
Benefit obligations at January 1 $ 3,148 1,228 2,730 1,007 226 220
Service cost 138 28 127 23 5 5
Interest cost 91 22 109 26 7 9
Plan participant contributions - 2 - 2 6 5
Plan amendments - - - - - (2)
Net actuarial loss (gain) 353 168 380 186 (13) 6
Benefits paid (325) (34) (198) (31) (18) (17)
Foreign currency exchange rate change - 66 - 15 - -
Benefit obligations at December 31 $ 3,405 1,480 3,148 1,228 213 226
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1 $ 2,702 1,046 2,377 902 - -
Actual return on plan assets 342 118 478 121 - -
Company contributions 19 26 45 28 12 12
Plan participant contributions - 2 - 2 6 5
Benefits paid (325) (34) (198) (31) (18) (17)
Foreign currency exchange rate change - 54 - 24 - -
Fair value of plan assets at December 31 $ 2,738 1,212 2,702 1,046 - -
Funded Status at December 31 $ (667) (268) (446) (182) (213) (226)
Amounts recognized in the consolidated balance sheet for our pension and other postretirement benefit plans at December 31 include:
Millions of Dollars
Pension Benefits Other Benefits
2020 2019 2020 2019
U.S. Int’l. U.S. Int’l.
Amounts Recognized in the Consolidated Balance Sheet
Noncurrent assets $ - - - 29 - -
Current liabilities (25) - (25) - (15) (15)
Noncurrent liabilities (642) (268) (421) (211) (198) (211)
Total recognized $ (667) (268) (446) (182) (213) (226)
Included in accumulated other comprehensive loss 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
2020 2019 2020 2019
U.S. Int’l. U.S. Int’l.
Unrecognized net actuarial loss (gain)
$ 562 253 523 164 (13) -
Unrecognized prior service credit
- (1) - (2) (4) (6)
Other changes in plan assets and benefit obligations recognized in other comprehensive income (loss):
Millions of Dollars
Pension Benefits Other Benefits
2020 2019 2020 2019
U.S. Int’l. U.S. Int’l.
Sources of Change in Other Comprehensive Income (Loss)
Net actuarial gain (loss) arising during the period $ (170) (105) (45) (106) 13 (7)
Amortization of net actuarial loss (gain) and settlements
131 16 61 6 - (1)
Prior service credit arising during the period - - - - - 2
Amortization of prior service credit - (1) - (1) (2) (2)
Total recognized in other comprehensive income (loss) $ (39) (90) 16 (101) 11 (8)
The accumulated benefit obligations for all U.S. and international pension plans were $3,076 million and $1,289 million, respectively, at December 31, 2020, and $2,855 million and $1,068 million, respectively, at December 31, 2019.
Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31 was:
Millions of Dollars
Pension Benefits
2020 2019
U.S. Int’l. U.S. Int’l.
Accumulated benefit obligations $ 3,076 447 2,855 396
Fair value of plan assets
2,738 242 2,702 207
Information for U.S. and international pension plans with a projected benefit obligation in excess of plan assets at December 31 was:
Millions of Dollars
Pension Benefits
2020 2019
U.S. Int’l. U.S. Int’l.
Projected benefit obligations $ 3,405 1,480 3,148 419
Fair value of plan assets
2,738 1,212 2,702 207
Components of net periodic benefit cost for all defined benefit plans are presented in the table below:
Millions of Dollars
Pension Benefits Other Benefits
2020 2019 2018 2020 2019 2018
U.S. Int’l. U.S. Int’l. U.S. Int’l.
Components of Net Periodic Benefit Cost
Service cost $ 138 28 127 23 136 29 5 5 6
Interest cost 91 22 109 26 104 28 7 9 7
Expected return on plan assets
(159) (50) (143) (44) (169) (46) - - -
Amortization of prior service credit - (1) - (1) - (1) (2) (2) (1)
Amortization of net actuarial loss (gain)
70 16 53 6 59 19 - (1) -
Settlements
61 - 8 - 72 - - - -
Total net periodic benefit cost*
$ 201 15 154 10 202 29 10 11 12
* Included in the “Operating expenses” and “Selling, general and administrative expenses” line items on our consolidated statement of operations.
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% of the unamortized balance each year. The amount subject to amortization is determined on a plan-by-plan basis.
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
2020 2019 2020 2019
U.S. Int’l. U.S. Int’l.
Assumptions Used to Determine Benefit Obligations:
Discount rate 2.50 % 1.27 3.30 1.81 2.30 3.05
Rate of compensation increase 4.00 3.01 4.00 3.34 - -
Interest crediting rate on cash balance plan
2.05 - 2.70 - - -
Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate 3.00 % 1.81 4.30 2.59 3.05 4.15
Expected return on plan assets 6.50 4.86 6.50 4.93 - -
Rate of compensation increase 4.00 3.34 4.00 3.34 - -
Interest crediting rate on cash balance plan
2.22 - 3.25 - - -
For both U.S. and international pension plans, the overall expected long-term rate of return is developed from the expected future return of each asset class, weighted by the expected allocation of pension assets to that asset class. We rely on a variety of independent market forecasts in developing the expected rate of return for each class of assets.
For the year ended December 31, 2020, actuarial losses resulted in increases in our U.S. and international pension benefit obligations of $353 million and $168 million, respectively. For the year ended December 31, 2019, actuarial losses resulted in increases in our U.S. and international pension benefit obligations of $380 million and $186 million, respectively. The primary drivers for the actuarial losses in 2020 and 2019 were decreases in the discount rates and changes to the census data demographics.
For the year ended December 31, 2020, the weighted-average actual return on plan assets for our U.S. pension plans was 14%, which resulted in a $342 million increase in plan assets. For the year ended December 31, 2019, the weighted-average actual return on plan assets for our U.S. pension plans was 20%, which resulted in a $478 million increase in plan assets. The primary driver of the return on plan assets in 2020 and 2019 was fluctuations in the equity and fixed income markets.
Our other postretirement benefit plans for health insurance are contributory. Effective December 31, 2012, we terminated the subsidy for retiree medical plans. Since January 1, 2013, eligible employees have been able to utilize notional amounts credited to an account during their period of service with the company to pay all, or a portion, of their cost to participate in postretirement health insurance. 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 6.50% in 2021 that declines to 5.00% by 2027.
Plan Assets
The investment strategy for managing pension plan assets is to seek a reasonable rate of return relative to an appropriate level of risk and provide adequate liquidity for benefit payments and portfolio management. We follow a policy of diversifying pension plan assets across asset classes, investment managers, and individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include equities, fixed income, cash, real estate, infrastructure 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 46% equity securities, 38% debt securities, 8% real estate investments and 8% in all other types of investments as of December 31, 2020. Generally, the investments in the plans are publicly traded, therefore minimizing the liquidity risk in the portfolio.
The following is a description of the valuation methodologies used for the pension plan assets.
•Fair values of equity securities and government debt securities are based on quoted market prices.
•Fair values of corporate debt securities are estimated using recently executed transactions and market price quotations. If there have been no market transactions in a particular fixed income security, its fair value is calculated by pricing models that benchmark the security against other securities with actual market prices.
•Cash and cash equivalents are valued at cost, which approximates fair value.
•Fair values of insurance contracts are valued at the present value of the future benefit payments owed by the insurance company to the plans’ participants.
•Fair values of investments in common/collective trusts and real estate funds are valued at the net asset value (NAV) as a practical expedient. The NAV is based on the underlying net assets owned by the fund and the relative interest of each participating investor in the fair value of the underlying assets. These investments valued at NAV are not classified within the fair value hierarchy, but are presented in the fair value table to permit reconciliation of total plan assets to the amounts presented in the fair value table.
The fair values of our pension plan assets at December 31, by asset class, were:
Millions of Dollars
U.S. International
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Equity securities $ 446 - - 446 - - - -
Government debt securities 424 - - 424 - - - -
Corporate debt securities - 138 - 138 - - - -
Cash and cash equivalents 31 - - 31 3 - - 3
Insurance contracts - - - - - - 15 15
Total assets in the fair value hierarchy
901 138 - 1,039 3 - 15 18
Common/collective trusts measured at NAV
1,538 1,103
Real estate funds measured at NAV
161 91
Total $ 901 138 - 2,738 3 - 15 1,212
Millions of Dollars
U.S. International
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Equity securities $ 437 - - 437 - - - -
Government debt securities 475 - - 475 - - - -
Corporate debt securities
- 134 - 134 - - - -
Cash and cash equivalents 136 - - 136 4 - - 4
Insurance contracts - - - - - - 14 14
Total assets in the fair value hierarchy
1,048 134 - 1,182 4 - 14 18
Common/collective trusts measured at NAV
1,364 938
Real estate funds measured at NAV
156 90
Total $ 1,048 134 - 2,702 4 - 14 1,046
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 2021, we expect to contribute approximately $40 million to our U.S. pension plans and other postretirement benefit plans and $30 million to our international pension plans.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid to plan participants in the years indicated:
Millions of Dollars
Pension Benefits Other Benefits
U.S. Int’l.
2021 $ 469 24 18
2022 392 26 19
2023 320 28 19
2024 309 31 19
2025 288 33 19
2026-2030 1,241 194 85
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% of their eligible pay, subject to certain statutory limits, in the Savings Plan to a choice of investment funds. Phillips 66 provides a company match of participant contributions up to 6% of eligible pay. Prior to January 1, 2019, the match was up to 5% of eligible pay. In addition, eligible participants receive an additional discretionary Success Share contribution from the company. The target for the Success Share contribution is 2% of eligible pay, but the Success Share contribution can range from 0% to 6% based on management discretion.
For the years ended December 31, 2020, 2019 and 2018, we recorded expense of $145 million, $192 million and $178 million, respectively, related to our contributions to the Savings Plan.
Note 20-Share-Based Compensation Plans
In accordance with the Employee Matters Agreement related to the separation, compensation awards based on ConocoPhillips stock and granted before April 30, 2012 (the Separation Date) were converted to compensation awards based on both ConocoPhillips and Phillips 66 stock if, on the Separation Date, the awards were: (1) options outstanding and exercisable; or (2) restricted stock or restricted stock units (RSUs) awarded for completed performance periods under the ConocoPhillips Performance Share Program. Phillips 66 restricted stock, RSUs and options issued in this conversion became subject to the “Omnibus Stock and Performance Incentive Plan of Phillips 66” (the 2012 Plan) on the Separation Date, whether held by grantees working for Phillips 66 or grantees that remained employees of ConocoPhillips. Some of these awards based on Phillips 66 stock and held by employees of ConocoPhillips are outstanding and appear in the activity tables for the Stock Option and the Performance Share Programs presented later in this note.
In May 2013, shareholders approved the 2013 Omnibus Stock and Performance Incentive Plan of Phillips 66 (the P66 Omnibus Plan). Subsequent to this approval, all new share-based awards are granted under the P66 Omnibus Plan, which authorizes the Human Resources and Compensation Committee (HRCC) of our Board of Directors to grant stock options, stock appreciation rights, stock awards (including restricted stock and RSU awards), cash awards, and performance awards to our employees, nonemployee directors and other plan participants. The number of new shares that may be issued under the P66 Omnibus Plan to settle share-based awards may not exceed 45 million.
We recognize share-based compensation expense over the shorter of: (1) the service period (i.e., the stated period of time required to earn the award); or (2) the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months as this is the minimum period of time required for an award not to be subject to forfeiture. Our equity-classified programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for awards held by employees at the time they become eligible for retirement (at age 55 with 5 years of service). We have elected to recognize expense on a straight-line basis over the service period for the entire award, irrespective of whether the award was granted with ratable or cliff vesting, and have elected to recognize forfeitures of awards when they occur.
Total share-based compensation expense recognized in income and the associated income tax benefit for the years ended December 31 were:
Millions of Dollars
2020 2019 2018
Share-based compensation expense $ 127 169 100
Income tax benefit (35) (53) (45)
Stock Options
Stock options granted under the provisions of the P66 Omnibus Plan and earlier plans permit purchases of our common stock at exercise prices equivalent to the average of the high and low market price of our stock on the date the options were granted. The options have terms of 10 years and vest ratably, with one-third of the options becoming exercisable on each anniversary date for the three years following the date of grant. Options awarded to employees eligible for retirement are not subject to forfeiture six months after the grant date.
The following table summarizes our stock option activity from January 1, 2020, to December 31, 2020:
Millions of Dollars
Options Weighted-Average
Exercise Price Weighted-Average
Grant-Date
Fair Value Aggregate
Intrinsic Value
Outstanding at January 1, 2020 4,779,404 $ 72.55
Granted 1,015,000 89.57 $ 15.80
Forfeited (37,958) 91.90
Exercised (322,458) 23.76 $ 21
Outstanding at December 31, 2020 5,433,988 $ 78.49
Vested at December 31, 2020 3,811,788 $ 72.62 $ 24
Exercisable at December 31, 2020 3,695,000 $ 72.20 $ 24
The weighted-average remaining contractual terms of vested options and exercisable options at December 31, 2020, were 4.78 years and 4.60 years, respectively. During 2020, we received $8 million in cash and realized an income tax benefit of less than $1 million from the exercise of options. At December 31, 2020, the remaining unrecognized compensation expense from unvested options was $5 million, which will be recognized over a weighted-average period of 21 months, the longest period being 25 months. The calculations of realized income tax benefits and weighted-average periods include awards based on both Phillips 66 and ConocoPhillips stock held by Phillips 66 employees.
During 2019 and 2018, we granted options with a weighted-average grant-date fair value of $17.58 and $20.69, respectively. During 2019 and 2018, employees exercised options with an aggregate intrinsic value of $51 million and $37 million, respectively.
The following table provides the significant assumptions used to calculate the grant-date fair values of options granted over the years shown below, as calculated using the Black-Scholes-Merton option-pricing model:
2020 2019 2018
Risk-free interest rate 1.58 % 2.68 2.81
Dividend yield 3.20 % 3.70 2.80
Volatility factor 25.23 % 25.61 25.41
Expected life (years) 6.96 7.06 7.18
We calculate the volatility factor using historical Phillips 66 end-of-week closing stock prices since the Separation Date. We periodically calculate the average period of time elapsed between grant dates and exercise dates of past grants to estimate the expected life of new option grants.
Restricted Stock Units
Generally, RSUs are granted annually under the provisions of the P66 Omnibus Plan and cliff vest at the end of three years. The grant date fair value is equal to the average of the high and low market price of our stock on the grant date. The recipients receive a quarterly dividend equivalent cash payment until the RSU is settled by issuing one share of our common stock for each RSU at the end of the service period. RSUs granted to retirement-eligible employees are not subject to forfeiture six months after the grant date. Special RSUs are granted to attract or retain key personnel and the terms and conditions may vary by award.
The following table summarizes our RSU activity from January 1, 2020, to December 31, 2020:
Millions of Dollars
Stock Units Weighted-Average
Grant-Date
Fair Value Total Fair Value
Outstanding at January 1, 2020 2,374,584 $ 90.47
Granted 1,289,842 83.48
Forfeited (74,451) 94.17
Issued (803,756) 80.72 $ 69
Outstanding at December 31, 2020 2,786,219 $ 89.95
Not Vested at December 31, 2020 1,964,339 $ 89.05
At December 31, 2020, the remaining unrecognized compensation cost from unvested RSU awards was $74 million, which will be recognized over a weighted-average period of 20 months, the longest period being 50 months.
During 2019 and 2018, we granted RSUs with a weighted-average grant-date fair value of $95.16 and $96.16, respectively. During 2019 and 2018, we issued shares with an aggregate fair value of $80 million and $102 million, respectively, to settle RSUs.
Performance Share Units
Under the P66 Omnibus Plan, we annually grant to senior management restricted performance share units (PSUs) with three-year performance periods that vest when the HRCC approves the three-year performance results on the grant date. PSUs granted under the P66 Omnibus Plan are classified as liability awards and compensation expense is recognized beginning on the authorization date and ending on the vesting date.
PSUs granted under the P66 Omnibus Plan are settled by cash payments equal to the fair value of the awards, which is based on the market prices of our stock near the end of the performance periods. The HRCC must approve the three-year performance results prior to payout. Dividend equivalents are not paid on these awards.
PSUs granted under prior incentive compensation plans were classified as equity awards. These equity awards are settled upon an employee’s retirement by issuing one share of our common stock for each PSU held. Dividend equivalents are paid on these awards.
The following table summarizes our PSU activity from January 1, 2020, to December 31, 2020:
Millions of Dollars
Performance
Share Units Weighted-Average
Grant-Date
Fair Value Total Fair Value
Outstanding at January 1, 2020 1,440,560 $ 46.44
Granted 554,457 112.73
Forfeited - -
Issued (482,770) 64.62 $ 41
Cash settled (554,457) 112.73 63
Outstanding at December 31, 2020 957,790 $ 37.28
Not Vested at December 31, 2020 1,596 $ 32.41
At December 31, 2020, the remaining unrecognized compensation cost from unvested PSU awards was immaterial. 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 2019 and 2018, we granted PSUs with a weighted-average grant-date fair value of $87.42 and $99.74, respectively. During 2019 and 2018, we issued shares with an aggregate fair value of $44 million and $70 million, respectively, to settle PSUs. During 2019 and 2018, we cash settled PSUs with an aggregate fair value of $25 million and $49 million, respectively.
Note 21-Income Taxes
During the year ended December 31, 2020, in accordance with the Coronavirus Aid, Relief, and Economic Security (CARES) Act, we recorded a tax benefit reflecting the carryback of a significant portion of our 2020 net operating loss to a year that had a 35% federal statutory income tax rate. An income tax receivable of $1.5 billion is included in the “Accounts and notes receivable” line item on our consolidated balance sheet as of December 31, 2020, which reflects tax refunds we expect to receive within the next 12 months.
During the year ended December 31, 2019, we recorded adjustments to the one-time deemed repatriation tax, which decreased our income tax expense by $42 million. The adjustments were due to the issuance of additional guidance by the U.S. Internal Revenue Service related to the Tax Act.
During the year ended December 31, 2018, we recorded adjustments to finalize our accounting for the income tax effects of the Tax Act, which increased our income tax expense by $36 million. The adjustments were primarily due to the revision of our estimated revaluation of deferred income tax balances from 35% to 21% in conjunction with the filing of our 2017 income tax return and the issuance of additional guidance by the U.S. Internal Revenue Service related to the calculation of the one-time deemed repatriation tax.
Components of income tax expense (benefit) were:
Millions of Dollars
2020 2019 2018
Income Tax Expense (Benefit)
Federal
Current $ (1,324) 354 739
Deferred 171 177 257
Foreign
Current 9 204 326
Deferred 67 (50) 53
State and local
Current (61) 61 255
Deferred (112) 55 (58)
$ (1,250) 801 1,572
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
2020 2019
Deferred Tax Liabilities
Properties, plants and equipment, and intangibles $ 3,487 3,297
Investment in joint ventures 1,859 2,137
Investment in subsidiaries 940 794
Inventory 77 -
Other 310 263
Total deferred tax liabilities 6,673 6,491
Deferred Tax Assets
Benefit plan accruals 499 460
Loss and credit carryforwards 148 54
Asset retirement obligations and accrued environmental costs 114 115
Other financial accruals and deferrals 73 38
Inventory - 28
Other 289 313
Total deferred tax assets 1,123 1,008
Less: valuation allowance 40 22
Net deferred tax assets 1,083 986
Net deferred tax liabilities $ 5,590 5,505
At December 31, 2020, the loss and credit carryforward deferred tax assets were primarily related to a state tax net operating loss carryforward of $51 million; tax credit, capital loss and net operating loss carryforwards in the United Kingdom of $46 million; a foreign tax credit carryforward in the United States of $32 million; and a German interest deduction carryforward of $18 million. Foreign tax credit carryforwards, which have a full valuation allowance against them, begin to expire in 2029. The other loss and credit carryforwards, all of which relate to foreign operations, have indefinite lives.
Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be realized. During the year ended December 31, 2020, our total valuation allowance balance increased by $18 million. Based on our historical taxable income, expectations for the future and available tax planning strategies, management expects the remaining net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and the tax consequences of future taxable income.
Earnings of our foreign subsidiaries and foreign joint ventures after December 31, 2017, are generally not subject to incremental income taxes in the United States or withholding taxes in foreign countries upon repatriation. As such, we only assert that the earnings of one of our foreign subsidiaries are permanently reinvested. At December 31, 2020 and 2019, the unrecorded deferred tax liability related to the undistributed earnings of this foreign subsidiary was not material.
As a result of the separation and pursuant to the Tax Sharing Agreement with ConocoPhillips, the unrecognized income tax benefits related to our operations for the periods for which ConocoPhillips was the taxpayer remain the responsibility of ConocoPhillips, and we have indemnified ConocoPhillips for such amounts. We file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Unrecognized tax benefits reflect the difference between positions taken on income tax returns and the amounts recognized in the financial statements. The following table is a reconciliation of the changes in our unrecognized income tax benefits balance:
Millions of Dollars
2020 2019 2018
Balance at January 1 $ 40 23 34
Additions for tax positions of current year - 2 -
Additions for tax positions of prior years 44 29 1
Reductions for tax positions of prior years (28) (14) (2)
Settlements - - (10)
Balance at December 31 $ 56 40 23
Included in the balance of unrecognized income tax benefits at December 31, 2020, 2019 and 2018, were $37 million, $15 million and $1 million, respectively, which, if recognized, would affect our effective income tax rate. With respect to various unrecognized income tax benefits and the related accrued liabilities, we do not expect any to be recognized or paid within the next twelve months.
At December 31, 2020, 2019 and 2018, accrued liabilities for interest and penalties, net of accrued income taxes, totaled $5 million, $10 million and $5 million, respectively. These accruals decreased our results by $3 million for each of the years ended December 31, 2020 and 2019.
Audits in significant jurisdictions are generally complete as follows: United Kingdom (2018), Germany (2014) and United States (2013). Certain issues remain in dispute for audited years, and unrecognized income tax benefits for years still subject to or currently undergoing an audit are subject to change. As a consequence, the balance in unrecognized income tax benefits can be expected to fluctuate from period to period. Although it is reasonably possible such changes could be significant when compared with our total unrecognized income tax benefits, the amount of change is not estimable.
The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of income tax at the federal statutory rate to the recorded income tax expense (benefit), were:
Millions of Dollars Percentage of
Income Before Income Taxes
2020 2019 2018 2020 2019 2018
Income (loss) before income taxes
United States $ (5,292) 3,267 5,716 106.6 % 78.2 76.8
Foreign 328 911 1,729 (6.6) 21.8 23.2
$ (4,964) 4,178 7,445 100.0 % 100.0 100.0
Federal statutory income tax $ (1,043) 877 1,563 21.0 % 21.0 21.0
State income tax, net of federal benefit
(139) 92 155 2.8 2.2 2.1
Net operating loss carryback (398) - - 8.0 - -
Goodwill impairment 387 - - (7.8) - -
Noncontrolling interests (54) (61) (58) 1.1 (1.5) (0.8)
Foreign rate differential (11) (31) (3) 0.2 (0.7) -
Tax Cuts and Jobs Act - (42) 36 - (1.0) 0.5
Other* 8 (34) (121) (0.1) (0.8) (1.7)
$ (1,250) 801 1,572 25.2 % 19.2 21.1
* Other includes individually immaterial items but is primarily attributable to foreign operations and change in valuation allowance.
An income tax benefit of $1 million for the year ended December 31, 2020, and income tax expense of $123 million and $13 million for the years ended December 31, 2019 and 2018, respectively, is reflected in the “Capital in Excess of Par” column on our consolidated statement of changes in equity.
Note 22-Accumulated Other Comprehensive Loss
Changes in the balances of each component of accumulated other comprehensive loss were as follows:
Millions of Dollars
Defined
Benefit
Plans Foreign
Currency
Translation Hedging Accumulated
Other
Comprehensive Loss
December 31, 2017 $ (598) (26) 7 (617)
Other comprehensive income (loss) before reclassifications 14 (192) 4 (174)
Amounts reclassified from accumulated other comprehensive loss
Defined benefit plans*
Amortization of net actuarial loss, prior service credit and settlements 112 - - 112
Foreign currency translation - (10) - (10)
Hedging - - (3) (3)
Net current period other comprehensive income (loss) 126 (202) 1 (75)
December 31, 2018 (472) (228) 8 (692)
Other comprehensive income (loss) before reclassifications (140) 95 (5) (50)
Amounts reclassified from accumulated other comprehensive loss
Defined benefit plans*
Amortization of net actuarial loss, prior service credit and settlements 49 - - 49
Foreign currency translation - - - -
Hedging - - (6) (6)
Net current period other comprehensive income (loss) (91) 95 (11) (7)
Income taxes reclassified to retained earnings** (93) 2 2 (89)
December 31, 2019 (656) (131) (1) (788)
Other comprehensive income (loss) before reclassifications (262) 151 1 (110)
Amounts reclassified from accumulated other comprehensive loss
Defined benefit plans*
Amortization of net actuarial loss, prior service credit and settlements 109 - - 109
Foreign currency translation - - - -
Hedging - - (5) (5)
Net current period other comprehensive income (loss) (153) 151 (4) (6)
Other - 5 - 5
December 31, 2020 $ (809) 25 (5) (789)
* Included in the computation of net periodic benefit cost. See Note 19-Pension and Postretirement Plans, for additional information.
** As of January 1, 2019, stranded income taxes related to the enactment of the Tax Act in December 2017 were reclassified to retained earnings upon adoption of ASU No. 2018-02.
Note 23-Cash Flow Information
Supplemental Cash Flow Information
Millions of Dollars
2020 2019 2018
Cash Payments
Interest $ 478 426 465
Income taxes 103 955 984
Note 24-Other Financial Information
Millions of Dollars
2020 2019 2018
Interest and Debt Expense
Incurred
Debt
$ 550 504 493
Other
24 31 28
574 535 521
Capitalized (75) (77) (17)
Expensed $ 499 458 504
Other Income
Interest income $ 14 43 45
Other, net* 52 76 16
$ 66 119 61
* Includes derivatives-related activities. See Note 15-Derivatives and Financial Instruments, for additional information.
Research and Development Expenses $ 48 54 55
Advertising Expenses $ 51 63 68
Foreign Currency Transaction (Gains) Losses
Midstream $ - - -
Chemicals - - -
Refining 4 - (24)
Marketing and Specialties - - 1
Corporate and Other 8 5 (8)
$ 12 5 (31)
Note 25-Related Party Transactions
Significant transactions with related parties were:
Millions of Dollars
2020 2019 2018
Operating revenues and other income (a) $ 1,932 2,977 3,514
Purchases (b) 6,536 11,726 12,755
Operating expenses and selling, general and administrative expenses (c) 247 96 59
(a)We sold NGL, other petrochemical feedstocks and solvents to CPChem, NGL and certain feedstocks to DCP Midstream, gas oil and hydrogen feedstocks to Excel Paralubes (Excel), and refined petroleum products to several of our equity affiliates in the Marketing and Specialties segment, including OnCue and CF United. We also sold certain feedstocks and intermediate products to WRB and acted as agent for WRB in supplying crude oil and other feedstocks for a fee. In addition, we charged several of our equity affiliates, including CPChem, for the use of common facilities, such as steam generators, waste and water treaters and warehouse facilities.
(b)We purchased crude oil, refined petroleum products and NGL from WRB and also acted as agent for WRB in distributing solvents. We also purchased natural gas and NGL from DCP Midstream and CPChem, as well as other feedstocks from various equity affiliates, for use in our refinery and fractionation processes. In addition, we purchased base oils and fuel products from Excel for use in our specialty and refining businesses. We paid NGL fractionation fees to CPChem. We also paid fees to various pipeline equity affiliates for transporting crude oil, refined petroleum products and NGL.
(c)We paid consignment fees to CF United, and utility and processing fees to various equity affiliates.
Note 26-Segment Disclosures and Related Information
Our operating segments are:
1)Midstream-Provides crude oil and refined petroleum product transportation, terminaling and processing services, as well as natural gas and NGL transportation, storage, fractionation, processing and marketing services, mainly in the United States. The Midstream segment includes our master limited partnership (MLP), Phillips 66 Partners, as well as our 50% equity investment in DCP Midstream.
2)Chemicals-Consists of our 50% equity investment in CPChem, which manufactures and markets petrochemicals and plastics on a worldwide basis.
3)Refining-Refines crude oil and other feedstocks into petroleum products, such as gasoline, distillates and aviation fuels, at 13 refineries in the United States and Europe.
4)Marketing and Specialties-Purchases for resale and markets refined petroleum products, mainly in the United States and Europe. In addition, this segment includes the manufacturing and marketing of specialty products.
Corporate and Other includes general corporate overhead, interest expense, our investment in new technologies and various other corporate activities. Corporate assets include all cash, cash equivalents and income tax-related assets.
Intersegment sales are at prices that we believe approximate market.
Analysis of Results by Operating Segment
Millions of Dollars
2020 2019 2018
Sales and Other Operating Revenues*
Midstream
Total sales $ 6,047 7,103 8,293
Intersegment eliminations (1,873) (2,122) (2,176)
Total Midstream 4,174 4,981 6,117
Chemicals 3 3 5
Refining
Total sales 42,206 76,792 83,140
Intersegment eliminations (24,176) (45,871) (49,343)
Total Refining 18,030 30,921 33,797
Marketing and Specialties
Total sales 43,164 73,616 73,414
Intersegment eliminations (1,272) (2,256) (1,899)
Total Marketing and Specialties 41,892 71,360 71,515
Corporate and Other 30 28 27
Consolidated sales and other operating revenues $ 64,129 107,293 111,461
* See Note 3-Sales and Other Operating Revenues, for further details on our disaggregated sales and other operating revenues.
Equity in Earnings (Loss) of Affiliates
Midstream $ 761 754 676
Chemicals 625 870 1,025
Refining (376) 318 796
Marketing and Specialties 181 185 164
Corporate and Other - - 15
Consolidated equity in earnings of affiliates $ 1,191 2,127 2,676
Depreciation, Amortization and Impairments*
Midstream $ 1,795 1,162 326
Chemicals - - -
Refining 3,642 857 841
Marketing and Specialties 103 103 114
Corporate and Other 107 80 83
Consolidated depreciation, amortization and impairments $ 5,647 2,202 1,364
* See Note 9-Impairments, for further details on impairments by segment.
Millions of Dollars
2020 2019 2018
Interest Income and Expense
Interest income
Corporate and Other $ 14 43 45
Interest and debt expense
Corporate and Other $ 499 458 504
Income (Loss) Before Income Taxes
Midstream $ (9) 684 1,181
Chemicals 635 879 1,025
Refining (6,155) 1,986 4,535
Marketing and Specialties 1,446 1,433 1,557
Corporate and Other (881) (804) (853)
Consolidated income (loss) before income taxes $ (4,964) 4,178 7,445
Investments In and Advances To Affiliates
Midstream $ 4,255 5,131 5,423
Chemicals 6,126 6,229 6,233
Refining 2,202 2,290 2,226
Marketing and Specialties 744 650 349
Corporate and Other - - -
Consolidated investments in and advances to affiliates $ 13,327 14,300 14,231
Total Assets
Midstream $ 15,596 15,716 14,329
Chemicals 6,183 6,249 6,235
Refining 20,404 25,150 23,230
Marketing and Specialties 7,180 8,659 6,572
Corporate and Other 5,358 2,946 3,936
Consolidated total assets $ 54,721 58,720 54,302
Millions of Dollars
2020 2019 2018
Capital Expenditures and Investments
Midstream $ 1,747 2,292 1,548
Chemicals - - -
Refining 816 1,001 826
Marketing and Specialties 173 374 125
Corporate and Other 184 206 140
Consolidated capital expenditures and investments $ 2,920 3,873 2,639
Geographic Information
Long-lived assets, defined as net PP&E plus investments and long-term receivables, by geographic location at December 31 were:
Millions of Dollars
2020 2019 2018
United States $ 35,273 36,407 34,587
United Kingdom 1,313 1,256 1,191
Germany 653 601 570
Other foreign countries 101 93 91
Worldwide consolidated $ 37,340 38,357 36,439
Note 27-Phillips 66 Partners LP
Phillips 66 Partners, headquartered in Houston, Texas, is a publicly traded MLP formed in 2013 to own, operate, develop and acquire primarily fee-based midstream assets. Phillips 66 Partners’ operations currently consist of crude oil, refined petroleum product and NGL transportation, fractionation, processing, terminaling and storage assets.
On August 1, 2019, Phillips 66 Partners completed a restructuring transaction to eliminate the IDRs held by us and convert our 2% economic general partner interest into a noneconomic general partner interest in exchange for 101 million Phillips 66 Partners common units. As a result of the restructuring transaction, the balance of “Noncontrolling interests” in our consolidated balance sheet decreased $373 million, with a $275 million increase to “Capital in excess of par,” a $91 million increase in “Deferred income taxes” and $7 million of transaction costs. No distributions were made for the general partner interest after August 1, 2019.
At December 31, 2020, we owned 170 million Phillips 66 Partners common units, representing a 74% limited partner interest, while the public owned a 26% limited partner interest and 13.8 million perpetual convertible preferred units. Prior to October 2020, holders of the preferred units received cumulative quarterly distributions equal to $0.678375 per unit. Beginning in October 2020, holders receive quarterly distributions equal to the greater of $0.678375 per unit or the per-unit distribution paid to common unitholders.
We consolidate Phillips 66 Partners because we determined it is a VIE of which we are the primary beneficiary. As general partner of Phillips 66 Partners, we have the ability to control its financial interests, as well as the ability to direct the activities that most significantly impact its economic performance. As a result of this consolidation, the public common and perpetual convertible preferred unitholders’ ownership interests in Phillips 66 Partners are reflected as noncontrolling interests of $2,219 million and $2,228 million on our consolidated balance sheet at December 31, 2020 and 2019, respectively.
The most significant assets of Phillips 66 Partners that are available to settle only its obligations, along with its most significant liabilities for which its creditors do not have recourse to Phillips 66’s general credit, were:
Millions of Dollars
December 31
2020 December 31
Cash and cash equivalents $ 7 286
Equity investments* 3,244 2,961
Net properties, plants and equipment 3,639 3,349
Short-term debt 465 25
Long-term debt 3,444 3,491
* Included in “Investments and long-term receivables” line item on the Phillips 66 consolidated balance sheet.
Phillips 66 Partners has authorized an aggregate of $750 million under three $250 million continuous offerings of common units, or at-the-market (ATM) programs. The first two programs concluded in June 2018 and December 2019, respectively. For the years ended December 31, 2020, 2019 and 2018, on a settlement-date basis, Phillips 66 Partners generated net proceeds of $2 million, $173 million and $128 million, respectively, from common units issued under the ATM programs. Since inception in June 2016 and through December 31, 2020, the ATM programs have generated net proceeds of $494 million.
Gray Oak Pipeline, LLC was formed to develop and construct the Gray Oak Pipeline, which transports crude oil from the Permian and Eagle Ford to Texas Gulf Coast destinations that include Corpus Christi, Texas, and the Sweeny area, including our Sweeny Refinery. Phillips 66 Partners has a consolidated holding company that owns 65% of Gray Oak Pipeline, LLC. In December 2018, a third party acquired a 35% interest in the holding company. Because the holding company’s sole asset was its ownership interest in Gray Oak Pipeline, LLC, which was considered a financial asset, and because certain restrictions were placed on the third party’s ability to transfer or sell its interest in the holding company during the construction of the Gray Oak Pipeline, the legal sale of the 35% interest did not qualify as a sale under GAAP at that time. The Gray Oak Pipeline commenced full operations in the second quarter of 2020, and the restrictions placed on the co-venturer were lifted on June 30, 2020, resulting in the recognition of the sale under GAAP. Accordingly, at June 30, 2020, the co-venturer’s 35% interest in the holding company was recharacterized from a long-term obligation to a noncontrolling interest on our consolidated balance sheet, and the premium of $84 million previously paid by the co-venturer in 2019 was recharacterized from a long-term obligation to a gain in our consolidated statement of operations. For the year ended December 31, 2020, the co-venturer contributed an aggregate of $61 million to the holding company to fund its portion of Gray Oak Pipeline, LLC’s cash calls. Phillips 66 Partners’ effective ownership interest in Gray Oak Pipeline, LLC is 42.25% , after considering the co-venturer’s 35% interest in the consolidated holding company. See Note 6-Investments, Loans and Long-Term Receivables, for further discussion regarding Phillips 66 Partners’ investment in Gray Oak Pipeline, LLC, as well as certain other joint ventures.
Selected Quarterly Financial Data (Unaudited)
Millions of Dollars Per Share of Common Stock
Sales and Other Operating Revenues Income (Loss) Before Income Taxes Net Income (Loss) Net Income (Loss) Attributable to Phillips 66 Net Income (Loss) Attributable to Phillips 66
Basic Diluted
First $ 20,878 (2,478) (2,427) (2,496) (5.66) (5.66)
Second 10,913 (445) (67) (141) (0.33) (0.33)
Third 15,929 (1,350) (726) (799) (1.82) (1.82)
Fourth 16,409 (691) (494) (539) (1.23) (1.23)
First $ 23,103 340 270 204 0.44 0.44
Second 27,847 1,829 1,504 1,424 3.13 3.12
Third 27,218 943 793 712 1.58 1.58
Fourth 29,125 1,066 810 736 1.65 1.64

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
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, 2020, with the participation of management, our Chairman and Chief Executive Officer and our Executive Vice President, Finance and Chief Financial Officer carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of December 31, 2020.
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, 2020, 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.

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ITEM 9B. OTHER INFORMATION
Item 9B. OTHER INFORMATION
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding our executive officers appears in Part I of this report.
The remaining information required by Item 10 of Part III is incorporated herein by reference from our Proxy Statement for the Annual Meeting of Stockholders to be held on May 12, 2021, which will be filed within 120 days after December 31, 2020 (2021 Definitive Proxy Statement).*

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. EXECUTIVE COMPENSATION
The information required by Item 11 of Part III is incorporated herein by reference from our 2021 Definitive Proxy Statement.*

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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 2021 Definitive Proxy Statement.*

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Item 13 of Part III is incorporated herein by reference from our 2021 Definitive Proxy Statement.*

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by Item 14 of Part III is incorporated herein by reference from our 2021 Definitive Proxy Statement.*
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* Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing in our 2021 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.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. EXHIBIT AND 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 78, are filed as part of this Annual Report on Form 10-K.
2. Financial Statement Schedules
All financial statement schedules are omitted because they are not required, not significant, not applicable, or the information is shown in the financial statements or notes thereto.
3. Exhibits
The exhibits listed in the Index to Exhibits, which appears on pages 150 to 153, are filed as part of this Annual Report on Form 10-K.