EDGAR 10-K Filing

Company CIK: 1534701
Filing Year: 2024
Filename: 1534701_10-K_2024_0001534701-24-000078.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 businesses are 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, gathering, processing and marketing services, mainly in the United States. This segment also includes our 16% investment in NOVONIX Limited (NOVONIX).
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, as well as renewable fuels. This segment includes 12 refineries in the United States and Europe.
4)Marketing & Specialties-Purchases for resale and markets refined petroleum products and renewable fuels, mainly in the United States and Europe. In addition, this segment includes the manufacturing and marketing of base oils and lubricants.
Corporate and Other includes general corporate overhead, interest income, interest expense, our investment in research of new technologies and various other corporate activities. Corporate assets include all cash, cash equivalents and income tax-related assets. Corporate and Other also includes restructuring costs related to our business transformation. See Note 31-Restructuring, in the Notes to Consolidated Financial Statements, for additional information regarding restructuring costs.
SEGMENT AND GEOGRAPHIC INFORMATION
MIDSTREAM
The Midstream segment consists of three businesses:
•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-Gathers, processes, transports and markets natural gas and transports, fractionates and markets NGL.
•NOVONIX-Represents our 16% investment in NOVONIX, a company that develops technology and supplies materials for lithium-ion batteries.
At December 31, 2023, our Midstream business was comprised of over 72,000 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, 36 gathering and processing plants, 17 crude oil terminals, eight fractionation facilities, six NGL terminals, a petroleum coke exporting facility and various other storage and loading facilities.
DCP Midstream, LLC and Gray Oak Holdings LLC Merger (DCP Midstream Merger)
On August 17, 2022, we announced a realignment of our economic and governance interests in DCP Midstream, LP (DCP LP) and Gray Oak Pipeline, LLC (Gray Oak Pipeline) resulting from the DCP Midstream Merger. In connection with the DCP Midstream Merger, we were delegated DCP Midstream’s governance rights over DCP LP and its general partner entities, referred to as DCP Midstream Class A Segment, and our indirect economic interest in DCP LP increased to 43.3%. Starting on August 18, 2022, our financial results reflect the consolidation of DCP Midstream Class A Segment, as well as DCP Sand Hills and DCP Southern Hills within our NGL and Other business. Prior to August 18, 2022, our investments in DCP Midstream, DCP Sand Hills and DCP Southern Hills were accounted for using the equity method. In connection with the merger, our indirect interest in Gray Oak Pipeline was reduced to 6.5% and is now held through DCP Midstream Class B Segment. We account for our remaining interest in Gray Oak Pipeline using the equity method.
DCP Midstream, LP Merger (DCP LP Merger)
On June 15, 2023, we completed the acquisition of all publicly held common units of DCP LP pursuant to the terms of the Agreement and Plan of Merger, dated as of January 5, 2023 (DCP LP Merger Agreement). The DCP LP Merger Agreement was entered into with DCP LP, its subsidiaries and its general partner entities, pursuant to which one of our wholly owned subsidiaries merged with and into DCP LP, with DCP LP surviving as a Delaware limited partnership. Under the terms of the DCP LP Merger Agreement, at the effective time of the DCP LP Merger, each publicly held common unit representing a limited partner interest in DCP LP (other than the common units owned by DCP Midstream and its subsidiaries) issued and outstanding as of immediately prior to the effective time was converted into the right to receive $41.75 per common unit in cash. The DCP LP Merger increased our aggregate direct and indirect economic interest in DCP LP from 43.3% to 86.8%. See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, in the Notes to Consolidated Financial Statements, for additional information on the DCP Midstream and DCP LP Mergers.
Phillips 66 Partners Merger
On March 9, 2022, we completed the merger between us and Phillips 66 Partners. The merger resulted in the acquisition of all limited partnership interests in Phillips 66 Partners not already owned by us. Upon closing, Phillips 66 Partners became a wholly owned subsidiary of Phillips 66 and its common units are no longer publicly traded. See Note 30-Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on this merger.
Asset Dispositions
In August 2023, Phillips 66 sold its 25% interest in the South Texas Gateway Terminal for approximately $275 million. On February 28, 2023, we closed on the sale of the Belle Chasse Terminal for approximately $76 million.
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
The following table depicts our ownership interest in major pipeline systems included in our Transportation business at December 31, 2023:
Name State of
Origination/Terminus Interest Length
(Miles) Gross Capacity
(MBD)
Crude Oil
Bakken Pipeline North Dakota/Texas 25 % 1,918 750
Bayou Bridge Texas/Louisiana 40 213 480
Clifton Ridge Louisiana 100 10 260
CushPo Oklahoma 100 62 130
Eagle Ford Gathering Texas 100 28 58
Glacier Montana 79 800 124
Gray Oak Pipeline Texas 7 862 900
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
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
Name State of
Origination/Terminus Interest Length
(Miles) Gross Capacity
(MBD)
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 100 320 59
Cherokee North Oklahoma/Kansas 100 29 55
Cherokee South Oklahoma 100 98 47
Cross Channel Connector Texas 100 5 197
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
Powder River Colorado/Texas 100 350 13
Richmond California 100 14 31
SAAL Texas 33 102 32
SAAL Texas 54 19 30
Seminoe Montana/Wyoming 100 342 50
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
NGL
Blue Line Texas/Illinois 100 688 26
Brown Line Oklahoma/Kansas 100 76 26
Conway to Wichita Kansas 100 55 26
Medford Oklahoma 100 42 25
Skelly-Belvieu Texas 50 571 45
TX Panhandle Y1/Y2 Texas 100 249 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
* 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 for 661 miles 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 included in our Transportation business at December 31, 2023:
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 81 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
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
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
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 99 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 60
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 63 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
Rock Springs Wyoming Refined Petroleum Products 100 132 8
Sacramento California Refined Petroleum Products 100 146 12
Santa Margarita California Crude Oil 100 398 N/A
Sheridan Wyoming Refined Petroleum Products 100 94 6
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
The following table depicts our ownership interest in marine, rail and petroleum coke loading and offloading facilities included in our Transportation business at December 31, 2023:
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
Hartford Illinois Refined Petroleum Products 100 3
Pecan Grove Louisiana Lubricant Base Stocks, Refined Petroleum Products 100 6
Portland Oregon Refined Petroleum Products 100 10
Richmond California Refined Petroleum Products 100 3
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 35
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
* Marine facilities in thousands of barrels per hour (MB/h); Rail in thousands of barrels daily (MBD).
Marine Vessels
At December 31, 2023, we had 11 international-flagged crude oil, refined petroleum product and NGL tankers under time charter contracts, with capacities ranging in size from 300,000 to 1,100,000 barrels. Additionally, we had a variety of inland and offshore tug/barge units. These vessels are used primarily to transport crude oil and other feedstocks, 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 9,600 owned or leased railcars. Truck movements are provided through our wholly owned subsidiary, Sentinel Transportation LLC, and through numerous third-party trucking companies.
NGL and Other
At December 31, 2023, our NGL and Other business was comprised of natural gas processing plants, NGL and natural gas pipeline systems, and fractionators in the United States, including those partially owned or operated by our affiliates. A significant portion of our NGL and Other business is conducted through DCP LP, a consolidated subsidiary. DCP LP is one of the largest processors of natural gas and one of the largest producers of NGLs in the United States. DCP LP’s gathering and processing assets are strategically located in some of the major producing regions in the United States, including the Permian Basin, the Denver-Julesburg Basin (DJ Basin), the Midcontinent and Eagle Ford. Pipelines systems owned by DCP Sand Hills and DCP Southern Hills provide takeaway capabilities for DCP LP’s gathering and processing operations and provide access to customers and market outlets on the U.S. Gulf Coast, including our Sweeny fractionation and export facilities. The integration of DCP LP’s, DCP Sand Hills’ and DCP Southern Hills’ operations into our existing operations provides us with a diversified and integrated portfolio of assets across the wellhead-to-market value chain.
Natural Gas Processing
DCP LP owns or operates 36 active natural gas processing facilities, with a net processing capacity of 5.5 billion cubic feet per day (Bcf/d). At some of these facilities, we fractionate NGL into individual components (ethane, propane, butane and natural gasoline).
Pipeline Systems
At December 31, 2023, our aggregate direct and indirect economic interest in DCP LP was 86.8%, and our aggregate direct and indirect economic interests in DCP Sand Hills and DCP Southern Hills was 91.2%. DCP Sand Hills and DCP Southern Hills own NGL pipeline systems that connect the Eagle Ford, Permian Basin and Midcontinent production areas to the Mont Belvieu,Texas, market hub.
Sweeny Hub Assets
The Sweeny Hub is a U.S. Gulf Coast NGL market hub, consisting of four fractionators with a total fractionation nameplate capacity of 550,000 BPD, a liquified petroleum gas (LPG) export terminal, and NGL storage caverns. The 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 DCP 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. It also includes our C2G Pipeline, which is a 16-inch ethane pipeline that connects our Clemens Caverns storage facility to petrochemical facilities in Gregory, Texas, near Corpus Christi.
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 a propane vessel and a butane vessel, and has a combined LPG export capacity of 260,000 BPD. In addition, the terminal has the capability to export natural gasoline (C5+) produced by the Sweeny Hub fractionators.
The following table depicts our ownership interest in major pipeline systems included in our NGL and Other business at December 31, 2023:
Name State of
Origination/Terminus Interest Length
(Miles) Gross Capacity
(MBD)
NGL
Black Lake † Louisiana/Texas 100 % 314 80
C2G Texas 100 155 185
Chisholm Oklahoma/Kansas 50 202 42
Front Range † Colorado/Texas 33 450 260
Panola † Texas 15 250 100
Powder River Wyoming/Colorado 100 366 16
River Parish NGL Louisiana 100 499 104
Sand Hills †* New Mexico/Texas 100 1,400 500
Southern Hills †* Kansas/Texas 100 940 192
Seabreeze/Wilbreeze † Texas 100 80 52
Sweeny LPG Texas 100 260 942
Sweeny NGL Texas 100 18 204
Texas Express † Texas 10 600 370
Wattenberg † Colorado/Kansas 100 450 112
Natural Gas
Cheyenne Connector † Colorado 50 70 0.6 Bcf/d
Guadalupe † Texas Various 600 0.2 Bcf/d
Gulf Coast Express † Texas 25 530 2.0 Bcf/d
† Owned by DCP LP. At December 31, 2023, Phillips 66 held an aggregate 86.8% direct and indirect economic interest in DCP LP.
* Interest reflects Phillips 66’s 33.33% direct ownership interest in DCP Sand Hills and DCP Southern Hills, as well as its 86.8% aggregate direct and indirect economic interest in DCP LP, which owns a direct two-thirds interest.
The following table depicts our ownership interest in terminal and storage facilities included in our NGL and Other business at December 31, 2023:
Facility Name Location Commodity Handled Interest Gross Storage Capacity (MBbl) Gross Rack Capacity (MBD)
Clemens Texas NGL 100 % 16,500 N/A
Freeport Texas Refined Petroleum Products, NGL 100 3,485 N/A
Marysville † Michigan NGL 100 8,000 N/A
River Parish Louisiana NGL 100 1,500 N/A
Spindletop † Texas Natural Gas 100 12 Bcf N/A
† Owned by DCP LP. At December 31, 2023, Phillips 66 held an aggregate 86.8% direct and indirect economic interest in DCP LP.
The following table depicts our ownership interest in a marine facility included in our NGL and Other business at December 31, 2023:
Facility Name Location Commodity Handled Interest Gross Loading Capacity (MB/h)
Marine
Freeport Texas Refined Petroleum Products, NGL 100 % 46
The following table depicts our ownership interest in NGL fractionators included in our NGL and Other business at December 31, 2023:
Facility Name Location Interest Capacity (MBD)
Conway Kansas 40 % 43
Enterprise †* Texas 25 61
Gulf Coast Fractionators** Texas 23 33
Mont Belvieu 1 † Texas 20 32
Sweeny Fractionators Texas 100 550
† Owned by DCP LP. At December 31, 2023, Phillips 66 held an aggregate 86.8% direct and indirect economic interest in DCP LP.
* Interest reflects Phillips 66’s 12.5% direct interest, as well as its 86.8% direct and indirect economic interest in DCP LP, which owns a direct 12.5% interest.
** This facility has been idled since December 2020, with plans to restart in the second quarter of 2024.
The following table depicts our operating data in Gathering and Processing assets included in our NGL and Other business at December 31, 2023:
Regions Plants Approximate Gathering and Transmission Systems (Miles) Approximate Net Nameplate Plant Capacity (MMcf/d) †
North 13 3,400 1,580
Midcontinent 6 22,800 1,110
Permian 10 15,300 1,220
South 7 6,400 1,630
† Plant capacity represents DCP LP’s proportional ownership. At December 31, 2023, Phillips 66 held an aggregate 86.8% direct and indirect economic interest in DCP LP.
NOVONIX
We own a 16% interest in NOVONIX, a Brisbane, Australia-based company that develops technology and supplies materials for lithium-ion batteries. Our investment in NOVONIX supports an expansion of synthetic graphite production capacity at NOVONIX’s Chattanooga, Tennessee, plant.
CHEMICALS
The Chemicals segment consists of our 50% equity investment in CPChem, which is headquartered in The Woodlands, Texas. At December 31, 2023, CPChem owned or had joint venture interests in 30 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.
CPChem 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. CPChem manufactures and markets aromatics and styrenics products, such as benzene, cyclohexane, styrene and polystyrene, as well as 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. 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, 2023:
Millions of Pounds per Year*
U.S. Worldwide
Ethylene 11,910 14,430
Propylene 3,675 4,180
High-density polyethylene 5,305 7,470
Low-density polyethylene 620 620
Linear low-density polyethylene 1,815 1,815
Polypropylene - 310
Normal alpha olefins 2,920 3,435
Polyalphaolefins 125 255
Polyethylene pipe 500 500
Benzene 1,600 2,530
Cyclohexane 1,060 1,455
Styrene 1,050 1,875
Polystyrene 835 915
Specialty chemicals 440 575
Total 31,855 40,365
* Capacities include CPChem’s share in equity affiliates and excludes CPChem’s NGL fractionation capacity.
During 2023, CPChem completed construction and began operations of a 585 million pounds per year 1-hexene unit in Old Ocean, Texas. Additionally, CPChem completed construction and began operations of a 1 billion pounds per year propylene splitter at its Cedar Bayou facility in the fourth quarter of 2023.
CPChem and a co-venturer are building world-scale petrochemical facilities on the U.S. Gulf Coast and in Ras Laffan, Qatar. On the U.S. Gulf Coast, the Golden Triangle Polymers (GTP) facility will include a 4.6 billion pounds per year ethane cracker and two high-density polyethylene units with a combined capacity of 4.4 billion pounds per year. CPChem owns a 51% equity share in the joint venture. The Ras Laffan Petrochemical (RLP) facility will include a 4.6 billion pounds per year ethane cracker and two high-density polyethylene units with a total capacity of 3.7 billion pounds per year. CPChem owns a 30% equity share in the joint venture. Both facilities are expected to start up in 2026.
REFINING
Our Refining segment refines crude oil and other feedstocks into petroleum products, such as gasoline, distillates and aviation fuels, as well as renewable fuels. This segment includes 12 refineries in the United States and Europe.
The table below depicts information for each of our owned and joint venture refineries at December 31, 2023:
Thousands of Barrels Daily
Region/Refinery Location Interest Net Crude Throughput
Capacity Net Clean Product
Capacity** Clean
Product
Yield
Capability
At
December 31 2023 Effective January 1 2024 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 27 87
537 537
Gulf Coast
Lake Charles Westlake, LA 100 264 264 105 115 70
Sweeny Old Ocean, TX 100 265 265 158 125 86
529 529
Central Corridor
Ponca City Ponca City, OK 100 217 217 120 100 93
Billings Billings, MT 100 66 66 37 30 90
Wood River Roxana, IL 50 173 173 88 70 81
Borger Borger, TX 50 75 75 50 35 91
531 531
West Coast
Ferndale Ferndale, WA 100 105 105 65 39 90
Los Angeles Carson/Wilmington, CA 100 139 139 85 65 90
San Francisco*** Rodeo, CA 100 52 - - - -
296 244
1,893 1,841
* 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.
*** As part of our plans to convert the San Francisco Refinery into a renewable fuels facility, in early 2023, we ceased operations at the Santa Maria facility in Arroyo Grande, California, which reduced net crude throughput capacity from 120 MBD to 75 MBD. In October 2023, we further reduced net crude throughput capacity from 75 MBD to 52 MBD as we shut down one of the two crude units at the Rodeo facility. Effective January 1, 2024, net crude throughput capacity was 52 MBD, but we expect the remaining net crude throughput capacity to come offline upon the shutdown of the Rodeo facility’s second crude unit by the end of February 2024. Accordingly, we have not presented net crude throughput capacity effective January 1, 2024, net clean product capacities and clean product yield capability in the table.
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 l
Humber l l l l l l
MiRO l l l 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 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.
** We expect to stop processing crude oil at this refinery by the end of February 2024. See further discussion in the notes to the preceding table and the discussion below.
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 and railcar.
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
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, isomerization 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 Marketing and Specialties (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, a vacuum distillation unit, and a 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
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.
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.
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
Historically, our San Francisco Refinery consisted of two facilities linked by our pipelines: the Santa Maria facility, located in Arroyo Grande, California, and the Rodeo facility, located in the San Francisco Bay Area. We are in the process of converting the San Francisco Refinery into one of the world’s largest renewable fuels facilities. Consequently, in February 2023, we ceased operations of the Santa Maria Facility, and, in October 2023, we shut down one of the two crude units at the Rodeo facility. We expect to shut down the second crude unit at the Rodeo facility by the end of February 2024 and begin operations as a renewable fuels facility in the first quarter of 2024. The conversion will reduce emissions from the facility and produce lower carbon intensity transportation fuels. Upon completion, the facility will have over 50,000 BPD (800 million gallons per year) of renewable fuels production capacity. The renewable fuel production primarily will be distributed to customers in California, Oregon and Washington.
Until its expected shutdown, the Rodeo facility includes crude distillation, naphtha reforming, hydrocracking, hydrodesulfurization and delayed coking units. 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.
MARKETING AND SPECIALTIES
Our M&S segment purchases for resale and markets refined petroleum products, such as gasoline, distillates and aviation fuels, as well as renewable 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, 2023, we had approximately 7,260 branded outlets in 48 states and Puerto Rico.
Our wholesale operations utilize a network of marketers operating approximately 5,090 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 1,390 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 participate in joint ventures engaged in retail convenience store operations in the West Coast, as well as the Midcontinent and Rockies regions. These joint ventures enable us to secure long-term placement of our refinery production and extend participation in the retail value chain. At December 31, 2023, our retail joint ventures had approximately 790 outlets.
In the third quarter of 2023, we acquired a marketing business on the U.S. West Coast to optimize the placement of renewable diesel that will be produced by the Rodeo renewable fuels facility.
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, 2023, we had approximately 1,270 marketing outlets in Europe, of which approximately 980 were company owned and approximately 290 were dealer owned. We had interests in 330 additional sites through our Coop joint venture operations in Switzerland, and we held brand-licensing agreements covering approximately 70 sites in Mexico.
Specialties
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.
In addition, we own a 50% interest in Excel Paralubes LLC (Excel Paralubes), an operated joint venture that owns a hydrocracked lubricant base oil manufacturing plant located adjacent to the Lake Charles Refinery. The facility has capacity to produce 22,200 BPD of high-quality Group II clear hydrocracked base oils. Excel Paralubes markets the produced base oil under the Pure Performance brand. The facility’s feedstock is sourced primarily from our Lake Charles Refinery.
ENERGY RESEARCH & INNOVATION
Our Energy Research & Innovation organization, located in Bartlesville, Oklahoma, includes scientists and engineers working in over 200 laboratories and numerous pilot plants on our 440 acre research campus to develop new technical solutions focused on advancing our business and solving tomorrow’s energy challenges. Areas of focus for 2023 included feedstock characterization, renewables processing, and process optimization to enhance margins and reliability in our Refining, Midstream and M&S segments.
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 that are designed to enable us to deliver industry leading performance. On April 1, 2023, DCP Midstream employees transitioned into Phillips 66, and we are in the process of integrating the operations of DCP Midstream Class A Segment to enable the capture of commercial and operational synergies. At December 31, 2023, we had approximately 14,000 employees working toward our mission of providing energy and improving lives and our vision to be the leading integrated downstream energy provider.
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 priorities 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. The human capital measures and objectives that we focus on in managing our business and that we believe are important to understand our business, include:
•Safety-Safety is the cornerstone of our business. We endeavor to protect the health and safety of everyone who has a role in our operations and the communities in which we operate. We employ rigorous employee training and audit programs to drive ongoing improvement in personal safety as we strive for zero incidents. We include environmental and safety metrics in our annual incentive compensation program, including our total recordable rate and process safety event rate, to incentivize and reward safe operations. Under the variable cash incentive program, our personal safety performance is measured by our total recordable rate (TRR), which measures the number of incidents per 200,000 hours worked. In 2023, our combined workforce TRR of 0.12 was industry leading and 25 times better than the U.S. manufacturing average.
•Culture-Phillips 66 fosters behaviors that promote our culture. “Our Energy in Action” is a set of core behaviors embedded in the company’s talent and business processes to drive performance and 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 a diverse workforce and inclusive culture that supports equal opportunities. Our executive inclusion and diversity (I&D) council, chaired by our President and Chief Executive Officer and comprised of executives and business leaders, sets and monitors the execution of our I&D strategy. Members of the I&D council also serve as global sponsors of our 10 Employee Resource Groups (ERGs). These ERGs are organizations formed around a shared set of experiences and perspectives, and are focused on professional development, networking, raising cultural awareness, community involvement and supporting Phillips 66 recruiting activities. Our ERGs drive employee engagement and align with our corporate objective of fostering an inclusive and diverse workplace.
Historically, we have conducted biennial employee engagement surveys to gather employee perspectives on their experience. In 2023, we transitioned from a biennial to an annual employee engagement survey, with targeted pulse checks to enable us to capture real-time feedback on metrics such as employee engagement, manager effectiveness, performance enablement and our culture. The results of the survey are shared with our employees and Board of Directors. Management analyzes the findings from the survey to monitor our progress and identify potential areas of opportunity.
•Capability-We strive to build depth and breadth in the skills of our employees to create a workforce ready for the future. We drive employee development through technical training and providing opportunities for job rotations, as well as assisting employees with obtaining and sharpening managerial skills through targeted development programs and promotional moves. Our performance management process is designed to identify coaching and training needs.
We also have robust succession management practices and work each year to identify successors for key leadership positions within the company. As part of the process, quarterly sessions are held with management to monitor and guide leadership development.
•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 help drive desired behaviors. Additionally, “High Performing Organization” is one of the metrics used in our variable cash incentive program. In assessing our “High Performing Organization,” we measure success in areas such as employee engagement, I&D efforts, talent attraction, retention and development, and our organization’s ability to adapt and respond to challenges, changing market conditions or other external factors.
COMPETITION
Our businesses operate in a competitive environment. In the Midstream segment, our crude oil and refined products pipelines face competition from other crude oil and products pipeline companies, major integrated oil companies, as well as independent crude oil gathering and marketing companies. Competition is based primarily on quality of customer service and reliability, competitive rates and the proximity of our assets to customers and market hubs. In addition, the Midstream segment competes with numerous integrated petroleum companies, as well as natural gas processing, transmission and distribution companies, to deliver natural gas and NGL to end users. 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 and gas processing plants and securing markets placement for the products produced.
Elements of competition for both our Chemicals and Refining segments include product improvement, new product development, low-cost structures, ability to source adequate feedstock supply and run advantaged feedstocks, and efficient manufacturing and distribution systems. In the M&S segment, 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, 2023, we held a total of 518 active patents in 18 countries worldwide, including 415 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 HSE management system is designed to identify and mitigate the risks of personal safety, process safety, and environmental incidents. 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 in safety and environmental performance.
We are subject to various federal laws and government regulations concerning environmental matters and employee safety and health in the United States and other countries. In addition, 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 2023 and those expected for 2024 and 2025.
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 Our Manufacturing and Operations
Market conditions, including volatile commodity prices, margins and demand for refined petroleum, petrochemical and plastics products, impact our earnings, financial condition and cash flows.
Similar to other companies in the industry in which we operate, 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 cost 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, geopolitical risks, such as turmoil in the Middle East, Eastern Europe, and other producing regions, technology advancements and the pace of the energy transition, weather-related damage and disruptions due to other natural or human causes, consumer preferences and the use and availability of substitute products, and governmental regulation. We do not produce crude oil and other feedstocks and must purchase all of the feedstocks 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. The ability of the members of the Organization of Petroleum Exporting Countries (OPEC) to agree on and to maintain crude oil price and production controls and changes in trade flows from events such as the Russia-Ukraine war have also had, and are likely to continue to have, a significant impact on the market prices of crude oil and certain of our products. 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 natural gas and crude oil also influences prices for the petrochemical and plastics products we produce and the feedstocks used to manufacture those products. Our Chemicals segment uses feedstocks that are derivatively produced in the processing of natural gas and refining of crude oil, 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.
Sustained or prolonged declines in commodity prices and margins for our products may adversely affect our results of operations, liquidity, access to the capital markets, and our ability to fund our capital priorities, including share repurchases and dividends.
Market conditions, including volatile commodity prices and demand for crude oil, natural gas and NGL, impact the earnings, financial condition and cash flows of our Midstream business.
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 crude 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 crude 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 crude 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 crude oil and refined petroleum products in the areas serviced by our assets. A period of sustained low demand or prices for crude oil could lead to a decline in drilling activity and production, which would lead to a decrease in the volumes of crude oil transported through our pipelines and terminal facilities, negatively affecting our earnings and cash flows. Likewise, our earnings and cash flows would be negatively impacted by a period of sustained lower demand for refined petroleum products, which could lead to lower refinery utilization and result in a decrease in the volumes of refined petroleum product transported through our pipelines and terminal facilities.
The natural gas gathered, processed, transported, sold and stored by us 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. Additionally, revenues and cash flows can increase or decrease as the price of natural gas and NGL fluctuates 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.
In order to maintain or increase throughput levels on our natural gas gathering and transportation pipeline systems and NGL pipelines and the asset utilization rates at our natural gas processing plants, we 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 we are 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 our pipelines and the utilization rates of our treating and processing facilities would decline. This could have a material adverse effect on our business, results of operations, financial position and cash flows, and our ability to make cash distributions.
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. Additionally, the availability of natural gas and electricity necessary to operate our assets can be affected by weather, pipeline interruptions, grid outages, and logistics disruptions, which may also cause us to temporarily curtail or shut down operations.
Although we take precautions to ensure and enhance the safety of our operations and minimize the risk of disruptions, our operations are subject to the hazards inherent in chemicals, refining and midstream businesses, such as explosions, fires, refinery, processing facility or pipeline releases or other incidents, power outages, labor disputes, global health crises, restrictive governmental regulation or other natural or man-made disasters, such as geopolitical conflicts and 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 remediation fines or penalties 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, public health crises, armed hostilities, or third-party actions, including protests. 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.
Our investments in joint ventures decrease our ability to manage risk.
We conduct some of our operations, including parts of our Midstream, Refining and Marketing and Specialties (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.
Public health crises, epidemics and pandemics, such as the COVID-19 pandemic, have had and could continue to have a material adverse effect on our business. Any future widespread health crises could materially and adversely impact our business in the future.
Our global operations expose us to risks associated with public health crises and outbreaks of epidemics, pandemics, or contagious diseases, such as COVID-19. The COVID-19 pandemic and the associated containment efforts had a serious adverse impact on the economy and a material adverse effect on our business, as the demand for crude oil, gasoline, jet fuel, diesel fuel and other refined products was significantly reduced. We may be impacted again in the future depending on the duration and scope of any future health crises, epidemics, or pandemics.
Even if a virus or other illness does not spread significantly, the perceived risk of infection or health risk may result in reduced demand for our products and materially affect our business. As we cannot predict the duration or scope of any public health crisis, epidemic or pandemic, the negative financial impact to our results cannot be reasonably estimated and could be material. Factors that will influence the impact on our business and operations include the duration and extent of such events, including the virulence of the infection, the timing of vaccine development and distribution across the world and its impact on economic recovery, the extent of imposed or recommended containment and mitigation measures, including travel restrictions, and their impact on our operations, and the general economic consequences of public health crises, epidemics and pandemics, such as the COVID-19 pandemic.
To the extent any public health crisis, epidemic or pandemic adversely affected or affects our business and financial results, it may also have the effect of heightening many of the other risks that could adversely affect our business described in this Annual Report, such as risks associated with industry capacity utilization, volatility in the price and availability of raw materials, supply chain interruptions, material adverse changes in customer relationships including any failure of a customer to perform its obligations under agreements with us, and risks associated with worldwide or regional economic conditions.
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.
Volatility in market demand for our petrochemical and plastics products and midstream transportation services and the risk of overbuild in these industries could negatively impact the results of operations of our businesses.
We and our equity affiliates have made and continue to make significant investments to meet market demand for our products and services, such as investments in midstream infrastructure and construction of new petrochemicals facilities. 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 and industries 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 our products or services may change, or additional investments by competitors may be made that could result in an overbuild of supply. Any of these or other competitive forces could materially adversely affect our results of operations, financial position or cash flows, as well as our return on capital employed.
Strategic Performance and Future Growth Risks
Large capital-intensive projects can take many years to complete, and the political and regulatory environments or market conditions could deteriorate significantly between the project approval date and the project startup date, negatively impacting expected project returns.
Our basis for approving large-scale capital-intensive projects, such as the conversion of our San Francisco refinery into a renewable fuels facility, 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, the political and regulatory environments or other market conditions can change from those we anticipate, and these changes could be significant. Supply chain disruptions may also delay projects or increase costs. 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 or our joint ventures may have to expand or construct assets or develop new technologies, and plans for our future performance are subject to risks associated with societal and political pressures and other forms of opposition to the future development, transportation and use of petroleum-based fuels. Such risks could adversely impact our business and results of operations.
Certain of our plans are based upon the assumption that societal sentiment will continue to enable, and existing regulations will remain in place to allow for, the future development, transportation and use of petroleum-based fuels. A portion of our growth strategy is dependent on our and our joint ventures’ ability to capture growth opportunities in the Midstream and Chemicals segments. Regulatory policy decisions relating to the production, refining, transportation, marketing and use of petroleum-based fuels are subject to political pressures and the influence and protests of environmental and other special interest groups. For example, the construction or expansion of pipelines can involve numerous regulatory, permitting, environmental, political, and legal uncertainties, many of which are beyond our control. We may not be able to identify or execute growth projects, and those that are identified may not be completed on schedule or at the budgeted cost, if at all. 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 or the inability to complete growth projects could negatively impact our reputation, results of operations, cash flows and our return on capital employed.
Our Energy Research & Innovation organization works to develop new technologies and solutions focused on advancing our business units, including renewable and sustainable fuels research. Our efforts to research and develop new technologies is subject to a multitude of factors and conditions, many of which are out of our control. Examples of such factors include evolving government regulation, the pace of changes in technology, the successful development and deployment of existing or new technologies and business solutions on a commercial scale, competition from third parties in developing new technologies and the availability, timing and cost of equipment. The occurrence of these factors may delay or increase the cost of our efforts, which could negatively impact our reputation, 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:
•Establishing maximum margins that can be earned on sales of motor fuels or imposing financial penalties on profits earned above established maximum margins.
•Limiting or prohibiting our ability to undertake turnaround or other maintenance activities at our refineries.
•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.
For example, in March 2023, the California legislature adopted Senate Bill No. 2 (such statute, together with any regulations contemplated or issued thereunder, SBx 1-2), which, among other things, (i) authorizes the establishment of a maximum gross gasoline refining margin (maximum margin) and the imposition of a financial penalty for profits above the maximum margin, (ii) significantly expands reporting obligations relating to the maintenance and business of our California refineries, which includes reporting requirements to the California Energy Commission (CEC) for all participants in the petroleum industry supply chain in California, (iii) creates the Division of Petroleum Market Oversight within the CEC to analyze the data provided under SBx 1-2, and (iv) authorizes the CEC to regulate the timing and other aspects of refinery turnaround and other maintenance activities in certain instances. The CEC is currently in rulemaking with respect to various aspects of SBx 1-2, and the potential implementation of a financial penalty or any restrictions or delays on our ability to undertake turnaround or other maintenance activities creates uncertainty due to the potential adverse effects on our refining, marketing and midstream operations in California, which may be material to our results of operations, financial condition, profitability and cash flows.
We anticipate that other jurisdictions may contemplate similarly focused legislation or actions. The ultimate timing and impacts of SBx 1-2 and any other similarly focused legislation or actions are subject to considerable uncertainty due to a number of factors, including technological and economic feasibility, legal challenges, and potential changes in law, regulation, or policy, and it is not currently possible to predict the ultimate effects of these matters and developments, but they may be significant. For example, adverse effects on the financial performance of our operations in the state of California or the useful lives of the assets related to such operations may result in the recognition of material asset impairment charges and asset retirement obligations.
Furthermore, 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. We may face other regulatory changes in the U.S. including, but not limited to, the enactment of tax law changes that adversely affect our industry, new emissions standards, restrictive flaring regulations, and more stringent requirements for environmental impact studies and reviews.
Hostilities in the Middle East, Russia or elsewhere or the occurrence or threat of future terrorist attacks could adversely affect the economies of the U.S. and other countries. Other political and economic risks include global health crises; financial market turmoil; economic volatility and global economic slowdown; currency exchange rate fluctuations; short-term and long-term inflationary pressures; rising or prolonged periods of high interest rates; import or export restrictions and changes in trade regulations; supply chain disruptions; civil unrest and other political risks; limitations in the availability of labor to develop, staff and manage operations; and potentially adverse tax developments. If any of these events occur, our businesses and results of operations may be adversely affected.
We may not be able to effectively identify, whether through acquisition, investment or development, lower-carbon opportunities on favorable terms, or at all, and failure to do so could limit our growth, our ability to participate in the energy transition, and our ability to meet our environmental goals and targets.
Part of our strategy includes capturing growth opportunities in our Emerging Energy business to further advance our participation in the energy transition and meet our greenhouse gas (GHG) emissions reduction targets. This strategy depends on our ability to successfully identify and evaluate acquisition and investment opportunities or develop and commercialize new technologies. The number of lower-carbon opportunities may be limited, and we will compete with other energy companies for these limited opportunities, which could make them more expensive and the returns for our business less attractive and possibly cause us to refrain from making them at all. Further, certain lower-carbon opportunities will depend on technological and other advancements that may not be within our control and may not come to fruition or be economically feasible in the near term. Any new opportunities also may depend on the viability of new assets or businesses that are contingent on public policy mechanisms including investment tax credits, subsidies, renewable portfolio standards and carbon trading plans. These mechanisms have been implemented at the state and federal levels to support the development of renewable energy and other clean infrastructure technologies. The availability and continuation of public policy support mechanisms will drive a significant part of the economics and viability of lower-carbon and clean energy investments generally, as well as our participation in them. If we are unable to identify and consummate acquisitions and investments, our ability to execute a portion of our growth strategy and meet our environmental goals may be impeded.
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, as well as other chronic physical effects such as water shortages and rising sea levels, 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 such events could have an adverse effect on our assets and operations. Examples of potential physical risks include floods, hurricane-force winds, severe storms, droughts, heat waves, earthquakes, 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.
We operate facilities located in coastal regions of the United States, which have been impacted by hurricanes that have required us to temporarily, or even permanently, shut down operations at those sites. CPChem also operates facilities on the Gulf Coast and has had to temporarily shut down sites in the past as a result of hurricanes. Any extreme weather events or rising sea levels may disrupt the ability to operate our facilities located near coastal areas or to transport crude oil, refined petroleum or petrochemical and plastics products in these areas. 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, gas processing facilities 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 at 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 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 for GHG emissions 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, on August 25, 2022, the California Air Resources Board (CARB) adopted regulations that effectively ban the in-state sales of new cars containing internal combustion engines beginning in 2035. Also, on December 15, 2022, CARB adopted its “2022 Scoping Plan for Achieving Carbon Neutrality,” which purports to provide a road map for California to achieve carbon neutrality (which it defines as removing as many carbon emissions from the atmosphere as it emits) by year 2045. 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.
Federal, regional and state climate change and air emissions goals and regulatory programs are complex, subject to change and impose 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 heightened societal awareness and a number of international and national measures to limit GHG emissions. Additional stricter regulatory 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, and the 2023 United Nations Climate Change Conference, 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 future of the U.S.’s climate change strategy and the impact to our industry and operations due to further GHG regulation is unknown at this time.
Increased regulation of the fossil fuel industry, particularly with respect to 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.
Most of the crude oil and natural 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.
Also, certain interest groups have also proposed ballot initiatives and constitutional amendments designed to restrict crude oil and natural gas development generally. If ballot initiatives, local, state, or national restrictions or prohibitions are adopted and result in more stringent limitations on the production and development of crude oil and natural gas, we may incur significant costs to comply with the requirements, and producers may experience delays or curtailment in the permitting or pursuit of exploration, development or production activities. Such compliance costs and delays, curtailments, limitations or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity. In addition to these proposed ballot initiatives and constitutional amendments, municipalities, such as the City of Los Angeles, have already enacted or contemplate enacting complete or partial bans on oil and gas exploration and production activities.
If legislative and regulatory initiatives cause a material decrease in the drilling of new wells and related servicing activities, it may reduce crude oil, natural gas and NGL supplies, negatively affecting the volume of products available to our Midstream segment and increasing feedstock prices for our Chemicals and Refining segments, resulting in a material adverse effect on our financial position, results of operations and cash flows.
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 renewable volume obligation (RVO) requirements 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 RVO requirements 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, if we purchase RINs that are ultimately determined to be invalid, or if we are otherwise unable to meet the EPA’s RVO requirements, 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 for sale in the United States.
Societal, technological, political and scientific developments around emissions and fuel efficiency may decrease demand for traditional transportation fuels.
Developments aimed at reducing GHG emissions may decrease the demand or increase the cost for our transportation fuels. Societal 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 products. 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 the motor fuel we produce. 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. The competition for renewable fuels feedstocks may also increase, negatively impacting the availability of such feedstocks or increasing their cost.
These developments could potentially have a material adverse effect on our business, financial condition, results of operations and cash flows.
Continuing political and social concerns about climate change and other Environmental, Social and Governance (ESG) matters may result in changes to our business and significant expenditures, including litigation-related expenses.
Increasing attention to global climate change has resulted in increased investor attention and an increased risk of public and private litigation, which could increase our costs or otherwise adversely affect our business. Additionally, cities, counties, and other governmental entities in several states in the U.S. began filing lawsuits against energy companies in 2017, including Phillips 66, seeking damages allegedly associated with climate change, and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Similar lawsuits may be filed in other jurisdictions. While we believe these lawsuits are an inappropriate vehicle to address the challenges associated with climate change and will vigorously defend against them, the ultimate outcome and impact to us of any such litigation cannot be predicted with certainty, and we could incur substantial legal costs associated with defending these and similar lawsuits in the future.
Additionally, governments and private parties are also increasingly filing lawsuits or initiating regulatory action based on allegations that certain public statements regarding climate change and other ESG-related matters and practices by companies are false or misleading “greenwashing” that violate deceptive trade practices and consumer protection statutes. Such claims are included in lawsuits filed against energy companies, including Phillips 66. Such lawsuits present a high degree of uncertainty regarding the extent to which energy companies face an increased risk of liability stemming from climate change or ESG disclosures and practices.
Efforts have also been made by governments and private parties to shut down energy assets by challenging operating permits, the validity of easements or the compliance with easement conditions. Lawsuits and/or regulatory proceedings or actions of this nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which may have a material, adverse effect on our business, financial condition, results of operation and cash flows.
These risks may result in unexpected costs, negative sentiments about our company, disruptions in our operations, increases to our operating expenses and reduced demand for our products, which in turn could have an adverse effect on our business, financial condition and results of operations.
Increased concerns regarding plastic waste in the environment, consumers selectively reducing their consumption of plastic products due to recycling concerns, or new or more restrictive regulations and rules related to plastic waste could reduce demand for CPChem’s plastic products and could negatively impact our equity interest.
There is a growing concern with the accumulation of plastic, including microplastics, and other packaging waste in the environment. Additionally, plastics have recently faced increased public backlash and scrutiny. Policy measures to address this concern are being discussed or implemented by governments at all levels. In addition, a host of single-use plastic bans and taxes have been passed by countries around the world and counties and municipalities throughout the U.S. Increased regulation of, or prohibition on, the use of certain plastic products could reduce demand for certain of the products CPChem produces, which could negatively impact its financial condition, results of operations and cash flows, thereby negatively impacting our equity earnings, and cash distributions that we receive, from CPChem.
Cybersecurity and Data Privacy Risks
Cybersecurity incidents 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, including ransomware and other malware, phishing and social engineering schemes, malicious software, data privacy breaches by employees, insiders or others with authorized access, attempts to gain unauthorized access to our data and systems; and other cybersecurity incidents. Any such incidents could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such unauthorized access, disclosure or other loss of information could result in one or more of the following outcomes: (i) unauthorized access to or a loss or misuse 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, or regulatory fines or penalties; (vii) reputational damage that adversely affects customer or investor confidence; (viii) exposure to legal liability; and (ix) damage to our competitiveness, stock price, and long-term stockholder value. Any of the foregoing can be exacerbated by a delay or failure to detect a cybersecurity incident or the full extent of such incident. Further, we have exposure to cybersecurity incidents and the negative impacts of such incidents related to our critical data and proprietary information housed on third-party IT systems, including cloud-based systems. Additionally, authorized third-party IT systems or software can be compromised and used to gain access or introduce malware to our IT systems that can materially impact our business. Although we devote significant resources to prevent cybersecurity incidents and protect our system and data, we have experienced actual and attempted cybersecurity incidents, and while we do not believe that any of these incidents has had a material effect on our business, operations or financial condition, it is possible that a future incident may have such an effect.
A cybersecurity incident 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) and United Kingdom (UK) versions of the General Data Protection Regulation (GDPR) and the California Consumer Privacy Act (CCPA).
The GDPR applies to the transfer and processing of personal data of those who live in the EU or UK, respectively. 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.
Comprehensive privacy laws with some similarities to the CCPA have been proposed or passed at the U.S. federal and state levels, such as the Colorado Privacy Act. Additionally, the Federal Trade Commission and many state attorneys general are interpreting federal and state consumer protection laws to impose standards for the online collection, use, dissemination and security of data as well as requiring disclosures about these practices. Existing and potential future data privacy laws 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.
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 subject to factors 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 available cash 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.
Negative sentiment towards fossil fuels and increased attention to environmental and social matters, including climate change, could adversely affect our business, the market price for our common stock and our access to and cost of capital.
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 fossil fuel companies, as well as to pressure lenders, insurers, and other financial services companies to limit or curtail activities with fossil fuel companies. If these or similar efforts are continued, our stock price, our ability to access capital markets or insure our operations, and our cost of capital may be negatively impacted.
Members of the investment community are also increasing their focus on environmental and social (E&S) matters, including practices related to GHG emissions, climate change, business resilience, diversity and inclusion, environmental justice and other E&S matters. As a result, we may face increasing pressure regarding our E&S disclosures and practices. Additionally, members of the investment community may screen companies such as ours for E&S performance before investing in our stock or participating in our financing activities. If we are unable to meet the E&S standards set by these investors, we may lose investors, our stock price may be negatively impacted, our access to capital markets and lenders may be curtailed, and our reputation may be negatively affected.
Our efforts to accurately report on E&S-related issues expose us to operational, reputational, financial, legal, and other risks. Standards for tracking and reporting on E&S-related matters, including climate-related matters, have not been harmonized and continue to evolve. Processes and controls for reporting on E&S matters are subject to evolving and disparate standards of identification, measurement, and reporting on such metrics, including any climate change and E&S-related public company disclosure requirements adopted by the SEC, and such standards may change over time, which could result in significant revisions to our current E&S practices and disclosures.
A failure to achieve our published GHG emissions intensity reduction goals and other E&S targets we may set in the future could negatively impact our business.
We have announced targets to reduce our Scope 1 and Scope 2 GHG emissions intensity from our operations by 30% and Scope 3 GHG emissions intensity of our energy products by 15% by 2030, and a target to reduce our Scope 1 and Scope 2 GHG emissions intensity by 50% by 2050, in each case as compared to baseline 2019 levels. Our ability to achieve these goals depends on many factors, many of which are beyond our control, such as advancements that enable broad commercial deployment and use of lower-carbon technologies; global policies that fund and incentivize the development of a lower-carbon energy system; changes in consumer behavior and energy choices; the availability of materials throughout the supply chain; evolving regulatory requirements; competitor actions; the availability of renewable feedstocks; and acquisition and divestiture activities. Further, the standards for tracking and reporting on GHG emissions have not been harmonized and continue to evolve. Our selection of disclosure frameworks that seek to align with various reporting standards may change from time to time and may result in a lack of comparative data from period to period. In addition, our processes and controls may not always align with evolving voluntary standards for identifying, measuring, and reporting GHG emissions, our interpretation of reporting standards may differ from those of others, and such standards may change over time, any of which could result in significant revisions to our goals or reported progress in achieving such goals.
The pursuit of these targets, and any other climate-related or E&S goals we may announce, may increase our costs, require us to purchase emissions credits or offsets, or limit or negatively impact our business plans. Further, any failure or perceived failure to achieve such goals and targets within the timelines that we announce, or at all, could cause reputational harm, negatively impact our stock price and access to and cost of capital, and expose us to enforcement or litigation, among other negative impacts.
We do not fully insure against all potential losses, including those from extreme weather events, and, therefore, our business, financial condition, results of operations and cash flows could be adversely affected by unexpected or underinsured liabilities and increased costs.
We maintain insurance coverage in amounts we believe to be prudent, including against many, but not all, potential liabilities arising from operating hazards. We rely on existing liquidity, financial resources and borrowing capacity to meet short-term obligations that would result from uninsured or underinsured liabilities arising from operating hazards, including but not limited to, explosions, fires, refinery or pipeline releases or other incidents involving our assets or operations, including weather events, which 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 credit ratings could be lowered or withdrawn entirely by a rating agency if, in its judgment, the circumstances warrant. If a rating agency were to downgrade our rating below investment grade, our borrowing costs would increase, and our funding sources could decrease. This could require us to provide collateral, or other forms of security, which would increase our costs and restrict operational and financial flexibility.
In addition, a failure by Phillips 66 to maintain an investment grade rating could affect its business relationships with suppliers and operating partners. For example, Phillips 66’s agreement with Chevron Corporation (Chevron) regarding CPChem permits Chevron to buy Phillips 66’s 50% interest in CPChem for fair market value if Phillips 66 experiences a change in control or if both Standard & Poor’s Financial Services LLC and Moody’s Investors Service, Inc. lower their 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 Phillips 66’s 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. In addition, we may be required to incur additional costs in connection with future regulation of derivative instruments to the extent it is applicable to us.
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 in 2012, we entered into an Indemnification and Release Agreement and certain other agreements 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
From time to time, we may be involved in litigation and claims arising out of our operations in the normal course of business. Additionally, we have elected a $300,000 threshold to disclose certain proceedings arising under federal, state or local environmental laws when a governmental authority is a party to the proceedings. The below matters are disclosed in accordance with that requirement. We do not currently believe that the eventual outcome of any matters previously reported, but still unresolved, individually or in the aggregate, could have a material adverse effect on our business, financial condition, results of operations or cash flows.
Further, 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.
We received such a request in the first quarter of 2023, and we expect to receive a final demand for, alleged stipulated penalties arising from self-reported Clean Air Act violations at our Alliance, Borger, Sweeny and Wood River refineries. The proposed penalties exceed $500,000 and would be pursued pursuant to the consent decree referenced above and a related Wood River Refinery consent decree. There have been no further developments with respect to this matter.
New Matters
The California Department of Toxic Substances Control (DTSC), served Phillips 66 Company (as successor to Tosco) and approximately 50 other potentially responsible parties with Imminent and Substantial Endangerment Determinations and Orders and Remedial Action Orders in November 2016 related to historic waste sent to certain California landfill sites that were operated by a now bankrupt party. Since that time, we have been coordinating with other potentially responsible parties to negotiate a proposed settlement with DTSC regarding funding future operations, maintenance, and financial assurance for post-closure activities at the sites. As part of the settlement process and Consent Decree in the matter, in December 2023 we agreed to pay approximately $4 million in full satisfaction of our potential liability at the Vine Hill landfill complex located in Martinez, California. The company does not expect any future financial liabilities related to the Vine Hill landfill complex to be material.
On December 1, 2023, the South Coast Air Quality Management District (SCAQMD) issued a demand for penalties that exceeds the $300,000 reporting threshold. The penalty demand proposes to resolve seven Notices of Violation (NOVs) issued between 2020 and 2022 for alleged violations of air permit and air pollution regulatory requirements at the Los Angeles Refinery. We are working with SCAQMD to negotiate and resolve these NOVs.
Matters Previously Reported (unresolved or resolved since the quarterly report on Form 10-Q for the quarterly period ended September 30, 2023)
In 2018, the Colorado Department of Public Health and Environment (CDPHE) issued a Compliance Advisory in relation to an improperly permitted facility flare and related air emissions from flare operations at one of DCP Operating Company LP’s (DCP Operating LP) gas processing plants, which DCP Operating LP self-disclosed to CDPHE in December 2017. Following information exchanges and discussions with CDPHE, a resolution was proposed pursuant to which the plant’s air permit would be revised, and DCP Operating LP would be assessed an administrative penalty and economic benefit payment. A revised air permit was issued in May 2019, but the parties had not yet entered into a final settlement agreement to complete the matter. Subsequently, in July 2020, CDPHE issued a NOV in relation to amine treater emissions at this plant, which DCP Operating LP self-disclosed to CDPHE in April 2020. Two additional and related NOVs were then issued in 2021 and 2023. DCP Operating LP and the CDPHE have reached a tentative agreement to resolve these matters for aggregate monetary civil penalties of approximately $4 million. As part of the settlement, DCP Operating LP will install emissions management equipment that will address the alleged violations. A final order to resolve these matters is expected to be issued during the first quarter of 2024.
See “Dakota Access, LLC (Dakota Access) and Energy Transfer Crude Oil Company, LLC (ETCO)” section of Note 8-Investments, Loans and Long-Term Receivables and Note 16-Contingencies and Commitments, in the Notes to Consolidated Financial Statements, for additional information regarding Legal Proceedings and other regulatory actions.

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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*
Mark E. Lashier President and Chief Executive Officer 62
Kevin J. Mitchell Executive Vice President and Chief Financial Officer 57
Zhanna Golodryga Executive Vice President, Emerging Energy and Sustainability 68
Richard G. Harbison Executive Vice President, Refining 58
Brian M. Mandell Executive Vice President, Marketing and Commercial 60
Timothy D. Roberts Executive Vice President, Midstream and Chemicals 62
Vanessa L. Allen Sutherland Executive Vice President, Government Affairs, General Counsel and Corporate Secretary 52
J. Scott Pruitt Vice President and Controller 59
* As of February 21, 2024.
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.
Mark E. Lashier is President and Chief Executive Officer, a position he has held since July 2022. Previously, Mr. Lashier served as President and Chief Operating Officer of Phillips 66 from April 2021 to July 2022; President and Chief Executive Officer of CPChem from August 2017 to April 2021; and as Executive Vice President, Commercial of CPChem from August 2015 to August 2017.
Kevin J. Mitchell is Executive Vice President and Chief Financial Officer, a position he has held since January 2016. Previously, Mr. Mitchell served as Vice President, Investor Relations from September 2014 to January 2016.
Zhanna Golodryga is Executive Vice President, Emerging Energy and Sustainability, a position she has held since October 2022. Previously, Ms. Golodryga served as Senior Vice President, Chief Digital and Administrative Officer from April 2017 to October 2022.
Richard G. Harbison is Executive Vice President, Refining, a position he has held since June 2022. Mr. Harbison previously served as Vice President, San Francisco Refinery from March 2021 to May 2022; General Manager, San Francisco Refinery from June 2020 to February 2021; Manager, Lake Charles Manufacturing Complex from February 2016 to May 2020 and Manager of the Ferndale Refinery from August 2014 to January 2016.
Brian M. Mandell is Executive Vice President, Marketing and Commercial, 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.
Timothy D. Roberts is Executive Vice President, Midstream and Chemicals, 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.
Vanessa L. Allen Sutherland is Executive Vice President, Government Affairs, General Counsel and Corporate Secretary, a position she has held since January 2022. Ms. Sutherland previously served as Executive Vice President and Chief Legal Officer of Norfolk Southern Corporation from April 2020 to January 2022; Senior Vice President, Government Relations and Chief Legal Officer from August 2019 to April 2020; Senior Vice President, Law and Chief Legal Officer from April 2019 to August 2019; and Vice President, Law from June 2018 to April 2019. Prior to joining Norfolk Southern Corporation, Ms. Sutherland served as Chairperson of the U.S. Chemical Safety and Hazard Investigation Board from August 2015 to June 2018.
J. Scott Pruitt is Vice President and Controller, a position he has held since August 2021. Mr. Pruitt previously served as General Auditor from September 2020 to August 2021 and Assistant Controller from May 2012 to September 2020.
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 31, 2024, the number of stockholders of record of our shares was 28,817.
Performance Graph
The above performance graph represents cumulative total stockholder return, which assumes reinvestment of dividends, of a $100 investment in our common stock, our self-constructed peer group for the year ended December 31, 2023 (the Peer Group) and the S&P 500 Index, for the five years ended December 31, 2023. We evaluate our peer group on an annual basis and believe the Peer Group closely aligns with our size and lines of business.
The Peer Group consists of CVR Energy, Inc.; Delek US Holdings, Inc.; Dow Inc.; HF Sinclair Corporation; LyondellBasell Industries N.V.; Marathon Petroleum Corporation; ONEOK, Inc.; PBF Energy Inc.; Targa Resources Corp.; Valero Energy Corporation; Westlake Chemical Corporation; and The Williams Companies, Inc. Additionally, HollyFrontier Corporation was included as a peer for periods prior to its acquisition by HF Sinclair Corporation in March 2022.
Issuer Purchases of Equity Securities
On October 25, 2023, our Board of Directors approved a $5 billion increase to our share repurchase authorization. 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.
Millions of Dollars
Period Total Number of Shares Purchased* Average Price Paid per Share** Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs*** Approximate Dollar
Value of Shares
that May Yet Be
Purchased Under the
Plans or Programs
October 1-31, 2023 2,380,576 $ 113.47 2,380,576 $ 7,824
November 1-30, 2023 4,101,833 117.82 4,101,833 7,341
December 1-31, 2023 3,298,558 131.45 3,298,558 6,907
Total 9,780,967 $ 121.36 9,780,967
* Includes repurchase of shares of common stock from company employees in connection with the company’s broad-based employee incentive plans, when applicable.
** Average price paid per share includes excise taxes.
*** Since the inception of our share repurchase program in 2012, our Board of Directors has authorized an aggregate of $25 billion of repurchases of our outstanding common stock. Our share repurchase authorizations do not expire. 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. Shares of stock repurchased are held as treasury shares.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. [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, financial condition, and significant trends that may affect future performance. It should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K.
The term “earnings” as used in Management’s Discussion and Analysis refers to net income attributable to Phillips 66. The terms “results,” “before-tax income” or “before-tax loss” as used in Management’s Discussion and Analysis refer to income (loss) before income taxes.
EXECUTIVE OVERVIEW AND BUSINESS ENVIRONMENT
Phillips 66 is uniquely positioned as a diversified and integrated downstream energy company operating with Midstream, Chemicals, Refining, and Marketing and Specialties (M&S) segments. At December 31, 2023, we had total assets of $75.5 billion.
Executive Overview
During 2023, we reported earnings of $7 billion, generated $7 billion in cash from operating activities and received proceeds from debt offerings, net of debt repayments, of $2 billion. We used available cash primarily to repurchase noncontrolling interests in DCP Midstream, LP (DCP LP) for $4.1 billion, fund capital expenditures and investments of $2.4 billion, repurchase shares of common stock for $4 billion and pay dividends on our common stock of $1.9 billion. We ended 2023 with $3.3 billion of cash and cash equivalents and approximately $6.4 billion of total committed capacity available under our credit facilities.
Strategic Priorities Update
In November 2022, we announced financial and operational targets toward achieving the company’s strategic priorities and in October 2023, we announced updates to certain targets. Our strategic priorities that are intended to enhance long-term shareholder value include:
•Deliver Shareholder Returns - We believe shareholder value is enhanced through, among other things, a secure, competitive and growing dividend, complemented by share repurchases. We increased our target for returns to shareholders through share repurchases and dividends from July 2022 through year-end 2024 to a range of $13 billion to $15 billion from a range of $10 billion to $12 billion. In support of the increased target, our Board of Directors approved a $5 billion increase to our share repurchase authorization on October 25, 2023. We plan to return at least 50% of net cash provided by operating activities to shareholders through share repurchases and dividends. In 2023, we paid $4 billion to repurchase shares of our common stock and paid dividends on our common stock of $1.9 billion. The amount and timing of future dividend payments and the level and timing of future share repurchases is subject to the discretion of, and approval by, our Board of Directors and will depend on various factors including our share price, results of operations, financial condition and cash required for future business plans.
We also plan to monetize certain assets that are no longer considered to be a long-term strategic fit. We expect to generate proceeds of over $3 billion from the disposition of these non-core assets, which we plan to use to further advance our strategic priorities, including returns to shareholders through share repurchases and dividends. The timing of these asset dispositions will be subject to satisfactory market conditions and any necessary regulatory approvals.
•Improve Refining Performance - We are focused on optimizing utilization rates and product yield at our refineries through reliable and safe operations, which will enable us to capture the value available in the market in terms of prices and margins. We plan to enhance Refining segment returns and increase our utilization rates by focusing on low-capital, higher-return projects that increase asset reliability, improve market capture and reduce costs. During 2023, our worldwide refining crude oil capacity utilization rate was 92% and our worldwide refining clean product yield was 85%, compared to 90% and 84%, respectively, in 2022.
•Capture Value from Wellhead-to-Market - We are focused on growing our fully integrated natural gas liquids (NGL) wellhead-to-market value chain within our Midstream segment. As part of executing this strategy, we completed two transactions that increased our economic interest in DCP LP; the first in 2022, which increased our indirect economic interest to 43.3%, and the second in 2023, which increased our aggregate direct and indirect economic interest in DCP LP to 86.8%. We have already captured operating and commercial synergies from these transactions and remain focused on capturing additional synergies as we complete our integration activities in 2024. In 2024, we have budgeted $985 million of capital expenditures and investments in our Midstream segment, of which $593 million will be focused on enhancing our integrated NGL wellhead-to-market value chain. In addition, growth capital includes $250 million related to the repayment of our 25% share of Dakota Access, LLC’s (Dakota Access) debt due in 2024.
•Execute Business Transformation - We continue to progress our multi-year business transformation aimed at sustainably reducing our cost structure. We exceeded our savings target by achieving a run-rate cost reduction of $900 million per year and sustaining capital reduction of $300 million per year by the end of 2023. As such, we are now targeting a run-rate cost reduction of $1.1 billion per year by the end of 2024, while maintaining our sustaining capital reduction of $300 million per year in 2024.
•Maintain Financial Strength and Flexibility - During 2023, we successfully reduced our sustaining capital spend and used available cash and proceeds from debt offerings to increase our economic interest in DCP LP, repurchase shares of our common stock, pay dividends on our common stock, fund capital expenditures and investments and repay a portion of DCP LP’s debt.
•Drive Disciplined Growth and Returns - A disciplined capital allocation process ensures we invest in projects that are expected to generate competitive returns. Our strategy remains focused on investing growth capital in the Midstream and Chemicals segments. We are also investing in capital-efficient renewable fuels projects to advance a lower-carbon future. In 2024, we have budgeted $2.2 billion in capital expenditures and investments, which includes $1.3 billion of growth capital.
DCP Midstream, LLC and Gray Oak Holdings LLC Merger (DCP Midstream Merger)
On August 17, 2022, we announced a realignment of our economic and governance interests in DCP LP and Gray Oak Pipeline, LLC (Gray Oak Pipeline) resulting from the merger of DCP Midstream, LLC (DCP Midstream) and Gray Oak Holdings LLC (Gray Oak Holdings). In connection with the DCP Midstream Merger, we were delegated DCP Midstream’s governance rights over DCP LP and its general partner entities, referred to as DCP Midstream Class A Segment, and our indirect economic interest in DCP LP increased to 43.3%.
Starting on August 18, 2022, our financial results reflect the consolidation of DCP Midstream Class A Segment, as well as DCP Sand Hills Pipeline, LLC (DCP Sand Hills) and DCP Southern Hills Pipeline, LLC (DCP Southern Hills). Since the DCP Midstream Merger, we have taken steps to integrate the operations and personnel of DCP Midstream Class A Segment to enable the capture of commercial and operational synergies.
DCP Midstream, LP Merger (DCP LP Merger)
On June 15, 2023, we completed the acquisition of all publicly held common units of DCP LP pursuant to the terms of the Agreement and Plan of Merger, dated as of January 5, 2023 (DCP LP Merger Agreement). The DCP LP Merger Agreement was entered into with DCP LP, its subsidiaries and its general partner entities, pursuant to which one of our wholly owned subsidiaries merged with and into DCP LP, with DCP LP surviving as a Delaware limited partnership. Under the terms of the DCP LP Merger Agreement, at the effective time of the DCP LP Merger, each publicly held common unit representing a limited partner interest in DCP LP (other than the common units owned by DCP Midstream and its subsidiaries) issued and outstanding as of immediately prior to the effective time was converted into the right to receive $41.75 per common unit in cash. The DCP LP Merger increased our aggregate direct and indirect economic interest in DCP LP from 43.3% to 86.8%.
See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, in the Notes to Consolidated Financial Statements, for additional information on the DCP Midstream and DCP LP Mergers.
Business Environment
The Midstream segment includes our Transportation and NGL businesses. Our Transportation business contains fee-based operations not directly exposed to commodity price risk. Our NGL business, including DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills from August 18, 2022, forward, contains both fee-based operations and operations directly impacted by NGL and natural gas prices. During 2023, NGL and natural gas prices decreased, compared with 2022, as the result of increased production.
The Chemicals segment consists of our 50% equity investment in Chevron Phillips Chemical Company LLC (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 2022, the benchmark high-density polyethylene chain margin decreased in 2023, due to lower polyethylene sales prices as a result of industry oversupply driven by recent capacity additions.
Our Refining segment results are driven by several factors, including market crack spreads, refinery throughput, feedstock costs, product yields, turnaround activity, and other operating costs. Market crack spreads are used as indicators of refining margins and measure the difference between market prices for refined petroleum products and crude oil. The composite 3:2:1 market crack spread for our business decreased to an average of $28.37 per barrel during 2023, from an average of $34.26 per barrel in 2022. The decrease in the composite market crack spread was primarily driven by lower global prices for gasoline and distillates reflecting reduced refining costs due to lower natural gas prices. While the composite market crack spread fell in 2023, from the highest levels in at least a decade during 2022, it remains well above the five-year and 10-year average levels. The price of U.S. benchmark crude oil, West Texas Intermediate (WTI) at Cushing, Oklahoma, decreased to an average of $77.69 per barrel during 2023, from an average of $94.44 per barrel in 2022. The decrease in crude oil prices was primarily driven by increased production in the United States and other countries outside of the Organization of Petroleum Exporting Countries (OPEC).
Results for our M&S segment depend largely on marketing fuel and lubricant margins and sales volumes of our refined petroleum products. While marketing fuel and lubricant margins are primarily driven by market factors, largely determined by the relationship between supply and demand, marketing fuel margins, in particular, are influenced by trends in spot prices, and where applicable, retail prices for refined petroleum products in the regions and countries where we operate.
RESULTS OF OPERATIONS
Our business segment and consolidated results reflect the consolidation of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills, in connection with the DCP Midstream Merger, from August 18, 2022, forward. See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, in the Notes to Consolidated Financial Statements, for additional information regarding the DCP Midstream Merger.
Consolidated Results
A summary of income before income taxes by business segment with a reconciliation to net income attributable to Phillips 66 follows:
Millions of Dollars
Year Ended December 31
2023 2022 2021
Midstream $ 2,774 4,734 1,500
Chemicals 600 856 1,844
Refining 5,266 7,816 (2,353)
Marketing and Specialties 2,135 2,402 1,723
Corporate and Other (1,306) (1,169) (974)
Income before income taxes 9,469 14,639 1,740
Income tax expense 2,230 3,248 146
Net income 7,239 11,391 1,594
Less: net income attributable to noncontrolling interests 224 367 277
Net income attributable to Phillips 66 $ 7,015 11,024 1,317
2023 vs. 2022
Net income attributable to Phillips 66 for the year ended December 31, 2023, was $7,015 million, compared with $11,024 million for the year ended December 31, 2022. The decrease in 2023 was primarily due to the recognition of an aggregate before-tax gain of $3,013 million in 2022 in our Midstream segment in connection with the DCP Midstream Merger and a decline in realized refining margins, partially offset by a decrease in income tax expense and lower unrealized investment losses related to our investment in NOVONIX Limited (NOVONIX).
2022 vs. 2021
Net income attributable to Phillips 66 for the year ended December 31, 2022, was $11,024 million, compared with $1,317 million for the year ended December 31, 2021. The improvement was primarily due to higher realized refining margins, an aggregate before-tax gain of $3,013 million recognized in our Midstream segment in connection with the DCP Midstream Merger, lower impairments in the Refining segment, and improved international marketing fuel margins. These improvements were partially offset by an increase in income tax expense, lower equity earnings from CPChem, and an unrealized decrease in the fair value of our investment in NOVONIX.
See the “Segment Results” section for additional information on our segment results and Note 23-Income Taxes, in the Notes to Consolidated Financial Statements, for additional information on income taxes. See also Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, in the Notes to Consolidated Financial Statements, for additional information regarding the DCP Midstream Merger.
Statement of Income Analysis
2023 vs. 2022
Sales and other operating revenues and purchased crude oil and products decreased 13% and 15%, respectively, in 2023. These decreases were mainly due to lower prices for refined petroleum products, crude oil and NGL.
Equity in earnings of affiliates decreased 32% in 2023, resulting from lower equity earnings from DCP Midstream, DCP Sand Hills, DCP Southern Hills and Gray Oak Pipeline due to the DCP Midstream Merger in August 2022, as well as decreased equity earnings from WRB Refining LP (WRB) and CPChem primarily due to lower margins, partially offset by lower operating costs. See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, in the Notes to Consolidated Financial Statements, and the Chemicals segment analysis in the “Segment Results” section for additional information.
Net gain on dispositions increased $108 million in 2023, primarily due to a before-tax gain recognized in the Midstream segment in the third quarter of 2023 associated with the sale of our 25% ownership interest in the South Texas Gateway Terminal.
Other income decreased $2,378 million in 2023, primarily due to an aggregate before-tax gain of $3,013 million recognized in our Midstream segment in connection with the DCP Midstream Merger in August 2022. The decrease was partially offset by lower unrealized investment losses on our investment in NOVONIX in 2023 compared to 2022, and higher interest income. See Note 4-Business Combinations, and Note 18-Fair Value Measurements, in the Notes to Consolidated Financial Statements, for additional information on the aggregate before-tax gain. See Note 8-Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for additional information regarding our investment in NOVONIX.
Selling, general and administrative expenses increased 16% in 2023, mainly driven by the consolidation of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills starting in August 2022 and higher costs associated with our business transformation. These increases were partially offset by lower selling expenses due to decreased refined petroleum product prices. See Note 31-Restructuring, in the Notes to Consolidated Financial Statements, for additional information regarding restructuring costs.
Depreciation and amortization increased 21% in 2023, primarily due to additional depreciation and amortization related to assets acquired as a result of consolidating DCP Midstream Class A Segment, DCP Southern Hills and DCP Sand Hills starting in August 2022.
Taxes other than income taxes increased 33% in 2023, primarily due to consolidating DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills starting in August 2022 and an increase in environmental taxes.
Interest and debt expense increased 45% in 2023, primarily driven by higher interest expense as a result of consolidating DCP Midstream Class A Segment, new debt issuances in 2023 related to the DCP LP Merger, and a $53 million before-tax loss on the early redemption of DCP LP’s 5.850% junior subordinated notes.
Income tax expense decreased 31% in 2023, primarily due to lower income before income taxes. See Note 23-Income Taxes, in the Notes to Consolidated Financial Statements, for more information regarding our income taxes.
Net income attributable to noncontrolling interests decreased 39% in 2023. The decrease reflects the impacts of the DCP LP Merger in June 2023, and the consolidation of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills and the derecognition of a noncontrolling interest related to Gray Oak Holdings as a result of the DCP Midstream Merger in August 2022. The decrease also reflects the impact of the merger between us and Phillips 66 Partners in March 2022. See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, and Note 30-Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on the DCP Midstream Merger and the Phillips 66 Partners merger, respectively.
2022 vs. 2021
Sales and other operating revenues and purchased crude oil and products increased 52% and 47%, respectively, in 2022. These increases were mainly due to higher prices for refined petroleum products, crude oil and NGL.
Other income increased $2,283 million in 2022, primarily due to an aggregate before-tax gain of $3,013 million recognized in our Midstream segment in connection with the DCP Midstream Merger. The impact of this gain was partially offset by an unrealized investment loss on our investment in NOVONIX, compared with an unrealized gain in 2021. See Note 4-Business Combinations, and Note 18-Fair Value Measurements, in the Notes to Consolidated Financial Statements, for additional information on the aggregate before-tax gain. See Note 8-Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for additional information regarding our investment in NOVONIX.
Operating expenses increased 19% in 2022, mainly attributable to higher utility costs driven by increased natural gas and power prices and higher turnaround and other maintenance expenses.
Selling, general and administrative expenses increased 24% in 2022, primarily driven by higher employee-related expenses, restructuring costs related to our business transformation and increased selling expenses driven by rising refined petroleum product prices.
Impairments decreased 96% in 2022, primarily due to a before-tax impairment of $1,298 million recorded in the third quarter of 2021 associated with our Alliance Refinery. See Note 11-Impairments, in the Notes to Consolidated Financial Statements, for additional information.
Taxes other than income taxes increased 29% in 2022, primarily due to tax credits received from renewable diesel blending activity at our San Francisco Refinery in the third quarter of 2021, as well as higher property and other taxes.
Income tax expense increased $3,102 million in 2022 primarily due to improved results. See Note 23-Income Taxes, in the Notes to Consolidated Financial Statements, for more information regarding our income taxes.
Net income attributable to noncontrolling interests increased 32% in 2022. The increase was primarily driven by the consolidation of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills as part of the DCP Midstream Merger in August 2022, which resulted in us reflecting the additional noncontrolling interests owned by the public common and preferred unitholders of DCP LP, as well as Enbridge’s noncontrolling interest in DCP Midstream Class A Segment, on our consolidated statement of income. The increase was partially offset by a decrease due to the merger between us and Phillips 66 Partners in March 2022 that resulted in Phillips 66 Partners becoming a wholly owned subsidiary of Phillips 66. See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, and Note 30-Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on the DCP Midstream Merger and the Phillips 66 Partners merger, respectively.
Segment Results
Midstream
Year Ended December 31
2023 2022 2021
Millions of Dollars
Income (Loss) Before Income Taxes
Transportation $ 1,310 1,176 678
NGL and Other 1,503 4,000 452
NOVONIX (39) (442) 370
Total Midstream $ 2,774 4,734 1,500
Thousands of Barrels Daily
Transportation Volumes
Pipelines* 3,069 3,089 3,271
Terminals 3,246 2,981 2,790
Operating Statistics
NGL fractionated** 711 529 410
NGL production*** 437 423 394
Wellhead Volume (Bcf/D)*** 4.6 4.4 4.2
* Pipelines represent the sum of volumes transported through each separately tariffed consolidated pipeline segment, excluding NGL pipelines.
** Includes 100% of DCP Midstream Class A Segment’s volumes from August 18, 2022, forward.
*** Includes 100% of DCP Midstream Class A Segment’s volumes.
Dollars Per Gallon
Market Indicator
Weighted-Average NGL Price* $ 0.67 1.00 0.83
* 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; NGL production, transportation, storage, fractionation, processing and marketing services; natural gas gathering, compressing, treating, processing, storage, transportation and marketing services; and condensate recovery. These activities are mainly in the United States. This segment also includes our investment in NOVONIX.
In connection with the DCP Midstream Merger, the results of our Transportation business reflect a decrease in our indirect economic interest in Gray Oak Pipeline to 6.5% from August 18, 2022, forward. Prior to August 18, 2022, the Transportation results presented in the table above reflect Gray Oak Holdings’ 65% economic interest in Gray Oak Pipeline. In addition, the results of our NGL and Other business include the consolidated results of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills from August 18, 2022, forward. Prior to August 18, 2022, our investments in DCP Midstream, DCP Sand Hills and DCP Southern Hills were accounted for using the equity method and equity earnings from these investments are included in the results of our NGL and Other business.
In the Notes to Consolidated Financial Statements, see Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, for additional information regarding the DCP Midstream Merger.
2023 vs. 2022
Results from our Midstream segment decreased $1,960 million in 2023, compared with 2022.
Results from our Transportation business increased $134 million in 2023, compared with 2022. The increase in 2023 was primarily due to higher volumes and tariffs, as well as decreased operating costs, partially offset by lower before-tax gains on sales and transfers of interests in equity affiliates. In August 2023, we recognized a $101 million before-tax gain on the sale of our 25% ownership interest in the South Texas Gateway Terminal, while in August 2022, we recognized a before-tax gain of $182 million related to the transfer of an indirect economic interest in Gray Oak Pipeline as part of the DCP Midstream Merger.
Results from our NGL and Other business decreased $2,497 million in 2023, compared with 2022. The decrease was primarily due to an aggregate before-tax gain of $2,831 million recognized in the third quarter of 2022 from remeasuring our previously held equity investments in DCP Midstream, DCP Sand Hills and DCP Southern Hills to their fair values in connection with the DCP Midstream Merger. The decrease was partially offset by the consolidation of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills from August 18, 2022, forward, as well as increased fractionation volumes at the Sweeny Hub reflecting the startup of Frac 4 in October 2022.
The fair value of our investment in NOVONIX declined by $39 million in 2023, compared with a decline of $442 million in 2022.
In the Notes to Consolidated Financial Statements, see Note 8-Investments, Loans and Long-Term Receivables, for additional information on our investment in NOVONIX and the before-tax gain on the sale of our 25% ownership interest in the South Texas Gateway Terminal in August 2023. See also Note 4-Business Combinations, and Note 18-Fair Value Measurements, in the Notes to Consolidated Financial Statements, for additional information regarding the before-tax gains recorded in connection with the DCP Midstream Merger.
See the “Executive Overview and Business Environment” section for information on market factors impacting 2023 results.
2022 vs. 2021
Midstream’s results increased $3,234 million in 2022, compared with 2021.
Results from our Transportation business increased $498 million in 2022, compared with 2021. The increase was primarily due to a before-tax impairment of $198 million recorded in the first quarter of 2021 related to Phillips 66 Partners’ decision to exit the Liberty Pipeline project, a before-tax gain of $182 million from the transfer of a 35.75% indirect economic interest in Gray Oak Pipeline to our co-venturer as part of the DCP Midstream Merger, and lower depreciation and amortization expense from logistic assets that were retired in the fourth quarter of 2021 as part of the planned conversion of the Alliance Refinery to a terminal.
Results from our NGL and Other business increased $3,548 million in 2022, compared with 2021. The increase was primarily due to before-tax gains totaling $2,831 million recognized from remeasuring our previously held equity investments in DCP Midstream, DCP Sand Hills and DCP Southern Hills to their fair values in connection with the DCP Midstream Merger. Additionally, the increased results reflect the consolidation of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills from August 18, 2022, forward, as well as improved Sweeny Hub results.
In 2022, the fair value of our investment in NOVONIX decreased by $442 million compared with an increase of $370 million in 2021. We acquired this investment in September 2021.
See Note 11-Impairments, and Note 8-Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for additional information on impairments and our investment in NOVONIX, respectively. See Note 4-Business Combinations, and Note 18-Fair Value Measurements, in the Notes to Consolidated Financial Statements, for additional information regarding the before-tax gains recorded in connection with the DCP Midstream Merger.
Chemicals
Year Ended December 31
2023 2022 2021
Millions of Dollars
Income Before Income Taxes $ 600 856 1,844
Millions of Pounds
CPChem Externally Marketed Sales Volumes* 23,798 23,749 24,067
* 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) 96 % 91 95
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. CPChem 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. CPChem manufactures and markets aromatics and styrenics products, such as benzene, cyclohexane, styrene and polystyrene, as well as manufactures and/or markets a variety of specialty chemical products. Unless otherwise noted, amounts referenced below reflect our net 50% interest in CPChem.
2023 vs. 2022
Results from the Chemicals segment decreased $256 million in 2023, compared with 2022. The decrease was primarily due to lower margins driven by decreased sales prices, partially offset by lower utility costs due to a decline in natural gas prices.
See the “Executive Overview and Business Environment” section for information on market factors impacting CPChem’s 2023 results.
2022 vs. 2021
Results from the Chemicals segment decreased $988 million in 2022, compared with 2021. The decrease was primarily due to lower margins driven by decreased sales prices, higher feedstock and utility costs, as well as decreased results from CPChem’s equity affiliates.
Refining
Year Ended December 31
2023 2022 2021
Millions of Dollars
Income (Loss) Before Income Taxes
Atlantic Basin/Europe $ 910 2,402 1
Gulf Coast 1,640 2,091 (1,759)
Central Corridor 2,210 2,415 72
West Coast 506 908 (667)
Worldwide $ 5,266 7,816 (2,353)
Dollars Per Barrel
Income (Loss) Before Income Taxes
Atlantic Basin/Europe $ 4.99 12.05 0.01
Gulf Coast 7.95 10.29 (7.30)
Central Corridor 21.50 24.64 0.75
West Coast 4.20 7.86 (5.90)
Worldwide 8.61 12.69 (3.69)
Realized Refining Margins*
Atlantic Basin/Europe $ 13.30 20.30 7.48
Gulf Coast 15.17 18.25 5.65
Central Corridor 22.67 24.96 9.65
West Coast 19.07 24.31 7.70
Worldwide 17.32 21.55 7.42
* 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
2023 2022 2021
Operating Statistics
Refining operations*
Atlantic Basin/Europe
Crude oil capacity 537 537 537
Crude oil processed 479 524 479
Capacity utilization (percent) 89 % 98 89
Refinery production 502 549 522
Gulf Coast**
Crude oil capacity 529 529 720
Crude oil processed 511 488 592
Capacity utilization (percent) 97 % 92 82
Refinery production 574 565 662
Central Corridor
Crude oil capacity 531 531 531
Crude oil processed 477 469 461
Capacity utilization (percent) 90 % 88 87
Refinery production 497 487 476
West Coast***
Crude oil capacity 313 364 364
Crude oil processed 299 290 284
Capacity utilization (percent) 95 % 80 78
Refinery production 329 315 308
Worldwide
Crude oil capacity 1,910 1,961 2,152
Crude oil processed 1,766 1,771 1,816
Capacity utilization (percent) 92 % 90 84
Refinery production 1,902 1,916 1,968
* Includes our share of equity affiliates.
** Excludes operating statistics of the Alliance Refinery beginning on October 1, 2021.
*** Reflects reduced capacity of our San Francisco refinery from the shutdown of the Santa Maria facility in February 2023 and the shutdown of one of the Rodeo facility’s crude units in October 2023 in connection with converting this refinery into a renewable fuels facility.
Our Refining segment refines crude oil and other feedstocks into petroleum products, such as gasoline, distillates and aviation fuels, as well as renewable fuels. This segment includes 12 refineries in the United States and Europe. In the fourth quarter of 2021, we shut down our Alliance Refinery and converted it into a terminal.
2023 vs. 2022
Results from the Refining segment decreased $2,550 million in 2023, compared with 2022. The decrease was primarily due to lower realized margins, partially offset by lower utility costs. The decrease in realized margins was primarily driven by a decline in market crack spreads, partially offset by increased feedstock advantage and improved crude optimization benefits.
Our worldwide refining crude oil capacity utilization rate was 92% and 90% in 2023 and 2022, respectively. See the “Executive Overview and Business Environment” section for information on industry crack spreads and other market factors impacting this year’s results.
2022 vs. 2021
Results from the Refining segment increased $10,169 million in 2022, compared with 2021. The improved results were primarily due to higher realized refining margins driven by improved market crack spreads, partially offset by higher operating costs. In addition, 2021 included a before-tax impairment of $1,288 million associated with our Alliance Refinery. See Note 11-Impairments, in the Notes to Consolidated Financial Statements, for additional information regarding this impairment.
Our worldwide refining crude oil capacity utilization rate was 90% and 84% in 2022 and 2021, respectively. The increase in 2022 was primarily driven by improved demand for refined petroleum products due to supply constraints caused by the conflict between Russia and Ukraine and easing of restrictions from the COVID-19 pandemic.
Marketing and Specialties
Year Ended December 31
2023 2022 2021
Millions of Dollars
Income Before Income Taxes $ 2,135 2,402 1,723
Dollars Per Barrel
Income Before Income Taxes
U.S. $ 1.97 1.95 1.74
International 4.87 7.44 4.13
Realized Marketing Fuel Margins*
U.S. $ 2.45 2.34 2.19
International 6.00 8.29 5.96
* 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 $ 2.93 3.30 2.46
Distillates 3.23 3.86 2.36
* On third-party branded refined petroleum product sales, excluding excise taxes.
Thousands of Barrels Daily
Marketing Refined Petroleum Product Sales
Gasoline 1,218 1,167 1,154
Distillates 957 962 959
Other 18 18 17
2,193 2,147 2,130
The M&S segment purchases for resale and markets refined petroleum products, such as gasoline, distillates and aviation fuels, as well as renewable fuels, mainly in the United States and Europe. In addition, this segment includes the manufacturing and marketing of base oils and lubricants.
2023 vs. 2022
Before-tax income from the M&S segment decreased $267 million in 2023, compared with 2022. The decrease in 2023 was primarily driven by lower international realized marketing fuel margins and decreased equity earnings from affiliates, partially offset by higher U.S. realized marketing fuel margins.
See the “Executive Overview and Business Environment” section for information on marketing fuel margins and other market factors impacting 2023 results.
2022 vs. 2021
Before-tax income from the M&S segment increased $679 million in 2022, compared with 2021. The increase in 2022 was primarily driven by improved realized international marketing fuel margins and higher results from our specialty lubricants and other businesses.
Corporate and Other
Millions of Dollars
Year Ended December 31
2023 2022 2021
Loss Before Income Taxes
Net interest expense $ (628) (537) (583)
Corporate overhead and other (678) (632) (391)
Total Corporate and Other $ (1,306) (1,169) (974)
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, restructuring costs related to our business transformation, foreign currency transaction gains and losses, and other costs not directly associated with an operating segment.
2023 vs. 2022
Net interest expense increased $91 million in 2023, compared with 2022, primarily driven by higher interest expense as a result of consolidating DCP Midstream Class A Segment, new debt issuances in 2023 related to the DCP LP Merger and a $53 million before-tax loss on the early redemption of DCP LP’s 5.850% junior subordinated notes. The increase in interest expense in 2023 was partially offset by increased interest income. See Note 14-Debt, in the Notes to Consolidated Financial Statements, for additional information regarding debt.
Corporate overhead and other increased $46 million in 2023, compared with 2022, primarily due to higher costs related to our business transformation. See Note 31-Restructuring, in the Notes to Consolidated Financial Statements, for additional information regarding restructuring costs.
2022 vs. 2021
Net interest expense decreased $46 million in 2022, compared with 2021, primarily driven by increased interest income, partially offset by increased interest expense as a result of consolidating DCP Midstream Class A Segment from August 18, 2022, forward. See Note 14-Debt, in the Notes to Consolidated Financial Statements, for additional information regarding debt.
Corporate overhead and other increased $241 million in 2022, compared with 2021. The increase was primarily due to restructuring costs associated with our business transformation for consulting fees, severance and an impairment related to assets held for sale, as well as higher employee related expenses. See Note 28-Segment Disclosures and Related Information, and Note 31-Restructuring, in the Notes to Consolidated Financial Statements, for additional information regarding restructuring costs.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars, Except as Indicated
2023 2022 2021
Cash and cash equivalents $ 3,323 6,133 3,147
Net cash provided by operating activities 7,029 10,813 6,017
Short-term debt 1,482 529 1,489
Total debt 19,359 17,190 14,448
Total equity 31,650 34,106 21,637
Percent of total debt to capital* 38 % 34 40
Percent of floating-rate debt to total debt 10 % - 3
* 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 2023, we generated $7 billion in cash from operations and received proceeds from debt offerings, net of debt repayments, of $2 billion. We used available cash primarily to repurchase noncontrolling interests in DCP LP for $4.1 billion, repurchase shares of our common stock for $4 billion, fund capital expenditures and investments of $2.4 billion, and pay dividends on our common stock of $1.9 billion. During 2023, cash and cash equivalents decreased $2.8 billion to $3.3 billion.
Significant Sources of Capital
Operating Activities
During 2023, cash generated by operating activities was $7 billion, a $3.8 billion decrease compared with 2022. The decrease was primarily due to lower realized refining margins, working capital impacts, reduced operating distributions from equity affiliates, completion of long-term crude oil exchanges and higher contributions to our pension plans.
During 2022, cash generated by operating activities was $10.8 billion, a $4.8 billion increase compared with 2021. The increase was primarily due to higher earnings resulting from improved realized refining margins, partially offset by working capital impacts and lower operating distributions from equity affiliates.
Our short- and long-term operating cash flows are highly dependent upon refining and marketing margins, NGL prices and chemicals margins. Prices and margins in our industry are typically volatile, and are driven by market conditions over which we have little or no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.
The level and quality of output from our refineries also impacts our cash flows. Factors such as operating efficiency, maintenance turnarounds, market conditions, feedstock availability, and weather conditions can affect output. We actively manage the operations of our refineries, and any variability in their operations typically has not been as significant to cash flows as that caused by margins and prices. Our worldwide refining crude oil capacity utilization was 92%, 90% and 84% in 2023, 2022 and 2021, respectively. Our worldwide refining clean product yield was 85%, 84% and 83% in 2023, 2022 and 2021, respectively.
Equity Affiliate Operating Distributions
Our operating cash flows are also impacted by distribution decisions made by our equity affiliates, including CPChem. Over the three years ended December 31, 2023, our operating cash flows included aggregate distributions from our equity affiliates of $5.6 billion, including $2.2 billion from CPChem. We cannot control the amount of future dividends from equity affiliates; therefore, future dividend payments by these equity affiliates are not assured.
Tax Refunds
We received a U.S. federal income tax refund of $1.1 billion in the second quarter of 2021.
Asset Dispositions
On August 1, 2023, we sold our 25% ownership interest in the South Texas Gateway Terminal for approximately $275 million.
On February 28, 2023, we closed on the sale of the Belle Chasse Terminal for approximately $76 million.
Debt Issuances
On March 29, 2023, Phillips 66 Company, a wholly owned subsidiary of Phillips 66, issued $1.25 billion aggregate principal amount of senior unsecured notes consisting of:
•$750 million aggregate principal amount of 4.950% Senior Notes due December 2027 (2027 Notes).
•$500 million aggregate principal amount of 5.300% Senior Notes due June 2033 (2033 Notes).
The 2027 Notes and 2033 Notes (collectively, the Notes) are fully and unconditionally guaranteed by Phillips 66. Interest on the 2027 Notes is payable semi-annually on June 1 and December 1 of each year and commenced on December 1, 2023. Interest on the 2033 Notes is payable semi-annually on June 30 and December 30 of each year and commenced on December 30, 2023.
Term Loan Agreement
On March 27, 2023, Phillips 66 Company, a wholly owned subsidiary of Phillips 66, entered into a $1.5 billion delayed draw term loan agreement guaranteed by Phillips 66 (the Term Loan Agreement). The Term Loan Agreement provides for a single borrowing during a 90-day period commencing on the closing date, which borrowing was contingent upon the completion of the DCP LP Merger. The Term Loan Agreement contains customary covenants similar to those contained in our revolving credit agreement, including a maximum consolidated net debt-to-capitalization ratio of 65% as of the last day of each fiscal quarter. The Term Loan Agreement has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts after grace periods; and violation of covenants. We may at any time prepay outstanding borrowings under the Term Loan Agreement, in whole or in part, without premium or penalty. Outstanding borrowings under the Term Loan Agreement bear interest at either: (a) the adjusted term Secured Overnight Financing Rate (SOFR) in effect from time to time plus the applicable margin; or (b) the reference rate plus the applicable margin, as defined in the Term Loan Agreement. At December 31, 2023, $1.25 billion was borrowed under the Term Loan Agreement, which matures in June 2026. See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, in the Notes to Consolidated Financial Statements, for additional information regarding the DCP LP Merger.
Related Party Advance Term Loan Agreements
Borrowings under related party Advance Term Loan agreements with WRB increased from $25 million at December 31, 2022, to $290 million at December 31, 2023. Borrowings under these agreements are due in 2035 and 2038 and bear interest at a floating rate based on the adjusted term SOFR plus an applicable margin, payable on the last day of each month.
Credit Facilities and Commercial Paper
Phillips 66 and Phillips 66 Company
On June 23, 2022, we entered into a $5 billion revolving credit facility (the Facility) with Phillips 66 Company as the borrower and Phillips 66 as the guarantor and a scheduled maturity date of June 22, 2027. The Facility replaced our previous $5 billion revolving credit facility with Phillips 66 as the borrower and Phillips 66 Company as the guarantor. The Facility contains usual and customary covenants that are similar to the previous revolving credit facility, including a maximum consolidated net debt-to-capitalization ratio of 65% as of the last day of each fiscal quarter. We have the 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, subject to, among other things, the consent of the lenders holding the majority of the commitments and of each lender extending its commitment. Outstanding borrowings under the Facility bear interest at either (a) the adjusted term SOFR (as described in the Facility) 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 our senior unsecured long-term debt from time to time. We may at any time prepay outstanding borrowings, in whole or in part, without premium or penalty. At December 31, 2023 and 2022, 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 the Facility. Commercial paper maturities are contractually limited to 365 days. At December 31, 2023 and 2022, no borrowings were outstanding under the program.
Phillips 66 Partners
In connection with entering into the Facility, we terminated Phillips 66 Partners’ $750 million revolving credit facility.
DCP Midstream Class A Segment
DCP LP has a credit facility under its amended credit agreement (the Credit Agreement), with a borrowing capacity of up to $1.4 billion that matures on March 18, 2027. The Credit Agreement grants DCP LP the option to increase the revolving loan commitment by an aggregate principal amount of up to $500 million and to extend the term for up to two additional one-year periods, subject to requisite lender approval. Indebtedness under the Credit Agreement bears interest at either: (a) an adjusted SOFR (as described in the Credit Agreement) plus the applicable margin; or (b) the base rate (as described in the Credit Agreement) plus the applicable margin. The Credit Agreement also provides for customary fees, including commitment fees. The cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid based on DCP LP’s credit rating. At December 31, 2023, DCP LP had $25 million in borrowings outstanding under the Credit Agreement. At December 31, 2022, DCP LP had no borrowings outstanding under the Credit Agreement. At December 31, 2023, and December 31, 2022, respectively, $2 million and $10 million in letters of credit had been issued that are supported by the Credit Agreement.
DCP LP has an accounts receivable securitization facility (the Securitization Facility) that provides for up to $350 million of borrowing capacity through August 2024 at an adjusted SOFR and includes an uncommitted option to increase the total commitments under the Securitization Facility by up to an additional $400 million. Under the Securitization Facility, certain of DCP LP’s wholly owned subsidiaries sell or contribute receivables to another of DCP LP’s consolidated subsidiaries, DCP Receivables LLC, a bankruptcy-remote special purpose entity created for the sole purpose of the Securitization Facility. At December 31, 2023, and December 31, 2022, respectively, $350 million and $40 million of borrowings were outstanding under the Securitization Facility, which are secured by accounts receivable at DCP Receivables LLC.
Total Committed Capacity Available
At December 31, 2023, and 2022, we had approximately $6.4 billion and $6.7 billion, respectively, of total committed capacity available under the credit facilities described above.
Other Debt Issuances and Financings
Senior Unsecured Notes
In November 2021, Phillips 66 closed its public offering of $1 billion aggregate principal amount of 3.300% senior unsecured notes due 2052. Interest on the Senior Notes due 2052 is payable semiannually on March 15 and September 15 of each year, commencing on March 15, 2022. Proceeds received from the public offering were $982 million, net of underwriters’ discounts and commissions, as well as debt issuance costs. In December 2021, Phillips 66 used the proceeds from this offering, together with cash on hand, to repay $1 billion in aggregate principal amount of its $2 billion 4.300% Senior Notes due April 2022.
Phillips 66 Partners Term Loan
In April 2021, Phillips 66 Partners entered into a $450 million term loan agreement with a one-year term and borrowed the full amount. The term loan agreement was repaid upon maturity in April 2022 without premium or penalty.
Phillips 66 Availability of Debt Financing
We have an A3 credit rating, with a stable outlook, from Moody’s Investors Service and a BBB+ credit rating, with a stable outlook, from Standard & Poor’s. 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 by one or both rating agencies. Failure to maintain 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.
DCP LP Availability of Debt Financing
DCP LP has a BBB+ credit rating, with a stable outlook, from Standard and Poor’s and a Baa3 credit rating, with a positive outlook, from Moody’s Investors Service. These ratings facilitate DCP LP’s access to a variety of lenders. DCP LP does not have any ratings triggers on any of its corporate debt that would cause an automatic default, and thereby impact access to liquidity, in the event of a rating downgrade by one or more rating agencies.
Off-Balance Sheet Arrangements
Lease Residual Value Guarantees
Under the operating lease agreement for our headquarters facility in Houston, Texas, we have the option, at the end of the lease term in September 2025, 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, 2023. We also have residual value guarantees associated with railcar, airplane and truck leases with maximum potential future exposures totaling $168 million. These leases have remaining terms of one to ten years.
Dakota Access and Energy Transfer Crude Oil Company, LLC (ETCO)
In 2020, the trial court presiding over litigation brought by the Standing Rock Sioux Tribe (the Tribe) ordered the U.S. Army Corps of Engineers (USACE) to prepare an Environmental Impact Statement (EIS) addressing an easement under Lake Oahe in North Dakota. The trial court later vacated the easement. Although the easement is vacated, the USACE has no plans to stop pipeline operations while it proceeds with the EIS, and the Tribe’s request for a shutdown was denied in May 2021. In June 2021, the trial court dismissed the litigation entirely. Once the EIS is completed, new litigation or challenges may be filed.
In February 2022, the U.S. Supreme Court (the Court) denied Dakota Access’ writ of certiorari requesting the Court to review the trial court’s decision to order the EIS and vacate the easement. Therefore, the requirement to prepare the EIS stood. Also in February 2022, the Tribe withdrew as a cooperating agency, causing the USACE to halt the EIS process while the USACE engaged with the Tribe on their reasons for withdrawing.
The draft EIS process resumed in August 2022, and in September 2023 the USACE published its draft EIS for public comment. The USACE identified five potential outcomes, but did not indicate which one it preferred. The options comprise two “no action” alternatives where the USACE would deny an easement to Dakota Access and require it to shut down the pipeline and either remove the pipe from under Lake Oahe or allow the pipeline to be abandoned-in-place under the lake. The USACE also identified three “action” alternatives. Two of them contemplate that the USACE would reissue the easement to Dakota Access under essentially the same terms as 2017 with either the same or a larger volume of oil allowed through the pipeline while the third alternative would require decommissioning the current pipeline and construction of a new line 39 miles upstream from the current location. The USACE has not indicated when it will issue its final decision.
Dakota Access and ETCO have guaranteed repayment of senior unsecured notes issued by a wholly owned subsidiary of Dakota Access in March 2019. On April 1, 2022, Dakota Access’ wholly owned subsidiary repaid $650 million aggregate principal amount of its outstanding senior notes upon maturity. We funded our 25% share, or $163 million, with a capital contribution of $89 million in March 2022 and $74 million of distributions we elected not to receive from Dakota Access in the first quarter of 2022. At December 31, 2023, the aggregate principal amount outstanding of Dakota Access’ senior unsecured notes was $1.85 billion.
In conjunction with the notes offering, Phillips 66 Partners, now a wholly owned subsidiary of Phillips 66, and its co-venturers in Dakota Access also provided a Contingent Equity Contribution Undertaking (CECU). 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 above-mentioned ongoing litigation. At December 31, 2023, our 25% share of the maximum potential equity contributions under the CECU was approximately $467 million.
If the pipeline is required to cease operations, it may have a material adverse effect on our results of operations and cash flows. Should operations cease and Dakota Access and ETCO not have sufficient funds to pay its expenses, we also could be required to support our 25% share of the ongoing expenses, including scheduled interest payments on the notes of approximately $20 million annually, in addition to the potential obligations under the CECU at December 31, 2023.
See Note 15-Guarantees, in the Notes to Consolidated Financial Statements, for additional information regarding 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, 2023, was $19.4 billion and our total debt-to-capital ratio was 38%. See Note 14-Debt, in the Notes to Consolidated Financial Statements, for our annual debt maturities over the next five years and more information on debt repayments.
2023 Repayments
On May 19, 2023, DCP LP redeemed its 5.850% junior subordinated notes due May 2043 with an aggregate principal amount outstanding of $550 million.
On March 15, 2023, DCP LP repaid its 3.875% senior unsecured notes due March 2023 with an aggregate principal amount of $500 million.
2022 Repayments
In December 2022, Phillips 66 repaid its 3.700% senior notes due April 2023 with an aggregate principal amount of $500 million.
After our consolidation of DCP Midstream Class A Segment on August 17, 2022, DCP LP repaid $470 million of borrowings under its accounts receivable securitization and revolving credit facilities that were outstanding on the acquisition date.
In April 2022, upon maturity, Phillips 66 repaid its 4.300% senior notes with an aggregate principal amount of $1 billion and Phillips 66 Partners repaid its $450 million term loan.
Subsequent Repayment
On February 15, 2024, upon maturity, Phillips 66 repaid its 0.900% senior notes due February 2024 with an aggregate principal amount of $800 million.
Debt Exchange
On May 5, 2022, Phillips 66 Company, a wholly owned subsidiary of Phillips 66, completed offers to exchange (the Exchange Offers) all validly tendered notes of seven different series of notes issued by Phillips 66 Partners (collectively, the Old Notes), with an aggregate principal amount of approximately $3.5 billion, for notes issued by Phillips 66 Company (collectively, the New Notes). The New Notes are fully and unconditionally guaranteed by Phillips 66 and rank equally with Phillips 66 Company’s other unsecured and unsubordinated indebtedness, and the guarantees rank equally with Phillips 66’s other unsecured and unsubordinated indebtedness.
Old Notes with an aggregate principal amount of approximately $3.2 billion were tendered in the Exchange Offers. The New Notes have the same interest rates, interest payment dates and maturity dates as the Old Notes. Holders that validly tendered before the end of the early participation period on April 19, 2022 (the Early Participation Date), received New Notes with an aggregate principal amount equivalent to the Old Notes, while holders that validly tendered after the Early Participation Date, but before the Expiration Date, received New Notes with an aggregate principal amount 3% less than the Old Notes. Substantially all of the Old Notes exchanged were tendered during the Early Participation Period.
DCP Midstream Merger
On August 17, 2022, we and our co-venturer, Enbridge, agreed to merge DCP Midstream and Gray Oak Holdings with DCP Midstream as the surviving entity. As part of the DCP Midstream Merger, we made a net cash payment of $306 million.
DCP LP Merger
On June 15, 2023, we completed the acquisition of all publicly held common units of DCP LP pursuant to the terms of the Agreement and Plan of Merger, dated as of January 5, 2023 (DCP LP Merger Agreement). The DCP LP Merger Agreement was entered into with DCP LP, its subsidiaries and its general partner entities, pursuant to which one of our wholly owned subsidiaries merged with and into DCP LP, with DCP LP surviving as a Delaware limited partnership. Under the terms of the DCP LP Merger Agreement, at the effective time of the DCP LP Merger, each publicly held common unit representing a limited partner interest in DCP LP (other than the common units owned by DCP Midstream and its subsidiaries) issued and outstanding as of immediately prior to the effective time was converted into the right to receive $41.75 per common unit in cash. The DCP LP Merger increased our aggregate direct and indirect economic interest in DCP LP from 43.3% to 86.8%.
We paid approximately $3.8 billion in cash consideration, funded with a combination of available cash and proceeds from the offering of the Notes and borrowings under the Term Loan Agreement.
See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, Note 14-Debt, and Note 29-DCP Midstream Class A Segment, in the Notes to Consolidated Financial Statements, for additional information.
DCP LP Preferred Units
On October 16, 2023, DCP LP redeemed its Series C preferred units with an aggregate liquidation preference of approximately $110 million.
On June 15, 2023, DCP LP redeemed its Series B preferred units with an aggregate liquidation preference of approximately $161 million.
In December 2022, DCP LP redeemed its Series A preferred units with an aggregate liquidation preference of $500 million.
DCP LP Cash Distributions to Unitholders
DCP LP’s partnership agreement requires it to distribute all available cash within 45 days after the end of each quarter. For the year ended December 31, 2023, DCP LP made cash distributions of $125 million to common unitholders other than Phillips 66 and its subsidiaries and $15 million to preferred unitholders.
See Note 29-DCP Midstream Class A Segment, in the Notes to Consolidated Financial Statements, for additional information regarding the DCP LP public common unit acquisition and the redemptions of DCP LP’s Series B and Series C preferred units.
Merger with Phillips 66 Partners
On March 9, 2022, we completed a merger between us and Phillips 66 Partners. The merger resulted in the acquisition of all limited partnership interests in Phillips 66 Partners not already owned by us in exchange for 41.8 million shares of Phillips 66 common stock issued from treasury stock. Phillips 66 Partners common unitholders received 0.50 shares of Phillips 66 common stock for each outstanding Phillips 66 Partners common unit. Phillips 66 Partners’ perpetual convertible preferred units were converted into common units at a premium to the original issuance price prior to being exchanged for Phillips 66 common stock. Upon closing, Phillips 66 Partners became a wholly owned subsidiary of Phillips 66 and its common units are no longer publicly traded. See Note 30-Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on the merger transaction.
Dividends
On February 7, 2024, our Board of Directors declared a quarterly cash dividend of $1.05 per common share. The dividend is payable March 1, 2024, to holders of record at the close of business on February 20, 2024.
Share Repurchases
On October 25, 2023, our Board of Directors approved a $5 billion increase to our share repurchase authorization. Since the inception of our share repurchase program in 2012, our Board of Directors has authorized an aggregate of $25 billion of repurchases of our outstanding common stock, and we have repurchased 213.8 million shares at an aggregate cost of $18 billion. In 2023, we repurchased 37.8 million shares at an aggregate cost of $4 billion. Our share repurchase authorizations do not expire. 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. Shares of stock repurchased are held as treasury shares.
Employee Benefit Plan Contributions
During the year ended December 31, 2023, we contributed $391 million to our U.S. pension plans and $20 million to our international pension plans.
Marketing and Specialties Acquisition
On August 1, 2023, we acquired a marketing business on the U.S. West Coast for total consideration of $269 million. This acquisition supports the placement of renewable diesel that will be produced by the Rodeo renewable fuels facility.
Contractual Obligations
Our contractual obligations primarily consist of purchase obligations, outstanding debt principal and interest obligations, operating and finance lease obligations, and asset retirement and environmental obligations.
Purchase Obligations
Our purchase obligations represent agreements to purchase goods or services that are enforceable, legally binding and specify all significant terms. We expect these purchase obligations will be fulfilled with operating cash flows in the period when due. At December 31, 2023, our purchase obligations totaled $84.8 billion, with $40.7 billion due within one year.
The majority of our purchase obligations are market-based contracts, including exchanges and futures, for the purchase of commodities such as crude oil and NGL. The commodities are used to supply our refineries and fractionators and optimize our supply chain. At December 31, 2023, commodity purchase commitments with third parties and related parties were $44.2 billion and $23.9 billion, respectively. The remaining purchase obligations mainly represent 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, and our net share of purchase commitments for materials and services for jointly owned facilities where we are the operator.
Debt Principal and Interest Obligations
As of December 31, 2023, our aggregate principal amount of outstanding debt was $19.5 billion, with $1.5 billion due within one year. Our obligations for interest on the debt totaled $9.6 billion, with $870 million due within one year. See Note 14-Debt, in the Notes to Consolidated Financial Statements, for additional information regarding our outstanding debt principal and interest obligations.
Finance and Operating Lease Obligations
See Note 20-Leases, in the Notes to Consolidated Financial Statements, for information regarding our lease obligations and timing of our expected lease payments.
Asset Retirement and Environmental Obligations
See Note 12-Asset Retirement Obligations and Accrued Environmental Costs, in the Notes to Consolidated Financial Statements, for information regarding asset retirement and environmental obligations.
Capital Spending
Our capital expenditures and investments represent consolidated capital spending.
Millions of Dollars
Budget 2023 2022 2021
Capital Expenditures and Investments
Midstream* $ 985 625 1,043 733
Chemicals - - - -
Refining 1,066 1,339 928 784
Marketing and Specialties 112 364 89 202
Corporate and Other 68 90 134 141
Total Capital Expenditures and Investments $ 2,231 2,418 2,194 1,860
Selected Equity Affiliates**
CPChem $ 828 1,009 701 367
WRB 183 189 177 229
Total Selected Equity Affiliates $ 1,011 1,198 878 596
* Includes 100% of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills capital expenditures and investments from August 18, 2022, forward, net of acquired cash.
** Our share of joint ventures’ capital spending.
Midstream
Capital spending in our Midstream segment was $2.4 billion for the three-year period ended December 31, 2023, including:
•Expansion of gathering systems in the DJ Basin and Permian Basin for DCP LP.
•Continued development and expansion of fractionation capacity at our Sweeny Hub. We completed and started operations of Sweeny Frac 4 in the third quarter of 2022.
•Completion of construction on our C2G Pipeline, a new 16-inch ethane pipeline that connects our Clemens Caverns storage facility to petrochemical facilities in Gregory, Texas, near Corpus Christi.
•Net cash payment in connection with the DCP Midstream Merger.
•Investments in NOVONIX and a renewable feedstock processing plant.
•Contributions to Dakota Access for a pipeline optimization project, including a contribution to fund our 25% share of Dakota Access’ debt repayment.
•Spending associated with other return, reliability, and maintenance projects in our Transportation and NGL businesses.
Chemicals
During the three-year period ended December 31, 2023, CPChem had a self-funded capital program that totaled $4.2 billion on a 100% basis. Capital spending was primarily for the development of petrochemical projects on the U.S. Gulf Coast and in the Middle East, as well as sustaining, debottlenecking and optimization projects on existing assets.
Refining
Capital spending for the Refining segment during the three-year period ended December 31, 2023, was $3.1 billion, primarily for projects to enhance the yield of higher-value products, produce renewable fuels, and sustain the reliability and safety of our facilities. Key projects funded during the three-year period included:
•Installation of facilities to produce renewable fuels at our San Francisco and Humber refineries.
•Installation of facilities to improve clean product yield at the Ponca City and Sweeny refineries, as well as the jointly owned Wood River Refinery.
•Installation of facilities to improve product value at the Lake Charles Refinery.
•Installation of facilities to improve utilization and product value at the jointly owned Borger refinery.
Marketing and Specialties
Capital spending for the M&S segment during the three-year period ended December 31, 2023, was primarily for the acquisition of a marketing business and a commercial fleet fueling business on the U.S. West Coast, both of which will provide further placement opportunities for renewable diesel production to end-use customers; investment in a retail marketing joint venture in the U.S. Central region; and the continued 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, 2023, was primarily related to information technology and facilities.
2024 Budget
Our 2024 capital budget is $2.2 billion, including $923 million for sustaining capital and $1.3 billion for growth capital. Our sustaining capital budget reflects $300 million of efficiencies as a result of our business transformation efforts. Our projected $2.2 billion capital budget excludes our portion of planned capital spending by our major joint ventures CPChem and WRB totaling $1 billion.
The Midstream capital budget of $985 million comprises a growth capital budget of $593 million focused on enhancing our integrated NGL wellhead-to-market value chain, as well as $250 million related to the repayment of our 25% share of Dakota Access’ debt due in 2024. The Midstream capital budget also includes $392 million for sustaining projects, including DCP LP’s sustaining capital of $200 million. In Refining, the total capital budget of $1.1 billion consists of $412 million for sustaining capital and $654 million for growth capital. Refining’s growth capital includes completing the conversion of the San Francisco Refinery in Rodeo, California, into one of the world’s largest renewable fuels facilities. Startup of the converted facility is expected in the first quarter of 2024. Refining’s growth capital will also support high-return, low-capital projects to enhance market capture. The M&S capital budget of $112 million reflects continued enhancement of our retail network, including energy transition opportunities. The Corporate and Other capital budget of $68 million will primarily fund information technology projects.
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 uncertain.
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.
Environmental
We are subject to numerous international, federal, state and local environmental laws and regulations. Among the most significant of these international and federal environmental laws and regulations are the:
•U.S. Federal Clean Air Act, which governs air emissions.
•U.S. Federal Clean Water Act, which governs discharges into bodies of water.
•European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (EU REACH), which governs production, marketing and use of chemicals and the United Kingdom’s legislation for the Registration, Evaluation, Authorization and Restriction of Chemicals (UK REACH), which replaced EU REACH in the United Kingdom in 2021 following the United Kingdom’s exit from the European Union (BREXIT).
•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 crude 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 replaced the EU ETS in the United Kingdom in 2021, following BREXIT.
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 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 required a phased reduction of nitrogen oxide emissions through 2022, affecting refineries in the Los Angeles metropolitan area. In 2017, SCAQMD required additional nitrogen oxide emissions reductions through 2025 and, on November 5, 2021, promulgated 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 emissions 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). The law requires fuel producers and importers to provide additional renewable fuels for transportation motor fuels and stipulates a mix of various types. Renewable Identification Numbers (RINs) form the mechanism used by the EPA to record compliance with the Renewable Fuel Standard (RFS). 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 EPA’s renewable volume obligations (RVO) to date. These obligations have been met using a variety of operating and capital strategies. We are also implementing advanced and different technologies to address projected future RVOs. On June 21, 2023, the EPA finalized RVO for the 2023, 2024 and 2025 compliance years. These standards increase cellulosic volumes, which reflect the EPA’s forecast for increasing compressed natural gas (CNG) and liquified natural gas (LNG) volumes derived from biogas. In addition, the EPA increased total advanced biofuel volumes from the 5.63 billion gallons established for the 2022 compliance year to 7.33 billion gallons in 2025. We may experience a decrease in demand for refined petroleum products and increased program costs if not fully recovered in the market. This program continues to be the subject of possible Congressional review and re-promulgation in revised form, and the EPA’s final regulations establishing RVO requirements have been and continue to be subject to legal challenge, further creating uncertainty regarding RVO requirements.
We are required to purchase RINs in the open market to satisfy the portion of our obligation under the RFS that is not fulfilled by blending renewable fuels into the motor fuels we produce. For the years ended December 31, 2023, 2022 and 2021, we incurred expenses of $323 million, $478 million and $441 million, respectively, associated with our obligation to purchase RINs in the open market to comply with the RFS for our wholly owned refineries. These expenses are included in the “Purchased crude oil and products” line item on our consolidated statement of income. Our jointly owned refineries also incurred expenses associated with the purchase of RINs in the open market, of which our share was $389 million, $437 million and $351 million for the years ended December 31, 2023, 2022 and 2021, respectively. These expenses are included in the “Equity in earnings of affiliates” line item on our consolidated statement of income. The amount of these expenses and fluctuations between periods is primarily driven by the market price of RINs, refinery production, blending activities, and RVO requirements.
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 soil and groundwater and both the EPA and many states may adopt cleanup standards for per- and poly-fluoroalkyl substances (PFAS), which may have been a constituent in certain firefighting foams used or stored at or near some of our facilities.
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 is typically 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. At December 31, 2022, we reported that we had been notified of potential liability under CERCLA and comparable state laws at 22 sites within the United States. During the last quarter of 2023, our legal organization approved the removal of one site following Department of Justice dismissal of Phillips 66, thus, leaving 21 unresolved sites with potential liability at December 31, 2023.
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.
We incur costs related to the prevention, control, abatement or elimination of environmental pollution. Expensed environmental costs were $824 million in 2023 and are expected to be approximately $885 million and $863 million in 2024 and 2025, respectively. Capitalized environmental costs were $49 million in 2023 and are expected to be approximately $76 million and $216 million, in 2024 and 2025, 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 EU (BREXIT), those types of entities in the United Kingdom are now subject to the UK ETS, rather than the EU ETS.
•EU Renewable Energy Directive II, which increases the EU’s energy consumption from renewable sources in the electricity, heat, and transportation sectors to 32% by 2030.
•United Kingdom’s Renewable Transport Fuel Obligation, which is intended to reduce the GHG emissions from fuel used in the United Kingdom transportation sector by encouraging the supply of renewable fuels.
•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 states in the western U.S. have been enacted or are under consideration or development, including amendments to California's Low Carbon Fuel Standard, California’s Advanced Clean Cars and Trucks Programs, California’s Carbon Neutrality by 2045 Scoping Plan, Oregon's Low Carbon Fuel Standard and Climate Protection Plan, and Washington's carbon reduction programs.
•United States’ Inflation Reduction Act, which contains tax inducements and other provisions that incentivize investment, development, and deployment of alternative energy sources and technologies, which is intended to accelerate the energy transition.
•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 and there is agreement between the EU Member States, the European Parliament, and the EU Commission (which is pending ratification by the EU Council and European Parliament) to increase the Phase IV GHG emissions reduction to 63% by 2030 compared to 2005 levels. The United Kingdom is no longer part of the EU ETS and, instead, has been under the UK ETS since 2021. Phillips 66 has assets that are subject to the EU ETS and assets that are 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 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 efforts throughout our operations.
In February 2022, we announced a target to reduce our Scope 1 and Scope 2 GHG emissions intensity related to our operations by 50% of 2019 levels by the year 2050. The 2050 target builds upon our 2030 GHG emissions intensity targets to reduce Scope 1 and Scope 2 emissions from our operations by 30% and Scope 3 emissions from our energy products by 15% compared to 2019 levels.
In addition to the disclosures above, we have issued our 2023 Sustainability Report that is accessible on our website and provides more detailed information on our ESG initiatives, including information on environmental metrics and other topics of interest to our stakeholders, which may not be considered material for SEC reporting purposes. The information contained in the Sustainability Report is not incorporated by reference into, and does not constitute a part of, this Form 10-K.
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 addresses 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.
Business Combination
In accounting for a business combination, assets acquired, liabilities assumed and noncontrolling interests are recorded based on estimated fair values as of the date of acquisition. The excess or shortfall of the purchase price when compared to the fair value of the net tangible and identifiable intangible assets acquired, if any, is recorded as goodwill or a bargain purchase gain, respectively. A significant amount of judgment is made in estimating the individual fair value of property, plant and equipment, intangible assets, noncontrolling interests and other assets and liabilities. We use available information to make these fair value determinations and engage third-party specialists in the valuation process as necessary.
The fair values of assets acquired, liabilities assumed and noncontrolling interests as of the acquisition date are often estimated using a combination of approaches, including the income approach, which requires us to project future cash flows and apply an appropriate discount rate; the cost approach, which requires estimates of replacement costs and depreciation and obsolescence estimates; and the market approach which uses market data and adjusts for entity specific differences. The estimates used in determining fair values are based on assumptions believed to be reasonable, but which are inherently uncertain. Accordingly, actual results may differ materially from the estimated results used to determine fair value.
See Note 4-Business Combinations, and Note 18-Fair Value Measurements, in the Notes to Consolidated Financial Statements, for additional information on our acquisitions in 2023 and 2022.
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 11-Impairments, in the Notes to Consolidated Financial Statements, for information about impairments recorded in 2023, 2022 and 2021.
GUARANTOR FINANCIAL INFORMATION
We have various cross guarantees between Phillips 66 and its wholly owned subsidiary Phillips 66 Company (together, the Obligor Group) with respect to publicly held debt securities. 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. Phillips 66 has fully and unconditionally guaranteed the payment obligations of Phillips 66 Company with respect to its publicly held debt securities. In addition, Phillips 66 Company has fully and unconditionally guaranteed the payment obligations of Phillips 66 with respect to its publicly held debt securities. All guarantees are full and unconditional. At December 31, 2023, $13.3 billion of senior unsecured notes outstanding has been guaranteed by the Obligor Group.
Summarized financial information of 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, 2023, and the summarized financial position at December 31, 2023, of the Obligor Group on a combined basis were:
Summarized Combined Statement of Income Millions of Dollars
Sales and other operating revenues $ 112,050
Revenues and other income-non-guarantor subsidiaries 6,360
Purchased crude oil and products-third parties 64,991
Purchased crude oil and products-related parties 17,110
Purchased crude oil and products-non-guarantor subsidiaries 24,435
Income before income taxes 4,998
Net income 3,652
Summarized Combined Balance Sheet Millions of Dollars
Accounts and notes receivable-third parties $ 6,716
Accounts and notes receivable-related parties 1,152
Due from non-guarantor subsidiaries, current 1,827
Total current assets 14,260
Investments and long-term receivables 11,242
Net properties, plants and equipment 12,242
Goodwill 1,047
Due from non-guarantor subsidiaries, noncurrent 2,995
Other assets associated with non-guarantor subsidiaries 1,666
Total noncurrent assets 31,010
Total assets 45,270
Due to non-guarantor subsidiaries, current $ 3,153
Total current liabilities 13,162
Long-term debt 13,459
Due to non-guarantor subsidiaries, noncurrent 10,061
Total noncurrent liabilities 29,234
Total liabilities 42,396
Total equity 2,874
Total liabilities and equity 45,270
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 “Executive Overview and Business Environment-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, 2023
Income before income taxes $ 910 1,640 2,210 506 5,266
Plus:
Taxes other than income taxes
69 106 94 123 392
Depreciation, amortization and impairments
209 246 163 231 849
Selling, general and administrative expenses
38 19 76 36 169
Operating expenses
1,097 1,104 738 1,397 4,336
Equity in (earnings) losses of affiliates 8 (2) (445) - (439)
Other segment (income) expense, net 19 17 (7) 6 35
Proportional share of refining gross margins contributed by equity affiliates
89 - 1,257 - 1,346
Special items:
Certain tax impacts (15) - - - (15)
Realized refining margins
$ 2,424 3,130 4,086 2,299 11,939
Total processed inputs (thousands of barrels)
182,213 206,356 102,774 120,581 611,924
Adjusted total processed inputs (thousands of barrels)*
182,213 206,356 180,251 120,581 689,401
Income before income taxes per barrel (dollars per barrel)**
$ 4.99 7.95 21.50 4.20 8.61
Realized refining margins (dollars per barrel)***
13.30 15.17 22.67 19.07 17.32
Year Ended December 31, 2022
Income before income taxes $ 2,402 2,091 2,415 908 7,816
Plus:
Taxes other than income taxes
53 87 57 91 288
Depreciation, amortization and impairments
203 250 147 279 879
Selling, general and administrative expenses
41 19 62 31 153
Operating expenses
1,242 1,230 809 1,486 4,767
Equity in (earnings) losses of affiliates 9 7 (763) - (747)
Other segment (income) expense, net
(6) 1 2 (1) (4)
Proportional share of refining gross margins contributed by equity affiliates
93 - 1,668 - 1,761
Special items:
Regulatory compliance costs 9 26 22 13 70
Realized refining margins
$ 4,046 3,711 4,419 2,807 14,983
Total processed inputs (thousands of barrels)
199,319 203,269 97,997 115,457 616,042
Adjusted total processed inputs (thousands of barrels)*
199,319 203,269 177,112 115,457 695,157
Income before income taxes per barrel (dollars per barrel)**
$ 12.05 10.29 24.64 7.86 12.69
Realized refining margins (dollars per barrel)***
20.30 18.25 24.96 24.31 21.55
* 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.
Millions of Dollars, Except as Indicated
Realized Refining Margins Atlantic Basin/Europe Gulf Coast Central Corridor West Coast Worldwide
Year Ended December 31, 2021
Income (loss) before income taxes $ 1 (1,759) 72 (667) (2,353)
Plus:
Taxes other than income taxes
69 74 51 49 243
Depreciation, amortization and impairments
210 1,683 139 240 2,272
Selling, general and administrative expenses
32 34 30 37 133
Operating expenses
981 1,352 648 1,220 4,201
Equity in losses of affiliates 9 11 164 - 184
Other segment (income) expense, net
9 (7) (11) 4 (5)
Proportional share of refining gross margins contributed by equity affiliates
123 - 609 - 732
Special items:
Certain tax impacts (4) - - - (4)
Regulatory compliance costs (20) (28) (27) (13) (88)
Realized refining margins
$ 1,410 1,360 1,675 870 5,315
Total processed inputs (thousands of barrels)
188,697 240,859 95,595 112,994 638,145
Adjusted total processed inputs (thousands of barrels)*
188,697 240,859 173,230 112,994 715,780
Income (loss) before income taxes per barrel (dollars per barrel)**
$ 0.01 (7.30) 0.75 (5.90) (3.69)
Realized refining margins (dollars per barrel)***
7.48 5.65 9.65 7.70 7.42
* 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.
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
2023 2022 2021 2023 2022 2021
Realized Marketing Fuel Margins
Income before income taxes $ 1,378 1,329 1,180 494 765 403
Plus:
Depreciation and amortization 23 14 14 75 72 76
Selling, general and administrative expenses
814 808 758 253 251 253
Equity in earnings of affiliates
(54) (71) (48) (113) (115) (113)
Other operating (revenues) expenses* (477) (508) (424) (63) (62) 8
Other (income) expense, net 28 24 9 15 (7) 7
Marketing margins
1,712 1,596 1,489 661 904 634
Less: margin for nonfuel related sales
- - - 52 51 53
Realized marketing fuel margins
$ 1,712 1,596 1,489 609 853 581
Total fuel sales volumes (thousands of barrels)
698,961 680,930 680,102 101,466 102,862 97,529
Income before income taxes per barrel (dollars per barrel)
$ 1.97 1.95 1.74 4.87 7.44 4.13
Realized marketing fuel margins (dollars per barrel)**
2.45 2.34 2.19 6.00 8.29 5.96
* Includes other nonfuel revenues and expenses.
** 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 product, NGL, natural gas, renewable feedstock 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, NGL, renewable feedstock and natural gas 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, 2023 and 2022, 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 2023
2024 $ 1,100 1.32 % $ 350 6.38 %
2025 1,975 4.43 - -
2026 992 2.42 1,250 6.46
2027 1,250 5.22 25 6.51
2028 1,300 3.84 - -
Remaining years 10,676 4.74 290 6.46
Total $ 17,293 $ 1,915
Fair value $ 16,718 $ 1,915
Millions of Dollars, Except as Indicated
Expected Maturity Date Fixed Rate Maturity Average Interest Rate Floating Rate Maturity Average Interest Rate
Year-End 2022
2023 $ 500 3.88 % $ - - %
2024 1,100 1.32 40 5.33
2025 1,975 4.43 - -
2026 992 2.42 - -
2027 500 5.63 - -
Remaining years 12,040 4.67 25 4.72
Total $ 17,107 $ 65
Fair value $ 15,871 $ 65
\
Foreign Currency Risk
We are exposed to foreign currency exchange rate fluctuations related to our international operations. Generally, we do not hedge our foreign currency risk.
Risk Monitoring
Our Chief Executive Officer and Chief Financial Officer monitor risks to our business resulting from commodity prices, interest rates and foreign currency exchange rates.
For additional information about our use of derivative instruments, see Note 17-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 that convey the prospective nature of events or outcomes, but the absence of such words does not mean a statement is not forward-looking.
We based these 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. We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this report, as they are not guarantees of future performance and 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 forecasted in any forward-looking statement. Factors that could cause actual results to differ materially from those in our forward-looking statements include:
•Fluctuations in market conditions, including NGL, crude oil, refined petroleum product and natural gas prices and refining, marketing and petrochemical margins and demand.
•Changes in governmental policies relating to NGL, crude oil, natural gas or refined petroleum products pricing, regulation or taxation, including exports.
•Capacity constraints in, or other limitations on, the pipelines, storage and fractionation facilities to which we deliver natural gas or NGL and the availability of alternative markets and arrangements for our natural gas and NGL.
•Actions taken by OPEC and non-OPEC oil producing countries impacting supply and demand and correspondingly, commodity prices.
•Our ability to achieve the expected benefits of the DCP LP integration, including the realization of expected synergies.
•Unexpected changes in costs or technical requirements for constructing, modifying or operating our facilities or transporting our products.
•Unexpected technological or commercial difficulties in manufacturing, refining or transporting our products, including chemical products.
•Lack of, or disruptions in, adequate and reliable transportation for our NGL, crude oil, natural gas and refined petroleum products.
•The level and success of drilling and quality of production volumes around our midstream assets.
•Our ability to timely obtain or maintain permits, including those necessary for capital projects.
•Our ability to comply with government regulations or make capital expenditures required to maintain compliance.
•Our ability to realize sustained savings and cost reductions from the company’s business transformation initiatives.
•Changes to worldwide government policies relating to renewable fuels, climate change and greenhouse gas emissions that adversely affect programs like the renewable fuel standards program, low carbon fuel standards and tax credits for biofuels.
•Domestic and international economic and political developments including armed hostilities, such as the Russia-Ukraine war, instability in the financial services and banking sector, excess inflation, rising interest rates, expropriation of assets, and changes in fiscal policy.
•The impact on commercial activity and demand for refined petroleum products from any widespread public health crisis, as well as the extent and duration of recovery of economies and demand for our products following any such crisis.
•Failure to complete definitive agreements and feasibility studies for, and to complete construction of, announced and future capital projects on time and within budget.
•Our ability to successfully complete, or any material delay in the completion of, asset dispositions or acquisitions that we pursue.
•Potential disruption or interruption of our operations or those of our joint ventures due to litigation or other governmental or regulatory action.
•Damage to our facilities due to accidents, weather and climate events, civil unrest, insurrections, political events, terrorism or cyberattacks.
•Our ability to meet our sustainability goals, including reducing our GHG emissions intensity, developing and protecting new technologies, and commercializing lower-carbon opportunities.
•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 GHG emissions reductions and 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.
•Political and societal concerns about climate change that could result in changes to our business or operations or increase expenditures, including litigation-related expenses.
•Changes in estimates or projections used to assess fair value of intangible assets, goodwill, and properties, plants and equipment and/or strategic decisions or other developments 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 creditworthiness of our customers and the counterparties to our transactions, including the impact of bankruptcies.
•Cybersecurity incidents or other disruptions that compromise our information and expose us to liability.
•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 (PCAOB ID: 42)
Report of Independent Registered Public Accounting Firm (DCP Midstream, LP) (PCAOB ID: 34)
Consolidated Financial Statements of Phillips 66:
Consolidated Statement of Income for the years ended December 31, 2023, 2022 and 2021
Consolidated Statement of Comprehensive Income for the years ended December 31, 2023, 2022 and 2021
Consolidated Balance Sheet at December 31, 2023 and 2022
Consolidated Statement of Cash Flows for the years ended December 31, 2023, 2022 and 2021
Consolidated Statement of Changes in Equity for the years ended December 31, 2023, 2022 and 2021
Notes to Consolidated Financial Statements
Report of Management
Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this Annual Report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with 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, 2023. 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, 2023.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2023, and their report is included herein.
/s/ Mark E. Lashier /s/ Kevin J. Mitchell
Mark E. Lashier Kevin J. Mitchell
President and Chief Executive Officer Executive Vice President and
Chief Financial Officer
Date: February 21, 2024
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, 2023 and 2022, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, based on our audits and, for 2023 and 2022, the report of other auditors, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.
We did not audit the 2023 and 2022 financial statements of DCP Midstream, LP (DCP LP), a consolidated subsidiary, which reflect total assets constituting approximately 14% and 18% at December 31, 2023 and 2022 respectively, and total revenues constituting approximately 4% in 2023 and 3% in 2022 for the years then ended. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for DCP LP for 2023 and 2022, is based solely on the report of the other auditors.
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, 2023, 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 21, 2024 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 included 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 and the report of other auditors provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit and finance committee and that: (1) relates 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 matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impairment Assessment of Certain Equity Method Investments
Description of the Matter
As discussed in Note 1 to the consolidated financial statements, the Company assesses investments in nonconsolidated entities accounted for under the equity method for impairment when changes in the facts and circumstances indicate a loss in value has occurred.
As discussed in Note 8 to the consolidated financial statements, the Company owns a 50% interest in WRB Refining LP (WRB), a joint venture that owns the Wood River and Borger refineries. The carrying value of the Company’s investment in WRB was $2.7 billion as of December 31, 2023.
WRB’s earnings are subject to variability as they are dependent on market conditions, as well as the utilization of its refineries. Accordingly, significant judgment is required in determining whether events or changes in circumstances indicate a loss in value may have occurred that is indicative of a possible impairment.
We determined that the identification and evaluation of events or changes in circumstances indicating that the carrying value of the investment in WRB may not be recoverable is a critical audit matter because of the judgement and assumptions management uses to perform its identification and evaluation of such factors.
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 process for identifying and evaluating events or changes in circumstances that would indicate that the carrying value of the investment in WRB may not be recoverable and performed a walkthrough of the Company’s process and controls.
Our evaluation of the Company’s analysis included an assessment of whether events or changes in circumstances indicating that the carrying value of the investment in WRB may not be recoverable were appropriately identified and evaluated by the Company. This included, but was not limited to, an evaluation of the investee’s earnings history and an evaluation of the sustainability of the investee’s earnings under current and expected market conditions. We exercised professional judgment based on our knowledge of the industry and the investee’s business to assess the appropriateness of management’s evaluation and conclusions. For example, we performed inquiries of management, considered WRB’s historical operating results, reviewed the projected investment recovery period, and assessed current and expected market conditions affecting WRB’s results. We performed an independent assessment using both internally and externally available information, such as utilization and margins for WRB’s and other regional refineries, as well as forecasted prices, market crack spreads and demand. We also considered other information, such as the Company’s internal valuations, to identify evidence contrary to management’s conclusion. Additionally, we evaluated management’s process to accurately forecast future operating income by comparing actual results to budgeted results.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2011.
Houston, Texas
February 21, 2024
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, 2023, 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, 2023, based on the COSO criteria.
We did not examine the effectiveness of internal control over financial reporting of DCP Midstream, LP whose financial statements reflect total assets and sales constituting 14% and 4%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023. The effectiveness of DCP Midstream, LP’s internal control over financial reporting was audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the effectiveness of DCP Midstream, LP’s internal control over financial reporting, is based solely on the report of the other auditors.
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, 2023 and 2022, the related consolidated statements of income, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and our report dated February 21, 2024, expressed an unqualified opinion thereon, based on our audit and the report of the other auditors.
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 21, 2024
Report of Independent Registered Public Accounting Firm
To the Board of Directors of DCP Midstream GP, LLC and the Unitholders of DCP Midstream, LP
Opinion on the Financial Statements
We have audited the consolidated balance sheets of DCP Midstream, LP and subsidiaries (the "Partnership") as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows, for each of the two years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”) (not presented herein). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
We did not audit the financial statements of Gulf Coast Express Pipeline, LLC, the Partnership’s investment which is accounted for by use of the equity method. The consolidated financial statements of the Partnership include its equity investment in Gulf Coast Express Pipeline, LLC of $385 million and $408 million as of December 31, 2023 and 2022, and its equity earnings in Gulf Coast Express Pipeline, LLC of $68 million and $67 million for the years ended December 31, 2023 and 2022, respectively. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulf Coast Express Pipeline, LLC is based solely on the report of the other auditors.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB) and in accordance with auditing standards generally accepted in the United States of America, the Partnership’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2024, expressed an unqualified opinion on the Partnership’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’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 Partnership 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 and in accordance with auditing standards generally accepted in the United States of America. 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 included 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 and the report of the other auditors provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to those charged with governance and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Property, Plant and Equipment, Net - Determination of Impairment Indicators and Recoverability Analysis for Asset Grouping in the South Region - Refer to Notes 2, 9 and 12 to the financial statements
Critical Audit Matter Description
The Partnership evaluates on a quarterly basis whether the carrying value of long-lived assets should be impaired when circumstances indicate the carrying value of such long-lived assets may not be recoverable. Management considers various factors when determining if long-lived assets should be evaluated for impairment including a significant adverse change in the legal or business climate, a current period operating or cash flow loss combined with a history of losses, an accumulation of costs significantly in excess of the amount originally expected, a significant adverse change in the extent or manner in which an asset is used, a significant adverse change in the market value of an asset, or a current expectation that the asset will be sold or otherwise disposed of before the end of its useful life.
The Partnership’s determination of whether impairment indicators exist for long lived assets requires management to apply significant judgments and assumptions. When events or circumstances exist that indicate the carrying value of long-lived assets may not be recoverable, the Partnership evaluates its long-lived assets for impairment by comparing the carrying amount of the applicable asset group to the sum of the undiscounted cash flows expected to result from the use of the asset (“recoverability analysis”) using the income approach and selecting a discount rate reflective of the risk inherent in future cash flows, and applying that discount rate to the cash flow projections. If management determines the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. This analysis resulted in management determining that an impairment triggering event had occurred at a certain asset group in the South region of the Gathering and Processing segment. The triggering event is a reflection of the diminished probability of new well connects and margin degradation, commodity prices in the recently prepared budget forecasts, and a negative outlook for long-term production volume forecasts. Management prepared a recoverability analysis and recognized a $209 million impairment loss for the year ended December 31, 2023.
We considered the identification of impairment indicators for property, plant and equipment and the associated recoverability analysis as a critical audit matter because of the significant assumptions that management makes when determining whether events or changes in circumstances have occurred or could occur indicating that the carrying amounts of property, plant and equipment may not be recoverable as well as the significant judgements and assumptions made in the undiscounted cash flow analysis used to evaluate recoverability. This required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists, when performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to selection of the discount rate, the terminal value multiple, forecasted future gathering and processing volumes and future commodity pricing.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the identification of impairment indicators for long-lived assets included the following, among others:
•We tested the effectiveness of internal controls over financial reporting related to management’s identification of possible impairment indicators for long-lived assets that may indicate the carrying amount of long-lived assets may not be recoverable.
•We tested the effectiveness of controls over estimates of future volumes of raw natural gas, or other applicable throughput.
•We evaluated management’s analysis of impairment indicators by:
-Considering industry and analysts reports and the impact of macroeconomic factors, such as adverse changes in the regulatory environment, legislation, significant weather events or other factors that may represent impairment indicators not previously contemplated in management's analysis
-Evaluating management’s forecasts by comparing such forecasts to recent results of operations
-Inquiry of management over whether long-lived assets may be sold or otherwise disposed of significantly before the end of the assets' previously estimated useful life
-Inspecting minutes of the board of directors and committees of executive management to understand if there were factors that would represent potential impairment indicators for long-lived assets
Our further audit procedures on the recoverability analysis included evaluating Management’s significant inputs, including forecasted gathering and processing volumes, future commodity prices, the terminal value multiple, and the selection of the discount rate applied to estimated future cash flows included in Management’s cash flow model, included the following, among others:
•We tested the effectiveness of internal controls over financial reporting related to management’s preparation and review of significant underlying assumptions used in the undiscounted cash flow model
•For asset groups for which a recoverability analysis was performed, we evaluated management’s estimates for significant inputs by:
-Evaluating the reasonableness of volumetric assumptions by comparing forecasts to permits and rig count data including researching industry trends
-Performing a sensitivity analysis to evaluate the change in undiscounted cash flows that would result from changes in significant underlying assumptions
-Performing a lookback analysis by comparing historical results to management’s future assumptions to assess the reasonableness of estimates
-Evaluating the reasonableness of management’s future commodity pricing forecasts by comparing to independent analysts’ estimates
•With the assistance of our Internal fair value specialists, we evaluated the reasonableness of the discount rate and terminal value multiple by:
-Evaluating the appropriateness of the mathematical model used to develop the discount rate
-Evaluating the guideline public companies selected by management and used in the selection of the discount rate considering the comparability of operations to those of the Partnership
-Developing a range of independent estimates of the discount rate by independently obtaining information to estimate components of the discount rate, including the cost of debt capital, the cost of equity capital, and debt-to-equity ratio
-Evaluating the terminal value multiple in comparison to recent valuation metrics for companies of similar operations
/s/ Deloitte & Touche LLP
Denver, Colorado
February 21, 2024
We have served as the Partnership’s auditor since 2004.
Report of Independent Registered Public Accounting Firm
To the Board of Directors of DCP Midstream GP, LLC and the Unitholders of DCP Midstream, LP
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of DCP Midstream, LP and subsidiaries (the "Partnership") as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB) and in accordance with auditing standards generally accepted in the United States of America, the consolidated financial statements as of and for the year ended December 31, 2023, of the Partnership (not presented herein) and our report dated February 21, 2024, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Partnership'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 in Management’s Annual Report on Internal Control Over Financial Reporting (not presented herein). Our responsibility is to express an opinion on the Partnership'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 Partnership 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 and in accordance with auditing standards generally accepted in the United States of America. 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/ Deloitte & Touche LLP
Denver, Colorado
February 21, 2024
Consolidated Statement of Income Phillips 66
Millions of Dollars
Years Ended December 31 2023 2022 2021
Revenues and Other Income
Sales and other operating revenues $ 147,399 169,990 111,476
Equity in earnings of affiliates 2,017 2,968 2,904
Net gain on dispositions 115 7 18
Other income 359 2,737 454
Total Revenues and Other Income 149,890 175,702 114,852
Costs and Expenses
Purchased crude oil and products 128,086 149,932 102,102
Operating expenses 6,154 6,111 5,147
Selling, general and administrative expenses 2,525 2,168 1,744
Depreciation and amortization 1,977 1,629 1,605
Impairments 24 60 1,498
Taxes other than income taxes 707 530 410
Accretion on discounted liabilities 29 23 24
Interest and debt expense 897 619 581
Foreign currency transaction (gains) losses 22 (9) 1
Total Costs and Expenses 140,421 161,063 113,112
Income before income taxes 9,469 14,639 1,740
Income tax expense 2,230 3,248 146
Net Income 7,239 11,391 1,594
Less: net income attributable to noncontrolling interests 224 367 277
Net Income Attributable to Phillips 66 $ 7,015 11,024 1,317
Net Income Attributable to Phillips 66 Per Share of Common Stock (dollars)
Basic $ 15.56 23.36 2.97
Diluted 15.48 23.27 2.97
Weighted-Average Common Shares Outstanding (thousands)
Basic 450,136 471,497 440,028
Diluted 453,210 473,731 440,364
See Notes to Consolidated Financial Statements.
Consolidated Statement of Comprehensive Income Phillips 66
Millions of Dollars
Years Ended December 31 2023 2022 2021
Net Income $ 7,239 11,391 1,594
Other comprehensive income (loss)
Defined benefit plans
Net actuarial gain (loss) arising during the period (11) 191 320
Amortization of net actuarial loss, prior service credit and settlements 19 90 122
Plans sponsored by equity affiliates (8) 80 96
Income taxes on defined benefit plans 2 (85) (127)
Defined benefit plans, net of income taxes 2 276 411
Foreign currency translation adjustments 182 (295) (74)
Income taxes on foreign currency translation adjustments (3) 4 4
Foreign currency translation adjustments, net of income taxes 179 (291) (70)
Cash flow hedges (3) - 3
Income taxes on hedging activities - - -
Hedging activities, net of income taxes (3) - 3
Other Comprehensive Income (Loss), Net of Income Taxes 178 (15) 344
Comprehensive Income 7,417 11,376 1,938
Less: comprehensive income attributable to noncontrolling interests 224 367 277
Comprehensive Income Attributable to Phillips 66 $ 7,193 11,009 1,661
See Notes to Consolidated Financial Statements.
Consolidated Balance Sheet Phillips 66
Millions of Dollars
At December 31 2023 2022
Assets
Cash and cash equivalents $ 3,323 6,133
Accounts and notes receivable (net of allowances of $71 million in 2023 and
$67 million in 2022)
10,483 9,497
Accounts and notes receivable-related parties 1,247 1,488
Inventories 3,750 3,276
Prepaid expenses and other current assets 1,138 1,528
Total Current Assets 19,941 21,922
Investments and long-term receivables 15,302 14,950
Net properties, plants and equipment 35,712 35,163
Goodwill 1,550 1,486
Intangibles 920 831
Other assets 2,076 2,090
Total Assets $ 75,501 76,442
Liabilities
Accounts payable $ 10,332 10,748
Accounts payable-related parties 569 575
Short-term debt 1,482 529
Accrued income and other taxes 1,200 1,397
Employee benefit obligations 863 764
Other accruals 1,410 1,876
Total Current Liabilities 15,856 15,889
Long-term debt 17,877 16,661
Asset retirement obligations and accrued environmental costs 864 879
Deferred income taxes 7,424 6,671
Employee benefit obligations 630 937
Other liabilities and deferred credits 1,200 1,299
Total Liabilities 43,851 42,336
Equity
Common stock (2,500,000,000 shares authorized at $0.01 par value)
Issued (2023-654,842,101 shares; 2022-652,373,645 shares)
Par value 7 7
Capital in excess of par 19,650 19,791
Treasury stock (at cost: 2023-224,377,439 shares; 2022-186,529,667 shares)
(19,342) (15,276)
Retained earnings 30,550 25,432
Accumulated other comprehensive loss (282) (460)
Total Stockholders’ Equity 30,583 29,494
Noncontrolling interests 1,067 4,612
Total Equity 31,650 34,106
Total Liabilities and Equity $ 75,501 76,442
See Notes to Consolidated Financial Statements.
Consolidated Statement of Cash Flows Phillips 66
Millions of Dollars
Years Ended December 31 2023 2022 2021
Cash Flows From Operating Activities
Net income $ 7,239 11,391 1,594
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization 1,977 1,629 1,605
Impairments 24 60 1,498
Accretion on discounted liabilities 29 23 24
Deferred income taxes 840 1,320 (272)
Undistributed equity earnings (822) (1,308) (128)
Loss on early redemption of debt 53 - -
Net gain on dispositions (115) (7) (7)
Gain related to merger of businesses - (3,013) -
Unrealized investment (gain) loss 38 433 (365)
Other (419) 217 (51)
Working capital adjustments
Accounts and notes receivable (696) (2,073) (922)
Inventories (245) 74 511
Prepaid expenses and other current assets 269 (249) (339)
Accounts payable (480) 1,736 2,925
Taxes and other accruals (663) 580 (56)
Net Cash Provided by Operating Activities 7,029 10,813 6,017
Cash Flows From Investing Activities
Capital expenditures and investments (2,418) (2,194) (1,860)
Return of investments in equity affiliates 201 125 267
Proceeds from asset dispositions 392 4 27
Advances/loans-related parties - (75) (310)
Collection of advances/loans-related parties 3 662 2
Other 32 (10) 2
Net Cash Used in Investing Activities (1,790) (1,488) (1,872)
Cash Flows From Financing Activities
Issuance of debt 6,260 453 1,443
Repayment of debt (4,252) (2,883) (2,954)
Issuance of common stock 123 103 26
Repurchase of common stock (4,014) (1,513) -
Dividends paid on common stock (1,882) (1,793) (1,585)
Distributions to noncontrolling interests (163) (185) (324)
Repurchase of noncontrolling interests (4,067) (500) (24)
Other (97) (70) (52)
Net Cash Used in Financing Activities (8,092) (6,388) (3,470)
Effect of Exchange Rate Changes on Cash and Cash Equivalents 43 49 (42)
Net Change in Cash and Cash Equivalents (2,810) 2,986 633
Cash and cash equivalents at beginning of year 6,133 3,147 2,514
Cash and Cash Equivalents at End of Year $ 3,323 6,133 3,147
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, 2020 $ 6 20,383 (17,116) 16,500 (789) 2,539 21,523
Net income - - - 1,317 - 277 1,594
Other comprehensive income - - - - 344 - 344
Dividends paid on common stock - - - (1,585) - - (1,585)
Distributions to noncontrolling interests - - - - - (324) (324)
Repurchase of noncontrolling interests - - - (2) - (21) (23)
Benefit plan activity 1 121 - (14) - - 108
December 31, 2021 7 20,504 (17,116) 16,216 (445) 2,471 21,637
Net income - - - 11,024 - 367 11,391
Other comprehensive loss - - - - (15) - (15)
Dividends paid on common stock - - - (1,793) - - (1,793)
Repurchase of common stock - - (1,540) - - - (1,540)
Distributions to noncontrolling interests - - - - - (185) (185)
Acquisition of noncontrolling interest in Phillips 66 Partners LP - (901) 3,380 - - (2,163) 316
Merger of DCP Midstream, LLC and Gray Oak Holdings LLC - - - - - 4,622 4,622
Acquisition of noncontrolling interest in DCP Midstream, LP - - - - - (500) (500)
Benefit plan activity - 188 - (15) - - 173
December 31, 2022 7 19,791 (15,276) 25,432 (460) 4,612 34,106
Net income - - - 7,015 - 224 7,239
Other comprehensive income - - - - 178 - 178
Dividends paid on common stock - - - (1,882) - - (1,882)
Repurchase of common stock - - (4,066) - - - (4,066)
Distributions to noncontrolling interests - - - - - (163) (163)
Acquisition of noncontrolling interest in DCP Midstream, LP - (361) - - - (3,613) (3,974)
Benefit plan activity and other - 220 - (15) - 7 212
December 31, 2023 $ 7 19,650 (19,342) 30,550 (282) 1,067 31,650
Shares
Common Stock Issued Treasury Stock
December 31, 2020 648,643,223 211,771,827
Shares issued-share-based compensation 1,383,095 -
December 31, 2021 650,026,318 211,771,827
Repurchase of common stock - 16,583,076
Shares issued-share-based compensation 2,347,327 -
Shares issued-acquisition of noncontrolling
interest in Phillips 66 Partners LP
- (41,825,236)
December 31, 2022 652,373,645 186,529,667
Repurchase of common stock - 37,847,772
Shares issued-share-based compensation 2,468,456 -
December 31, 2023 654,842,101 224,377,439
Dollars
Years Ended December 31 Dividends Paid Per
Share of Common Stock
2021 $ 3.62
2022 3.83
2023 $ 4.20
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 29-DCP Midstream Class A Segment for further discussion about a significant VIE that we began consolidating in August 2022, and Note 30-Phillips 66 Partners LP, for further discussion regarding our merger with Phillips 66 Partners LP (Phillips 66 Partners).
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 8-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
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 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, except those designated as normal purchases and normal sales, are recorded on the balance sheet at fair value. We have master netting agreements with most of 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. When applicable, we also net collateral payables and receivables against derivative assets and derivative liabilities, respectively.
Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. All realized and unrealized gains and losses from derivative instruments for which we do not apply hedge accounting are immediately recognized in our consolidated statement of income. Unrealized gains or losses from derivative instruments that qualify for and are designated as cash flow hedges are recognized in other comprehensive income (loss) and appear on the balance sheet in accumulated other comprehensive income (loss) until the hedged transactions are recognized in earnings. However, to the extent the change in the fair value of a derivative instrument exceeds the change in the anticipated cash flows of the hedged transaction, the excess gain or loss is recognized immediately in earnings.
Loans and Long-Term Receivables
We enter into agreements with other parties to pursue business opportunities, which may require us to provide loans or advances to certain affiliated and 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 income in the period in which the impairment determination is made. Individual assets are grouped for impairment testing 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 for 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 income. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.
Goodwill
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination. 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 impairment 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 our 2023 testing date: Transportation and Marketing and Specialties (M&S).
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
When we have a legal obligation to incur costs to retire an asset, we record a liability in the period in which the obligation was incurred provided that a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made at the time the obligation arises, we record the liability when sufficient information is available to estimate its fair value. When a liability is initially recorded, we capitalize the costs by increasing the carrying amount of the related PP&E. Over time, the liability is increased for changes 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 liability and PP&E.
Our practice is to keep our refining and other processing assets in good operating condition through routine repair and maintenance of component parts in the ordinary course of business and by continuing to make improvements based on technological advances. As a result, we believe that generally these assets have no expected retirement dates for purposes of estimating asset retirement obligations since the dates or ranges of dates upon which we would retire these assets cannot be reasonably estimated at this time. We will recognize liabilities for these obligations in the period when sufficient information becomes available to estimate a date or range of potential retirement dates.
Environmental Costs
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 income 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 related transaction costs. Amounts are recorded as reductions of stockholders’ equity on the consolidated balance sheet. Common stock reissued from treasury stock is valued based on the average cost of historical repurchases.
Revenue Recognition
Our revenues are primarily associated with sales of refined petroleum products, crude oil, natural gas liquids (NGL) and natural gas. 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 income (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 income. Other sales and value-added taxes are recorded net in the “Taxes other than income taxes” line item on our consolidated statement of income.
Shipping and Handling Costs
We have elected to account for shipping and handling costs as fulfillment activities and include these activities in the “Purchased crude oil and products” line item on our consolidated statement of income. Freight costs billed to customers are recorded in “Sales and other operating revenues.”
Maintenance and Repairs
Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Major refinery maintenance turnarounds are expensed as incurred.
Share-Based Compensation
We recognize share-based compensation expense over the shorter of: (1) the service period (i.e., the stated period of time required to earn the award); or (2) the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than ten months for shared-based payment awards granted in 2023 and not less than six months for share-based payment awards granted prior to 2023 as those are the minimum periods of time required for awards 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. Income tax effects are released from accumulated other comprehensive loss to retained earnings, when applicable, on an individual item basis as those items are reclassified into income. 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 income.
Note 2-Changes in Accounting Principles
Effective January 1, 2023, we adopted ASU 2022-04, “Liabilities-Supplier Finance Programs (Subtopic 405-50): Disclosure of Supplier Finance Program Obligations.” This ASU requires the buyer in a supplier finance program to disclose qualitative and quantitative information about the program. At the time of adoption, this ASU did not have a material impact on our consolidated financial statements.
Effective January 1, 2022, we early adopted ASU 2021-08, “Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers.” This pronouncement requires application of ASC 606 “Revenue from Contracts with Customers” (“Topic 606”) to recognize and measure contract assets and contract liabilities from contracts with customers acquired in a business combination. The adoption of this pronouncement did not have a material impact on our consolidated financial statements.
Effective October 1, 2021, we adopted ASU No. 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” and ASU 2021-01, “Reference Rate Reform (Topic 848): Scope.” These pronouncements provide temporary optional expedients and exceptions to the current guidance on contracts, hedge relationships, and other transactions that reference the London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of reference rate reform. Amendments in ASU 2021-01 further clarify that certain optional expedients and exceptions in Topic 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition. These pronouncements were effective upon issuance and applicable to contract modifications through December 31, 2022. On December 21, 2022, the FASB issued ASU 2022-06, “Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848.” The ASU defers the sunset date of Topic 848 from December 31, 2022, to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848. This pronouncement was also effective upon issuance. The adoption of these pronouncements did not impact our consolidated financial statements.
Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers
DCP Midstream, LLC and Gray Oak Holdings LLC Merger (DCP Midstream Merger)
On August 17, 2022, we and our co-venturer, Enbridge Inc. (Enbridge), agreed to merge DCP Midstream, LLC (DCP Midstream) and Gray Oak Holdings LLC (Gray Oak Holdings), with DCP Midstream as the surviving entity.
Prior to the DCP Midstream Merger, we and Enbridge each held a 50% interest and jointly governed DCP Midstream, whose primary assets are its general partner and limited partner interests in DCP Midstream, LP (DCP LP), and we each held indirect economic interests in DCP LP of 28.26%. DCP LP is a VIE because its limited partners do not have the ability to remove its general partner with a simple majority vote, nor do its limited partners have substantive participating rights in the significant decisions made in the ordinary course of business. DCP Midstream ultimately consolidates DCP LP because one of its wholly owned subsidiaries is the primary beneficiary of DCP LP.
We and Enbridge also held 65% and 35% interests, respectively, in Gray Oak Holdings, whose primary asset was a 65% noncontrolling interest in Gray Oak Pipeline, LLC (Gray Oak Pipeline). Our and Enbridge’s indirect economic interests in Gray Oak Pipeline were 42.25% and 22.75%, respectively. We had voting control over and consolidated Gray Oak Holdings and reported Gray Oak Holdings’ 65% interest in Gray Oak Pipeline as an equity investment and Enbridge’s interest in Gray Oak Holdings as a noncontrolling interest.
In connection with the DCP Midstream Merger, we and Enbridge entered into a Third Amended and Restated Limited Liability Company Agreement of DCP Midstream (Amended and Restated LLC Agreement), which realigned the members’ economic interests and governance responsibilities. Under the Amended and Restated LLC Agreement, two classes of membership interests in DCP Midstream were created, Class A and Class B, that are intended to track the assets, liabilities, revenues and expenses of the following operating segments of DCP Midstream:
•Class A Segment comprised of the businesses, activities, assets and liabilities of DCP LP and its subsidiaries and its general partner entities (DCP Midstream Class A Segment).
•Class B Segment comprised of the business, activities, assets and liabilities of Gray Oak Pipeline (DCP Midstream Class B Segment).
We hold a 76.64% Class A membership interest, which represents an indirect economic interest in DCP LP of 43.3%, and a 10% Class B membership interest, which represents an indirect economic interest in Gray Oak Pipeline of 6.5%. Enbridge holds the remaining Class A and Class B membership interests. We have been designated as the managing member of DCP Midstream Class A Segment and are responsible for conducting, directing and managing all activities associated with this segment, except as limited in certain instances. Enbridge has been designated as the managing member of DCP Midstream Class B Segment. Earnings and distributions from each segment are allocated to the members based on their membership interest in each membership class, except as otherwise provided.
DCP Midstream Class A Segment and DCP Midstream Class B Segment were determined to be silos under the variable interest consolidation model. As a result, DCP Midstream was also determined to be a VIE. We determined that we are the primary beneficiary of DCP Midstream Class A Segment because of the governance rights granted to us under the Amended and Restated LLC Agreement as managing member of the segment.
We hold a 33.33% direct ownership interest in DCP Sand Hills Pipeline, LLC (DCP Sand Hills) and DCP Southern Hills Pipeline, LLC (DCP Southern Hills). DCP LP holds the remaining 66.67% ownership interest in these entities. As a result of the governance rights granted to us over DCP Midstream Class A Segment and the governance rights we hold through our direct ownership interests, we obtained controlling financial interests in these entities in connection with the DCP Midstream Merger. As a result of the DCP Midstream Merger, our aggregate direct and indirect economic interests in DCP Sand Hills and DCP Southern Hills increased from 52.2% to 62.2%.
Starting on August 18, 2022, we began consolidating the financial results of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills and reporting the direct and indirect economic interests held by others in these entities as noncontrolling interests on our financial statements.
We account for our remaining indirect economic interest in Gray Oak Pipeline, now held through DCP Midstream Class B Segment, using the equity method of accounting. As a result of the DCP Midstream Merger, we derecognized Enbridge’s noncontrolling interest in Gray Oak Holdings.
We accounted for our consolidation of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills as a business combination using the acquisition method of accounting. See Note 4-Business Combinations, for additional information regarding our accounting for this transaction. See Note 29-DCP Midstream Class A Segment, for additional information regarding our variable interest in DCP Midstream Class A Segment.
DCP Midstream, LP Merger (DCP LP Merger)
On June 15, 2023, we completed the acquisition of all publicly held common units of DCP LP pursuant to the terms of the Agreement and Plan of Merger, dated as of January 5, 2023 (DCP LP Merger Agreement). The DCP LP Merger Agreement was entered into with DCP LP, its subsidiaries and its general partner entities, pursuant to which one of our wholly owned subsidiaries merged with and into DCP LP, with DCP LP surviving as a Delaware limited partnership. Under the terms of the DCP LP Merger Agreement, at the effective time of the DCP LP Merger, each publicly held common unit representing a limited partner interest in DCP LP (other than the common units owned by DCP Midstream and its subsidiaries) issued and outstanding as of immediately prior to the effective time was converted into the right to receive $41.75 per common unit in cash. We accounted for the DCP LP Merger as an equity transaction. The DCP LP Merger increased our aggregate direct and indirect economic interest in DCP LP from 43.3% to 86.8% and our aggregate direct and indirect economic interests in DCP Sand Hills and DCP Southern Hills increased from 62.2% to 91.2%.
See Note 29-DCP Midstream Class A Segment, for additional information regarding the equity transaction.
Note 4-Business Combinations
Marketing and Specialties Acquisition
On August 1, 2023, our M&S segment acquired a marketing business on the U.S. West Coast for total consideration of $269 million. These operations were acquired to support the placement of renewable diesel that will be produced by our Rodeo renewable fuels facility. At December 31, 2023, we provisionally recorded $146 million of amortizable intangible assets, primarily customer relationships; $82 million of PP&E, including finance lease right of use assets; $40 million of net working capital; $64 million of goodwill; and $63 million of finance lease liabilities for this acquisition. The fair values of the assets acquired and liabilities assumed are preliminary and subject to change until we finalize our accounting for this acquisition.
DCP Midstream Merger
On August 17, 2022, we realigned our economic interest in, and governance rights over, DCP Midstream and Gray Oak Holdings through the DCP Midstream Merger, with DCP Midstream as the surviving entity. As part of the DCP Midstream Merger, we transferred a 35.75% indirect economic interest in Gray Oak Pipeline and contributed $404 million of cash to DCP Midstream, which was then paid to Enbridge, in return for a 15.05% incremental indirect economic ownership interest in DCP LP. As noted above, the additional governance rights we were granted as part of this transaction resulted in us consolidating DCP Midstream Class A Segment, as well as DCP Sand Hills and DCP Southern Hills. Given the nature of this transaction, we have accounted for the consolidation of these entities using the acquisition method of accounting.
The components of the fair value of the DCP Midstream Merger consideration are:
Millions of Dollars
Cash contributed $ 404
Fair value of transferred equity interest 634
Fair value of previously held equity interests 3,853
Total merger consideration $ 4,891
The aggregate purchase consideration noted above was allocated to the assets acquired and liabilities assumed of the entities consolidated based upon their estimated fair values as of the DCP Midstream Merger on August 17, 2022. We finalized the valuation of the assets acquired and liabilities assumed during the three months ended September 30, 2023, prior to the end of the one-year measurement period on August 16, 2023.
The following table shows the purchase price allocation as of the date of the DCP Midstream Merger, and cumulative adjustments we made during the measurement period:
Millions of Dollars
Fair value of assets acquired: As Originally Reported Adjustments As Adjusted
Cash and cash equivalents $ 98 - 98
Accounts and notes receivable 1,003 - 1,003
Inventories 74 238 312
Prepaid expenses and other current assets 439 13 452
Investments and long-term receivables 2,192 (125) 2,067
Properties, plants and equipment 12,837 193 13,030
Intangibles 36 (36) -
Other assets 343 (158) 185
Total assets acquired 17,022 125 17,147
Fair value of liabilities assumed:
Accounts payable 912 3 915
Short-term debt 625 (2) 623
Accrued income and other taxes 107 13 120
Employee benefit obligation-current 50 22 72
Other accruals 497 (6) 491
Long-term debt 4,541 40 4,581
Asset retirement obligations and accrued environmental costs 168 16 184
Deferred income taxes 40 14 54
Employee benefit obligations 54 - 54
Other liabilities and deferred credits 227 36 263
Total liabilities assumed 7,221 136 7,357
Fair value of net assets 9,801 (11) 9,790
Less: Fair value of noncontrolling interests 4,910 (11) 4,899
Total merger consideration $ 4,891 - 4,891
The adjustments reflected in the table above include reclassification adjustments we made to the purchase price allocation to conform with our historical presentation and adjustments we made to the estimated fair value of certain assets acquired and liabilities assumed during the measurement period. The adjustments to our purchase price allocation recorded during the measurement period were not material. See Note 18-Fair Value Measurements, for additional information on the determination of the fair value of the DCP Midstream Merger.
In connection with the DCP Midstream Merger, we recognized before-tax gains totaling $2,831 million from remeasuring our previously held equity investments in DCP Midstream, DCP Sand Hills and DCP Southern Hills to their fair values and a before tax gain of $182 million related to the transfer of a 35.75% indirect economic interest in Gray Oak Pipeline to our co-venturer. These before-tax gains are included in the “Other income” line item in our consolidated statement of income for the year ended December 31, 2022, and are reported in the Midstream segment. See Note 18-Fair Value Measurements, for additional information on the determination of the fair value of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills.
The following “Sales and other operating revenues” and “Net Income Attributable to Phillips 66” of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills were included in our consolidated statement of income from August 18, 2022, forward, for the year ended December 31, 2022.
Millions of Dollars
Sales and other operating revenues $ 4,531
Net Income Attributable to Phillips 66 216
Unaudited Pro Forma Financial Information
The following unaudited pro forma financial information presents consolidated results for the years ending December 31, 2022, and 2021, as if the DCP Midstream Merger occurred on January 1, 2021. The unaudited pro forma information includes adjustments based on available information, and we believe the estimates and assumptions used are reasonable, and that the significant effects of the transactions are properly reflected in the unaudited pro forma information. An aggregate before-tax gain of $2,831 million was included in the pro forma financial information for the year ended December 31, 2021, which is related to the remeasurement of the previously held equity investments in DCP Midstream, DCP Sand Hills and DCP Southern Hills to their fair values in connection with the DCP Midstream Merger. Adjustments related to the economic interest change in our equity investment in Gray Oak Pipeline were excluded from the pro forma financial information.
The unaudited pro forma financial information presented is for comparative purposes only and does not give effect to any potential synergies that could be achieved and is not necessarily indicative of the results of future operations.
Year Ended December 31
2022 2021
Sales and other operating revenues (millions)
$ 177,127 119,027
Net Income Attributable to Phillips 66 (millions)
8,847 3,360
Net Income Attributable to Phillips 66 per share-basic (dollars)
18.74 7.61
Net Income Attributable to Phillips 66 per share-diluted (dollars)
18.68 7.60
Note 5-Sales and Other Operating Revenues
Disaggregated Revenues
The following tables present our disaggregated sales and other operating revenues:
Millions of Dollars
2023 2022 2021
Product Line and Services
Refined petroleum products $ 108,644 131,798 89,020
Crude oil resales 20,824 20,574 12,801
NGL and natural gas 14,467 16,174 9,074
Services and other* 3,464 1,444 581
Consolidated sales and other operating revenues $ 147,399 169,990 111,476
Geographic Location**
United States $ 118,786 136,995 87,973
United Kingdom 14,642 16,741 11,132
Germany 5,547 6,392 4,290
Other countries 8,424 9,862 8,081
Consolidated sales and other operating revenues $ 147,399 169,990 111,476
* Includes derivatives-related activities. See Note 17-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, 2023 and 2022, receivables from contracts with customers were $9,638 million and $8,749 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, 2023 and 2022, our asset balances related to such payments were $537 million and $505 million, respectively.
Our contract liabilities primarily represent advances from our customers prior to product or service delivery. At December 31, 2023 and 2022, contract liabilities were $187 million and $156 million, respectively.
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. At December 31, 2023, the remaining performance obligations related to these minimum volume commitment contracts amounted to $365 million. This amount excludes variable consideration and estimates of variable rate escalation clauses in our contracts with customers, and is expected to be recognized through 2031 with a weighted average remaining life of two years as of December 31, 2023.
Note 6-Credit Losses
We are exposed to credit losses primarily through our sales of refined petroleum products, crude oil, NGL and natural gas. 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. In addition, when events and circumstances arise that may affect certain counterparties’ abilities to fulfill their obligations, we enhance our credit monitoring, and we may seek collateral to support some transactions or require prepayments from higher-risk counterparties.
At December 31, 2023 and 2022, we reported $11,730 million and $10,985 million of accounts and notes receivable, net of allowances of $71 million and $67 million, respectively. Based on an aging analysis at December 31, 2023, more than 95% 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 15-Guarantees, and Note 16-Contingencies and Commitments, for more information on these off-balance sheet exposures.
Note 7-Inventories
Inventories at December 31 consisted of the following:
Millions of Dollars
2023 2022
Crude oil and petroleum products $ 3,330 2,914
Materials and supplies 420 362
$ 3,750 3,276
Inventories valued on the LIFO basis totaled $3,050 million and $2,635 million at December 31, 2023 and 2022, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $5.3 billion and $6.3 billion at December 31, 2023 and 2022, respectively.
During each of the three years ended December 31, 2023, certain volume reductions in inventory caused liquidations of LIFO inventory values. For the years ended December 31, 2023 and 2022, LIFO inventory liquidations increased net income by $94 million and $75 million, respectively. For the year ended December 31, 2021, LIFO inventory liquidations decreased net income by $101 million.
Note 8-Investments, Loans and Long-Term Receivables
Components of investments and long-term receivables at December 31 were:
Millions of Dollars
2023 2022
Equity investments $ 14,728 14,414
Other investments 195 207
Loans and long-term receivables 379 329
$ 15,302 14,950
Equity Investments
Significant affiliated companies accounted for under the equity method, including nonconsolidated VIEs, at December 31, 2023 and 2022, 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, 2023 and 2022, the book value of our investment in CPChem was $7,341 million and $6,785 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, 2023, the aggregate remaining basis difference for this investment was $1,400 million. Equity earnings for the years ended December 31, 2023, 2022 and 2021, were increased by $198 million, $184 million and $186 million, respectively, due to the amortization of our aggregate basis difference. At December 31, 2023 and 2022, the book value of our investment in WRB was $2,736 million and $2,411 million, respectively.
•Gulf Coast Express LLC (Gulf Coast Express)-DCP LP 25 percent-owned joint venture that owns an intrastate pipeline that transports natural gas from the Waha area in West Texas to Agua Dulce, in Nueces County, Texas. The pipeline is operated by a co-venturer. This investment was acquired as part of our consolidation of DCP Midstream Class A Segment starting on August 18, 2022, and was recorded at fair value. We have a basis difference for our investment in Gulf Coast Express because the carrying value of our investment is higher than our share of Gulf Coast Express net assets. The basis difference is the result of recognizing the investment at fair value. The basis difference is being amortized and recognized as a decrease to equity earnings over a period of 20 years, which was the estimated remaining useful life of the joint venture’s PP&E at the acquisition date. At December 31, 2023, the aggregate remaining basis difference for this investment was $415 million. Equity earnings for each of the years ended December 31, 2023 and 2022, were decreased by $22 million and $7 million, respectively, due to the amortization of our basis difference. At December 31, 2023 and 2022, the book value of our investment in Gulf Coast Express was $800 million and $844 million, respectively. See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, Note 4-Business Combinations and Note 18-Fair Value Measurements, for additional information on the DCP Midstream Merger and our accounting for this transaction as a business combination.
•Dakota Access, LLC (Dakota Access) and Energy Transfer Crude Oil Company, LLC (ETCO)-Two 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 that extends from Patoka to Nederland, Texas. These two pipeline systems collectively form the Bakken Pipeline system, which is operated by a co-venturer.
In 2020, the trial court presiding over litigation brought by the Standing Rock Sioux Tribe (the Tribe) ordered the U.S. Army Corps of Engineers (USACE) to prepare an Environmental Impact Statement (EIS) addressing an easement under Lake Oahe in North Dakota. The trial court later vacated the easement. Although the easement is vacated, the USACE has no plans to stop pipeline operations while it proceeds with the EIS, and the Tribe’s request for a shutdown was denied in May 2021. In June 2021, the trial court dismissed the litigation entirely. Once the EIS is completed, new litigation or challenges may be filed.
In February 2022, the U.S. Supreme Court (the Court) denied Dakota Access’ writ of certiorari requesting the Court to review the trial court’s decision to order the EIS and vacate the easement. Therefore, the requirement to prepare the EIS stood. Also in February 2022, the Tribe withdrew as a cooperating agency, causing the USACE to halt the EIS process while the USACE engaged with the Tribe on their reasons for withdrawing.
The draft EIS process resumed in August 2022, and in September 2023 the USACE published its draft EIS for public comment. The USACE identified five potential outcomes, but did not indicate which one it preferred. The options comprise two “no action” alternatives where the USACE would deny an easement to Dakota Access and require it to shut down the pipeline and either remove the pipe from under Lake Oahe, or allow the pipeline to be abandoned-in-place under the lake. The USACE also identified three “action” alternatives; two of them contemplate that the USACE would reissue the easement to Dakota Access under essentially the same terms as 2017 with either the same or a larger volume of oil allowed through the pipeline, while the third alternative would require decommissioning the current pipeline and construction of a new line 39 miles upstream from the current location. The USACE has not indicated when it will issue its final decision.
Dakota Access and ETCO have guaranteed repayment of senior unsecured notes issued by a wholly owned subsidiary of Dakota Access in March 2019. On April 1, 2022, Dakota Access’ wholly owned subsidiary repaid $650 million aggregate principal amount of its outstanding senior notes upon maturity. We funded our 25% share, or $163 million, with a capital contribution of $89 million in March 2022 and $74 million of distributions we elected not to receive from Dakota Access in the first quarter of 2022. At December 31, 2023, the aggregate principal amount outstanding of Dakota Access’ senior unsecured notes was $1.85 billion.
In conjunction with the notes offering, Phillips 66 Partners, now a wholly owned subsidiary of Phillips 66, and its co-venturers in Dakota Access also provided a Contingent Equity Contribution Undertaking (CECU). 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 above-mentioned ongoing litigation. At December 31, 2023, our 25% share of the maximum potential equity contributions under the CECU was approximately $467 million.
If the pipeline is required to cease operations, it may have a material adverse effect on our results of operations and cash flows. Should operations cease and Dakota Access and ETCO not have sufficient funds to pay its expenses, we also could be required to support our 25% share of the ongoing expenses, including scheduled interest payments on the notes of approximately $20 million annually, in addition to the potential obligations under the CECU at December 31, 2023.
At December 31, 2023 and 2022, the aggregate book value of our investments in Dakota Access and ETCO was $640 million and $675 million, respectively.
•Front Range Pipeline LLC (Front Range)-DCP LP 33 percent-owned joint venture that owns an NGL pipeline that originates in the DJ Basin and extends to Skellytown, Texas. The pipeline is operated by a co-venturer. This investment was acquired as part of our consolidation of DCP Midstream Class A Segment starting on August 18, 2022, and was recorded at fair value. We have a basis difference for our investment in Front Range because the carrying value of our investment is higher than our share of Front Range net assets. The basis difference is the result of recognizing the investment at fair value. The basis difference is being amortized and recognized as a decrease to equity earnings over a period of 20 years, which was the estimated remaining useful life of the joint venture’s PP&E at the acquisition date. At December 31, 2023, the aggregate remaining basis difference for this investment was $292 million. Equity earnings for each of the years ended December 31, 2023 and 2022, were decreased by $16 million and $5 million, respectively, due to the amortization of our basis difference. At December 31, 2023 and 2022, the book value of our investment in Front Range was $477 million and $499 million, respectively. See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, Note 4-Business Combinations and Note 18-Fair Value Measurements, for additional information on the DCP Midstream Merger and our accounting for this transaction as a business combination.
•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. 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, 2023, the remaining basis difference for this investment was $261 million. Equity earnings for each of the years ended December 31, 2023, 2022 and 2021, were increased by $19 million due to the amortization of our basis difference. At December 31, 2023 and 2022, the book value of our investment in REX was $451 million and $483 million, respectively.
•CF United LLC (CF United)-A retail marketing joint venture with operations primarily on the U.S. West Coast. We own a 50% voting interest and a 48% economic interest in this joint venture. At December 31, 2023, CF United was considered a VIE because our co-venturer had an option to require us to purchase its interest based on a fixed multiple. The put option became effective July 1, 2023, and was scheduled to expire on March 31, 2024. The put option was 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 determined that we were not the primary beneficiary of CF United because we and our co-venturer jointly directed the activities that most significantly impacted economic performance.
At December 31, 2023, our maximum exposure to loss was comprised of our $291 million investment in CF United. At December 31, 2022, the book value of our investment in CF United was $296 million.
Effective January 1, 2024, in connection with an acquisition by CF United of another joint venture in which we have an ownership interest, the governing agreement for the CF United joint venture was amended and restated. The amended and restated agreement included removal of the put option that required us to purchase our co-venturer’s interest based on a fixed multiple. Accordingly, CF United ceased to be a VIE effective January 1, 2024.
•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, 2023, our maximum exposure to loss was $231 million, which represented the book value of our investment in OnCue of $166 million and guaranteed debt obligations of $65 million. At December 31, 2022, the book value of our investment in OnCue was $138 million.
•DCP Midstream, DCP Sand Hills, DCP Southern Hills, and Gray Oak Pipeline-Prior to the DCP Midstream Merger on August 17, 2022, we held:
◦A 50% interest in DCP Midstream a joint venture that owns and operates NGL and gas pipelines, gas plants, gathering systems, storage facilities and fractionation plants, through its subsidiary DCP LP.
◦A 33.33% direct ownership interest in DCP Sand Hills a joint venture that owns a 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.
◦A 33.33% direct ownership interest in DCP Southern Hills a joint venture that owns a NGL pipeline system that extends from the Midcontinent region to the Mont Belvieu, Texas, market hub.
◦A 65% interest in Gray Oak Pipeline, which was held through a consolidated holding company, Gray Oak Holdings. Our indirect interest in Gray Oak Pipeline was 42.25%, after considering a co-venturer’s 35% interest in Gray Oak Holdings. Gray Oak Pipeline is a crude oil pipeline that extends from the Permian and Eagle Ford to Texas Gulf Coast destinations that include Corpus Christi, Texas, and the Sweeny area, including our Sweeny Refinery.
As a result of the DCP Midstream Merger, effective August 18, 2022, we began consolidating the financial results of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills and our indirect economic interest in Gray Oak Pipeline was reduced to 6.5%. After the DCP Midstream Merger, our indirect economic interest in Gray Oak Pipeline is held through our economic interest in DCP Midstream Class B Segment. See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, and Note 4-Business Combinations, for additional information regarding the DCP Midstream Merger and associated accounting treatment.
At December 31, 2023 and December 31, 2022, the book value of our investment in DCP Midstream Class B Segment was $75 million and $79 million, respectively.
•Liberty Pipeline LLC (Liberty)-In the first quarter of 2021, Phillips 66 Partners’ decided to exit the Liberty Pipeline project, which resulted in a $198 million before-tax impairment. The impairment is included in the “Impairments” line item on our consolidated statement of income for the year ended December 31, 2021. In April 2021, Phillips 66 Partners transferred its ownership interest in Liberty to its co-venturer for cash and certain pipeline assets with a value that approximated its book value of $46 million at March 31, 2021. See Note 11-Impairments, and Note 18-Fair Value Measurements, for additional information regarding the impairment and the techniques used to determine the fair value of Phillips 66 Partners’ investment in Liberty.
Midstream Investment Disposition
On August 1, 2023, we sold our 25% ownership interest in the South Texas Gateway Terminal for approximately $275 million and recognized a before-tax gain of $101 million. The before-tax gain is included in the “Net gain on dispositions” line item on our consolidated statement of income for the year ended December 31, 2023, and is reported in the Midstream segment.
Other Investments
In September 2021, we acquired 78 million ordinary shares, representing a 16% ownership interest, in NOVONIX Limited (NOVONIX), for $150 million. NOVONIX is a Brisbane, Australia-based company that develops technology and supplies materials for lithium-ion batteries and its shares are traded on the Australian Securities Exchange. Since we do not have significant influence over the operating and financial policies of NOVONIX and the shares we own have a readily determinable fair value, our investment is recorded at fair value at the end of each reporting period. The fair value of our investment is recorded in the “Investments and long-term receivables” line item on our consolidated balance sheet. The change in the fair value of our investment due to fluctuations in NOVONIX’s stock price, or unrealized investment gain (losses), is recorded in the “Other income” line item of our consolidated statement of income, while changes due to foreign currency fluctuations are recorded in the “Foreign currency transaction (gains) losses” line item on our consolidated statement of income. At December 31, 2023 and 2022, the fair value of our investment in NOVONIX was $39 million and $78 million, respectively. The fair value of our investment in NOVONIX declined by $39 million and $442 million during the years ended December 31, 2023 and 2022, respectively, and increased by $370 million during the year ended December 31, 2021. The declines in fair value in 2023 and 2022 were primarily related to unrealized investment losses, while the increase in 2021 was primarily related to unrealized investment gains. See Note 18-Fair Value Measurements, for additional information regarding the recurring fair value measurement of our investment in NOVONIX.
Related Party Loans
We and our co-venturer have provided member loans to WRB. At December 31, 2023 and 2022, no member loans were outstanding.
Equity Affiliate Distributions
Total distributions received from affiliates were $1,396 million, $1,832 million, and $3,043 million for the years ended December 31, 2023, 2022 and 2021, respectively. In addition, at December 31, 2023, retained earnings included approximately $3.3 billion related to the undistributed earnings of affiliated companies.
Summarized Equity Affiliate Financial Information
Summarized 100% financial information for all affiliated companies accounted for under the equity method, on a combined basis, was:
Millions of Dollars
2023 2022 2021
Revenues $ 42,078 60,981 49,339
Income before income taxes 5,350 7,616 6,346
Net income 5,160 7,414 6,125
Current assets 6,759 7,511 7,866
Noncurrent assets 46,241 46,527 56,040
Current liabilities 5,750 5,592 7,952
Noncurrent liabilities 10,980 11,412 16,906
Noncontrolling interests 2 2 3,003
Note 9-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 35-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
2023 2022
Gross
PP&E Accum.
D&A Net
PP&E Gross
PP&E Accum.
D&A Net
PP&E
Midstream $ 26,124 4,382 21,742 25,422 3,524 21,898
Chemicals - - - - - -
Refining 25,421 13,103 12,318 24,200 12,523 11,677
Marketing and Specialties 1,997 1,166 831 1,800 1,058 742
Corporate and Other 1,650 829 821 1,568 722 846
$ 55,192 19,480 35,712 52,990 17,827 35,163
See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, Note 4-Business Combinations and Note 18-Fair Value Measurements, for additional information on the DCP Midstream Merger, accounting treatment and the associated fair value measurements. See Note 11-Impairments, for information regarding PP&E impairments associated with our Alliance Refinery asset group. See Note 28-Segment Disclosures and Related Information, for information regarding the change in the composition of our operating segments.
Note 10-Goodwill and Intangibles
The carrying amount of goodwill by segment at December 31 was:
Millions of Dollars
Midstream Marketing and Specialties Total
Balance at December 31, 2021 $ 626 858 1,484
Goodwill assigned to acquisitions - 2 2
Balance at December 31, 2022 626 860 1,486
Goodwill assigned to acquisitions - 64 64
Balance at December 31, 2023 $ 626 924 1,550
In August 2023, we acquired a marketing business on the U.S. West Coast, in our M&S segment and recognized goodwill of $64 million associated with this acquisition. Refer to Note 4-Business Combinations for additional information.
Intangible Assets
The gross carrying value of indefinite-lived intangible assets at December 31 consisted of the following:
Millions of Dollars
2023 2022
Trade names and trademarks $ 504 503
Refinery air and operating permits 196 200
$ 700 703
The net book value of our amortized intangible assets was $220 million and $128 million at December 31, 2023 and 2022, respectively. For the years ended December 31, 2023, 2022 and 2021, amortization expense was $33 million, $27 million and $26 million, respectively, and is expected to be less than $35 million per year in future years.
In August 2023, we acquired a marketing business on the U.S. West Coast, in our M&S segment and recorded additions of $146 million in amortized intangible assets. Acquisitions of amortized intangible assets were not material in 2022.
Note 11-Impairments
Millions of Dollars
2023 2022 2021
Midstream $ 3 1 209
Refining 10 13 1,288
Marketing and Specialties 3 - 1
Corporate and Other 8 46 -
Total impairments $ 24 60 1,498
Equity Investments
Liberty
In the first quarter of 2021, Phillips 66 Partners decided to exit the Liberty Pipeline project in our Midstream segment, which had previously been deferred due to the challenging business environment caused by the COVID-19 pandemic. As a result, Phillips 66 Partners recorded a $198 million before-tax impairment to reduce the book value of its investment in Liberty at March 31, 2021, to estimated fair value.
PP&E and Intangible Assets
Alliance Refinery
In the third quarter of 2021, we identified impairment indicators related to our Alliance Refinery as a result of damages sustained from Hurricane Ida and our reassessment of the role this refinery would play in our refining portfolio. Accordingly, we assessed the refinery asset group for impairment by performing an analysis that considered several usage scenarios, including selling or converting the asset group to an alternative use. Based on our analysis, we concluded that the carrying value of the asset group was not recoverable. As a result, we recorded a $1,298 million before-tax impairment to reduce the carrying value of net PP&E in this asset group to its fair value of approximately $200 million. $1,288 million of the impairment charge was recorded in our Refining segment and $10 million was recorded in our Midstream segment. In the fourth quarter of 2021, we shut down our Alliance Refinery.
These impairment charges are included within the “Impairments” line item on our consolidated income statement. See Note 18-Fair Value Measurements, for additional information on the determination of fair value use to record these impairments.
Note 12-Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
Millions of Dollars
2023 2022
Asset retirement obligations $ 537 565
Accrued environmental costs 446 434
Total asset retirement obligations and accrued environmental costs 983 999
Asset retirement obligations and accrued environmental costs due within one year*
(119) (120)
Long-term asset retirement obligations and accrued environmental costs $ 864 879
* 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. Our recognized asset retirement obligations primarily involve asbestos abatement at our refineries; decommissioning, removal or dismantlement of certain assets at refineries that have or will be shut down; decommissioning, removal or dismantlement of certain midstream pipelines and processing facilities; and dismantlement or removal of assets at certain leased international marketing sites. Most of our asset retirement 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.
During the years ended December 31, 2023 and 2022, our overall asset retirement obligation changed as follows:
Millions of Dollars
2023 2022
Balance at January 1 $ 565 395
Accretion of discount 25 15
New obligations - 7
Acquisition of DCP Midstream Class A Segment, DCP Sand Hills and DCP
Southern Hills - 168
Changes in estimates of existing obligations 23 17
Spending on existing obligations (58) (32)
Asset dispositions (23) -
Foreign currency translation 5 (5)
Balance at December 31 $ 537 565
Accrued Environmental Costs
Of our total accrued environmental costs at December 31, 2023, $279 million was primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations; $117 million was associated with nonoperator sites; and $50 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, 2023, the accrued balance for acquired environmental liabilities was $243 million. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $24 million in 2024, $18 million in 2025, $20 million in 2026, $17 million in 2027, $16 million in 2028, and $200 million in the aggregate for all years after 2028.
Note 13-Earnings Per Share
The numerator of basic earnings per share (EPS) is net income 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 attributable to Phillips 66, which is reduced by dividend equivalents paid on participating securities for which the dividends are more dilutive than the participation of the awards in the earnings of the periods presented. To the extent unvested stock, unit or option awards and vested unexercised stock options are dilutive, they are included with the weighted-average common shares outstanding in the denominator. Treasury stock is excluded from the denominator in both basic and diluted EPS.
2023 2022 2021
Basic Diluted Basic Diluted Basic Diluted
Amounts Attributed to Phillips 66 Common Stockholders (millions):
Net Income Attributable to Phillips 66 $ 7,015 7,015 11,024 11,024 1,317 1,317
Income allocated to participating securities (11) - (10) - (9) (9)
Premium paid for the repurchase of noncontrolling
interests
- - - - (2) (2)
Net income available to common stockholders $ 7,004 7,015 11,014 11,024 1,306 1,306
Weighted-average common shares outstanding (thousands):
448,381 450,136 469,436 471,497 437,886 440,028
Effect of share-based compensation 1,755 3,074 2,061 2,234 2,142 336
Weighted-average common shares outstanding-EPS
450,136 453,210 471,497 473,731 440,028 440,364
Earnings Per Share of Common Stock (dollars)
$ 15.56 15.48 23.36 23.27 2.97 2.97
Note 14-Debt
Short-term and long-term debt at December 31 was:
Millions of Dollars
December 31, 2023
Phillips 66 Phillips 66 Company Phillips 66 Partners DCP LP Total
0.900% Senior Notes due February 2024
$ 800 - - - 800
2.450% Senior Notes due December 2024
- 277 23 - 300
3.605% Senior Notes due February 2025
- 441 59 - 500
3.850% Senior Notes due April 2025
650 - - - 650
5.375% Senior Notes due July 2025
- - - 825 825
1.300% Senior Notes due February 2026
500 - - - 500
3.550% Senior Notes due October 2026
- 458 34 - 492
5.625% Senior Notes due July 2027
- - - 500 500
4.950% Senior Notes due December 2027
- 750 - - 750
3.750% Senior Notes due March 2028
- 427 73 - 500
3.900% Senior Notes due March 2028
800 - - - 800
5.125% Senior Notes due May 2029
- - - 600 600
3.150% Senior Notes due December 2029
- 570 30 - 600
8.125% Senior Notes due August 2030
- - - 300 300
2.150% Senior Notes due December 2030
850 - - - 850
3.250% Senior Notes due February 2032
- - - 400 400
5.300% Senior Notes due June 2033
- 500 - - 500
4.650% Senior Notes due November 2034
1,000 - - - 1,000
6.450% Senior Notes due November 2036
- - - 300 300
6.750% Senior Notes due September 2037
- - - 450 450
5.875% Senior Notes due May 2042
1,500 - - - 1,500
5.600% Senior Notes due April 2044
- - - 400 400
4.875% Senior Notes due November 2044
1,700 - - - 1,700
4.680% Senior Notes due February 2045
- 442 8 - 450
4.900% Senior Notes due October 2046
- 605 20 - 625
3.300% Senior Notes due March 2052
1,000 - - - 1,000
Securitization facility due August 2024 - - - 350 350
Floating Rate Term Loan due June 2026 at 6.456% at year-end 2023
- 1,250 - - 1,250
Floating Rate Advance Term Loan due 2035 at 6.096% at year end 2023-related party
25 - - - 25
Floating Rate Advance Term Loan due 2038 at 6.490% at year-end 2023-related party
265 - - - 265
Revolving credit facility due 2027 at 6.512% at year-end 2023
- - - 25 25
Other 1 - - - 1
Debt at face value 9,091 5,720 247 4,150 19,208
Finance leases 305
Software obligations 13
Net unamortized discounts, debt issuance costs and acquisition fair value adjustments (167)
Total debt 19,359
Short-term debt (1,482)
Long-term debt $ 17,877
Millions of Dollars
December 31, 2022
Phillips 66 Phillips 66 Company Phillips 66 Partners DCP LP Total
3.875% Senior Notes due March 2023
$ - - - 500 500
0.900% Senior Notes due February 2024
800 - - - 800
2.450% Senior Notes due December 2024
- 277 23 - 300
3.605% Senior Notes due February 2025
- 441 59 - 500
3.850% Senior Notes due April 2025
650 - - - 650
5.375% Senior Notes due July 2025
- - - 825 825
1.300% Senior Notes due February 2026
500 - - - 500
3.550% Senior Notes due October 2026
- 458 34 - 492
5.625% Senior Notes due July 2027
- - - 500 500
3.750% Senior Notes due March 2028
- 427 73 - 500
3.900% Senior Notes due March 2028
800 - - - 800
5.125% Senior Notes due May 2029
- - - 600 600
3.150% Senior Notes due December 2029
- 570 30 - 600
8.125% Senior Notes due August 2030
- - - 300 300
2.150% Senior Notes due December 2030
850 - - - 850
3.250% Senior Notes due February 2032
- - - 400 400
4.650% Senior Notes due November 2034
1,000 - - - 1,000
6.450% Senior Notes due November 2036
- - - 300 300
6.750% Senior Notes due September 2037
- - - 450 450
5.875% Senior Notes due May 2042
1,500 - - - 1,500
5.850% Junior Subordinated Notes due May 2043
- - - 550 550
5.600% Senior Notes due April 2044
- - - 400 400
4.875% Senior Notes due November 2044
1,700 - - - 1,700
4.680% Senior Notes due February 2045
- 442 8 - 450
4.900% Senior Notes due October 2046
- 605 20 - 625
3.300% Senior Notes due March 2052
1,000 - - - 1,000
Securitization facility due August 2024 - - - 40 40
Floating Rate Advance Term Loan due December 2034 at 4.720% at year-end 2022-related party
25 - - - 25
Other 1 - - - 1
Debt at face value 8,826 3,220 247 4,865 17,158
Finance leases 257
Software obligations 20
Net unamortized discounts, debt issuance costs and acquisition fair value adjustments (245)
Total debt 17,190
Short-term debt (529)
Long-term debt $ 16,661
Maturities of borrowings outstanding at December 31, 2023, inclusive of net unamortized discounts and debt issuance costs, for each of the years from 2024 through 2028 are $1,482 million, $1,999 million, $2,253 million, $1,276 million and $1,313 million, respectively.
2023 Activities
Debt Repayments
On May 19, 2023, DCP LP redeemed its 5.850% junior subordinated notes due May 2043 with an aggregate principal amount outstanding of $550 million. On the date of redemption, our carrying value of DCP LP’s junior subordinated notes was $497 million, which resulted in a $53 million before-tax loss. DCP LP’s junior subordinated notes were adjusted to fair value on August 17, 2022, in connection with the consolidation of DCP LP. See Note 18-Fair Value Measurements, for additional information regarding the fair value of DCP LP’s junior subordinated notes.
On March 15, 2023, DCP LP repaid its 3.875% senior unsecured notes due March 2023 with an aggregate principal amount of $500 million.
Debt Issuances
On March 29, 2023, Phillips 66 Company, a wholly owned subsidiary of Phillips 66, issued $1.25 billion aggregate principal amount of senior unsecured notes consisting of:
•$750 million aggregate principal amount of 4.950% Senior Notes due December 2027 (2027 Notes).
•$500 million aggregate principal amount of 5.300% Senior Notes due June 2033 (2033 Notes).
The 2027 Notes and 2033 Notes (collectively, the Notes) are fully and unconditionally guaranteed by Phillips 66. Interest on the 2027 Notes is payable semi-annually on June 1 and December 1 of each year and commenced on December 1, 2023. Interest on the 2033 Notes is payable semi-annually on June 30 and December 30 of each year and commenced on December 30, 2023.
Term Loan Agreement
On March 27, 2023, Phillips 66 Company, a wholly owned subsidiary of Phillips 66, entered into a $1.5 billion delayed draw term loan agreement guaranteed by Phillips 66 (the Term Loan Agreement). The Term Loan Agreement provides for a single borrowing during a 90-day period commencing on the closing date, which borrowing was contingent upon the completion of the DCP LP Merger. The Term Loan Agreement contains customary covenants similar to those contained in our revolving credit agreement, including a maximum consolidated net debt-to-capitalization ratio of 65% as of the last day of each fiscal quarter. The Term Loan Agreement has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts after grace periods; and violation of covenants. We may at any time prepay outstanding borrowings under the Term Loan Agreement, in whole or in part, without premium or penalty. Outstanding borrowings under the Term Loan Agreement bear interest at either: (a) the adjusted term Secured Overnight Financing Rate (SOFR) in effect from time to time plus the applicable margin; or (b) the reference rate plus the applicable margin, as defined in the Term Loan Agreement. At December 31, 2023, $1.25 billion was borrowed under the Term Loan Agreement, which matures in June 2026.
Related Party Advance Term Loan Agreements
Borrowings under related party Advance Term Loan agreements with WRB increased from $25 million at December 31, 2022, to $290 million at December 31, 2023. Borrowings under these agreements are due in 2035 and 2038 and bear interest at a floating rate based on an adjusted term SOFR plus an applicable margin, payable on the last day of each month.
See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, for additional information regarding the DCP LP Merger.
2022 Activities
Debt Repayments
In December 2022, Phillips 66 repaid its 3.700% senior notes due April 2023 with an aggregate principal amount of $500 million.
In April 2022, upon maturity, Phillips 66 repaid its 4.300% senior notes with an aggregate principal amount of $1 billion and Phillips 66 Partners repaid its $450 million term loan.
DCP Midstream Class A Segment
As a result of the DCP Midstream Merger, we recorded the fair value of DCP Midstream Class A Segment’s debt to our consolidated balance sheet as of August 17, 2022. See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, Note 4-Business Combinations, and Note 18-Fair Value Measurements, for additional information regarding the DCP Midstream Merger and the associated fair value measurements. All of DCP Midstream Class A Segment’s debt is held by DCP LP. Interest on all of DCP LP’s senior notes and junior subordinated notes is paid on a semi-annual basis.
Debt Exchange
On May 5, 2022, Phillips 66 Company, a wholly owned subsidiary of Phillips 66, completed offers to exchange (the Exchange Offers) all validly tendered notes of seven different series of notes issued by Phillips 66 Partners (collectively, the Old Notes), with an aggregate principal amount of approximately $3.5 billion, for notes issued by Phillips 66 Company (collectively, the New Notes). The New Notes are fully and unconditionally guaranteed by Phillips 66 and rank equally with Phillips 66 Company’s other unsecured and unsubordinated indebtedness, and the guarantees rank equally with Phillips 66’s other unsecured and unsubordinated indebtedness.
Old Notes with an aggregate principal amount of approximately $3.2 billion were tendered in the Exchange Offers. The New Notes have the same interest rates, interest payment dates and maturity dates as the Old Notes. Holders that validly tendered before the end of the early participation period on April 19, 2022 (the Early Participation Date), received New Notes with an aggregate principal amount equivalent to the Old Notes, while holders that validly tendered after the Early Participation Date, but before the Expiration Date, received New Notes with an aggregate principal amount 3% less than the Old Notes. Substantially all of the Old Notes exchanged were tendered during the Early Participation Period.
Subsequent Repayment
On February 15, 2024, upon maturity, Phillips 66 repaid its 0.900% senior notes due February 2024 with an aggregate principal amount of $800 million.
Credit Facilities and Commercial Paper
Phillips 66 and Phillips 66 Company
On June 23, 2022, we entered into a $5 billion revolving credit facility (the Facility) with Phillips 66 Company as the borrower and Phillips 66 as the guarantor and a scheduled maturity date of June 22, 2027. The Facility replaced our previous $5 billion revolving credit facility with Phillips 66 as the borrower and Phillips 66 Company as the guarantor. The Facility contains usual and customary covenants that are similar to the previous revolving credit facility, including a maximum consolidated net debt-to-capitalization ratio of 65% as of the last day of each fiscal quarter. We have the 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, subject to, among other things, the consent of the lenders holding the majority of the commitments and of each lender extending its commitment. Outstanding borrowings under the Facility bear interest at either (a) the adjusted term SOFR (as described in the Facility) 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 our senior unsecured long-term debt from time to time. We may at any time prepay outstanding borrowings, in whole or in part, without premium or penalty. At December 31, 2023 and 2022, 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 the Facility. Commercial paper maturities are contractually limited to 365 days. At December 31, 2023 and 2022, no borrowings were outstanding under the program.
Phillips 66 Partners
In connection with entering into the Facility, we terminated Phillips 66 Partners’ $750 million revolving credit facility.
DCP Midstream Class A Segment
DCP LP has a credit facility under its amended credit agreement (the Credit Agreement), with a borrowing capacity of up to $1.4 billion that matures on March 18, 2027. The Credit Agreement grants DCP LP the option to increase the revolving loan commitment by an aggregate principal amount of up to $500 million and to extend the term for up to two additional one-year periods, subject to requisite lender approval. Indebtedness under the Credit Agreement bears interest at either: (a) an adjusted SOFR (as described in the Credit Agreement) plus the applicable margin; or (b) the base rate (as described in the Credit Agreement) plus the applicable margin. The Credit Agreement also provides for customary fees, including commitment fees. The cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid based on DCP LP’s credit rating. At December 31, 2023, DCP LP had $25 million in borrowings outstanding under the Credit Agreement. At December 31, 2022, DCP LP had no borrowings outstanding under the Credit Agreement. At December 31, 2023, and December 31, 2022, respectively, $2 million and $10 million in letters of credit had been issued that are supported by the Credit Agreement.
DCP LP has an accounts receivable securitization facility (the Securitization Facility) that provides for up to $350 million of borrowing capacity through August 2024 at an adjusted SOFR and includes an uncommitted option to increase the total commitments under the Securitization Facility by up to an additional $400 million. Under the Securitization Facility, certain of DCP LP’s wholly owned subsidiaries sell or contribute receivables to another of DCP LP’s consolidated subsidiaries, DCP Receivables LLC, a bankruptcy-remote special purpose entity created for the sole purpose of the Securitization Facility. At December 31, 2023, and December 31, 2022, respectively, $350 million and $40 million of borrowings were outstanding under the Securitization Facility, which are secured by accounts receivable at DCP Receivables LLC.
After our consolidation of DCP Midstream Class A Segment on August 17, 2022, DCP LP repaid $470 million of borrowing under its accounts receivable securitization and revolving credit facilities that were outstanding on the acquisition date.
Total Committed Capacity Available
At December 31, 2023, and 2022, we had approximately $6.4 billion and $6.7 billion, respectively, of total committed capacity available under the credit facilities described above.
Note 15-Guarantees
At December 31, 2023, 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
Under the operating lease agreement for our headquarters facility in Houston, Texas, we have the option, at the end of the lease term in September 2025, 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, 2023. We also have residual value guarantees associated with railcar, airplane and truck leases with maximum potential future exposures totaling $168 million. These leases have remaining terms of one to ten years.
Guarantees of Joint Venture 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 8-Investments, Loans and Long-Term Receivables, for additional information regarding Dakota Access and the CECU.
At December 31, 2023, we also had other guarantees outstanding primarily for our portion of certain joint venture debt, which have remaining terms of up to two years. The maximum potential future exposures under these guarantees were approximately $214 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 indemnifications. 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, 2023 and 2022, the carrying amount of recorded indemnifications was $159 million and $137 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, 2023 and 2022, environmental accruals for known contamination of $114 million and $108 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 12-Asset Retirement Obligations and Accrued Environmental Costs and Note 16-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 16-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 uncertain. See Note 23-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 Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.
Although liability for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies alleged to have liability at a particular site. Due to such joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites 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 12-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, 2023, we had performance obligations secured by letters of credit and bank guarantees of $1,124 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, 2023, the estimated aggregate future payments under these agreements were $319 million per year for each year from 2024 through 2028 and $692 million in aggregate for all years after 2028. For the years ended December 31, 2023, 2022 and 2021, total payments under these agreements were $319 million, $323 million and $327 million, respectively.
Note 17-Derivatives and Financial Instruments
Derivative Instruments
We use financial and commodity-based derivative contracts to manage exposures to fluctuations in commodity prices, interest rates and foreign currency exchange rates, or to capture market opportunities. Because we do not apply hedge accounting for commodity derivative contracts, all realized and unrealized gains and losses from commodity derivative contracts are recognized in our consolidated statement of income. Gains and losses from derivative contracts held for trading not directly related to our physical business are reported net in the “Other income” line item on our consolidated statement of income. Cash flows from all our derivative activity for the periods presented appear in the operating section on our consolidated statement of cash flows.
Purchase and sales contracts with firm minimum notional volumes for commodities that are readily convertible to cash are recorded on our consolidated balance sheet as derivatives unless the contracts are eligible for, and we elect, the normal purchases and normal sales exception, whereby the contracts are recorded on an accrual basis. We generally apply the normal purchases and normal sales exception to eligible crude oil, refined petroleum product, NGL, natural gas, renewable feedstock, 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 18-Fair Value Measurements.
Commodity Derivative Contracts-We sell into or receive supply from the worldwide crude oil, refined petroleum product, NGL, natural gas, renewable feedstock, 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.
DCP Midstream Class A Segment
Through DCP LP’s operations, DCP Midstream Class A Segment is exposed to a variety of risks including but not limited to changes in the prices of commodities that DCP LP buys or sells. The information below includes DCP LP’s financial instruments from the effective date of the DCP Midstream Merger. See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, for additional information regarding the DCP Midstream Merger and the associated accounting treatment.
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, 2023 December 31, 2022
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 $ 2,148 (2,005) - 143 1,331 (1,110) - 221
Other assets 19 (2) - 17 46 (1) - 45
Liabilities
Other accruals 1,034 (1,127) 18 (75) 471 (750) 90 (189)
Other liabilities and deferred credits - (14) - (14) 12 (35) - (23)
Total $ 3,201 (3,148) 18 71 1,860 (1,896) 90 54
At December 31, 2023, there was $7 million of net collateral received that was not offset on our consolidated balance sheet. At December 31, 2022, there was $93 million of collateral paid that was not offset on our consolidated balance sheet.
The realized and unrealized gains (losses) incurred from commodity derivatives, and the line items where they appear on our consolidated statement of income, were:
Millions of Dollars
2023 2022 2021
Sales and other operating revenues $ 137 (128) (468)
Other income 99 79 34
Purchased crude oil and products (269) (348) (313)
Net gain (loss) from commodity derivative activity $ (33) (397) (747)
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 more than 90% at December 31, 2023 and 2022.
Open Position
Long / (Short)
2023 2022
Commodity
Crude oil, refined petroleum products, NGL and renewable feedstocks (millions of barrels)
(22) (25)
Natural gas (billions of cubic feet)
(25) (77)
Credit Risk from Derivative and Financial 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 ratings. 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, 2023 and 2022.
Note 18-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-The fair value of our exchange-traded contracts is based on quoted market prices obtained from the New York Mercantile Exchange, the Intercontinental Exchange or other exchanges, and is reported 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 or Level 3 based on the degree to which inputs are observable.
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.
When applicable, we determine the fair value of 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.
•Investment in NOVONIX-Our investment in NOVONIX is measured at fair value using unadjusted quoted prices available from the Australian Securities Exchange and is therefore categorized as Level 1 in the fair value hierarchy.
•Other investments-Includes other marketable securities with observable market prices.
•Debt-The carrying amount of our floating-rate debt approximates fair value. The fair value of our fixed-rate debt is estimated primarily 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, 2023
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 $ 3,075 54 - 3,129 (3,039) - - 90
OTC instruments - 1 - 1 - - - 1
Physical forward contracts - 70 1 71 (2) - - 69
Rabbi trust assets 155 - - 155 N/A N/A - 155
Investment in NOVONIX 39 - - 39 N/A N/A - 39
$ 3,269 125 1 3,395 (3,041) - - 354
Commodity Derivative Liabilities
Exchange-cleared instruments $ 3,057 41 - 3,098 (3,039) (18) - 41
Physical forward contracts - 50 - 50 (2) - - 48
Floating-rate debt - 1,915 - 1,915 N/A N/A - 1,915
Fixed-rate debt, excluding finance leases and software obligations - 16,718 - 16,718 N/A N/A 408 17,126
$ 3,057 18,724 - 21,781 (3,041) (18) 408 19,130
Millions of Dollars
December 31, 2022
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 $ 1,615 130 3 1,748 (1,582) - - 166
OTC instruments - 7 16 23 - - - 23
Physical forward contracts - 86 3 89 (12) - - 77
Rabbi trust assets 126 - - 126 N/A N/A - 126
Investment in NOVONIX 78 - - 78 N/A N/A - 78
Other investments 42 1 - 43 N/A N/A - 43
$ 1,861 224 22 2,107 (1,594) - - 513
Commodity Derivative Liabilities
Exchange-cleared instruments $ 1,676 164 5 1,845 (1,582) (90) - 173
OTC instruments - 9 - 9 - - - 9
Physical forward contracts - 42 - 42 (12) - - 30
Floating-rate debt - 65 - 65 N/A N/A - 65
Fixed-rate debt, excluding finance leases and software obligations - 15,871 - 15,871 N/A N/A 977 16,848
$ 1,676 16,151 5 17,832 (1,594) (90) 977 17,125
The rabbi trust assets and investment in NOVONIX 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 17-Derivatives and Financial Instruments, for information regarding where the assets and liabilities related to our commodity derivatives are recorded on our consolidated balance sheet.
Nonrecurring Fair Value Measurements
Equity Investments
In the first quarter of 2021, Phillips 66 Partners wrote down the book value of its investment in Liberty to estimated fair value using a Level 3 nonrecurring fair value measurement. This nonrecurring measurement was based on the estimated fair value of Phillips 66 Partners’ share of the joint venture’s pipeline assets and net working capital at March 31, 2021. See Note 8-Investments, Loans and Long-Term Receivables, for more information regarding Phillips 66 Partners’ transfer of its ownership in Liberty to its co-venturer in April 2021.
PP&E and Intangible Assets
Alliance Refinery
In the third quarter of 2021, we remeasured the carrying value of the net PP&E of our Alliance Refinery asset group to fair value. The fair value of PP&E was determined using a combination of the income, cost and sales comparison approaches. The income approach used a discounted cash flow model that required various observable and non-observable inputs, such as commodity prices, margins, operating rates, sales volumes, operating expenses, capital expenditures, terminal-year values and a risk-adjusted discount rate. The cost approach used assumptions for the current replacement costs of similar plant and equipment assets adjusted for estimated physical deterioration, functional obsolescence and economic obsolescence. The sales comparison approach used the value of similar properties recently sold or currently offered for sale. This valuation resulted in a Level 3 nonrecurring fair value measurement.
DCP Midstream Merger
On August 17, 2022, we and Enbridge agreed to merge DCP Midstream and Gray Oak Holdings with DCP Midstream as the surviving entity. As a result, we began consolidating the financial results of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills, and accordingly, accounted for the business combination using the acquisition method of accounting, which required DCP Midstream Class A Segment’s, DCP Sand Hills’ and DCP Southern Hills’, assets and liabilities to be recorded at fair value as of the acquisition date on our consolidated balance sheet. See Note 4-Business Combinations, for additional information on the DCP Midstream Merger.
Equity Method Investments
The fair value of the investments we acquired that are accounted for under the equity method was $2,034 million. The fair value of these assets was determined using the income approach. The income approach used discounted cash flow models that require various observable and non-observable inputs, such as margins, tariffs and rates, utilization, volumes, product costs, operating expenses, capital expenditures, terminal-year values and risk-adjusted discount rates. These valuations resulted in Level 3 nonrecurring fair value measurements.
PP&E
The fair value of PP&E was $13,030 million. The fair value of these assets was determined primarily using the cost approach. The cost approach used assumptions for the current replacement costs of similar plant and equipment assets adjusted for estimated physical deterioration, functional obsolescence and economic obsolescence. The fair value of properties was determined using a sales comparison approach. These valuations resulted in Level 3 nonrecurring fair value measurements.
Debt
The fair value of DCP LP’s senior and junior subordinated notes was measured using a market approach, based on the average of quotes for the acquired debt from major financial institutions. These valuations resulted in Level 2 nonrecurring fair value measurements.
Noncontrolling Interests
As a result of our consolidation of DCP Midstream Class A Segment, the noncontrolling interests held in DCP Midstream Class A Segment were recorded at their fair values on the DCP Midstream Merger date. These noncontrolling interests on the DCP Midstream Merger date primarily included Enbridge’s indirect economic interest in DCP LP, the public holders of DCP LP’s common units and the public holders of DCP LP’s preferred units. The fair value of the noncontrolling interests in DCP LP’s common units was based on their unit market price as of the date of the DCP Midstream Merger, August 17, 2022. The fair value of the noncontrolling interests in DCP LP’s publicly traded preferred units was based on their respective market price as of the date of the DCP Midstream Merger, August 17, 2022. These valuations resulted in Level 1 nonrecurring fair value measurements. The fair value of the noncontrolling interests in DCP LP’s other preferred units was based on an income approach that used projected distributions that were discounted using an average implied yield of DCP LP’s publicly traded preferred units and expected redemption dates. This valuation resulted in a Level 2 nonrecurring fair value measurement.
Gains Related to DCP Midstream Merger
In connection with the DCP Midstream Merger, we recognized before-tax gains totaling $2,831 million from remeasuring our previously held equity investments to their fair values and a before-tax gain of $182 million related to the transfer of a 35.75% indirect economic interest in Gray Oak Pipeline to our co-venturer. The fair values of our previously held equity interest in DCP Midstream and the equity interest in Gray Oak Pipeline we transferred were primarily based on DCP LP’s publicly traded common unit market price on the effective date of the merger, August 17, 2022, the cash consideration contributed and obligations that were deemed to be effectively settled. This valuation resulted in Level 1 nonrecurring fair value measurements. The fair values of our previously held equity interests in DCP Sand Hills and DCP Southern Hills were determined using the income approach. The income approach used discounted cash flow models that require various observable and non-observable inputs, such as tariffs, volumes, operating expenses, capital expenditures, terminal-year values and risk-adjusted discount rates. These valuations resulted in Level 3 nonrecurring fair value measurements.
Note 19-Equity
Preferred Stock
Phillips 66 has 500 million shares of preferred stock authorized, with a par value of $0.01 per share, none of which have been issued.
Treasury Stock
On October 25, 2023, our Board of Directors approved a $5 billion increase to our share repurchase authorization. Since the inception of our share repurchase program in 2012, our Board of Directors has authorized an aggregate of $25 billion of repurchases of our outstanding common stock, and we have repurchased 213.8 million shares at an aggregate cost of $18 billion. In 2023, we repurchased 37.8 million shares at an aggregate cost of $4 billion. Our share repurchase authorizations do not expire. 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. Shares of stock repurchased are held as treasury shares.
Our Board of Directors separately authorized two transactions in 2014 and 2018, which resulted in the repurchase of 52.4 million shares of Phillips 66 common stock with an aggregate value of $4.6 billion.
In March 2022, in connection with the Phillips 66 Partners merger, we issued 41.8 million shares of common stock from our treasury stock with an aggregate cost of $3.4 billion. See Note 30-Phillips 66 Partners LP, for information on the merger with Phillips 66 Partners.
Common Stock Dividends
On February 7, 2024, our Board of Directors declared a quarterly cash dividend of $1.05 per common share, payable March 1, 2024, to holders of record at the close of business on February 20, 2024.
Noncontrolling Interests
At December 31, 2023, our noncontrolling interests primarily represented Enbridge’s indirect economic interest in DCP LP. On June 15, 2023, as part of the DCP LP Merger, we acquired all publicly held common units of DCP LP and eliminated the public common unit noncontrolling interest in our consolidated financial statements from the DCP LP Merger date, forward. During 2023, DCP LP also redeemed its Series B and Series C preferred units. See Note 29-DCP Midstream Class A Segment, for further information on the DCP LP Merger and preferred unit redemptions.
At December 31, 2022, our noncontrolling interests primarily represented Enbridge’s indirect economic interest in DCP LP, the public holders of DCP LP’s common units and the holders of DCP LP’s Series B and Series C preferred units. In December 2022, DCP LP redeemed its Series A preferred units. In March 2022, we completed a merger between us and Phillips 66 Partners, which resulted in the acquisition of all limited partnership interests in Phillips 66 Partners not already owned by us. See Note 29-DCP Midstream Class A Segment, for further information on the preferred unit redemption. See Note 30-Phillips 66 Partners LP, for further information on the merger with Phillips 66 Partners.
Note 20-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.
We discount lease obligations using our incremental borrowing rate. We 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 account for the lease and service components on a combined basis. 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 do not recognize the right-of-use (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
2023 2022
Finance
Leases Operating
Leases Finance
Leases Operating
Leases
Right-of-Use Assets
Net properties, plants and equipment $ 298 - 259 -
Other assets - 1,116 - 995
Total right-of-use assets $ 298 1,116 259 995
Lease Liabilities
Short-term debt $ 25 - 23 -
Other accruals - 362 - 282
Long-term debt 280 - 234 -
Other liabilities and deferred credits - 790 - 745
Total lease liabilities $ 305 1,152 257 1,027
Future minimum lease payments at December 31, 2023, for finance and operating lease liabilities were:
Millions of Dollars
Finance
Leases Operating
Leases
2024 $ 39 406
2025 32 295
2026 34 206
2027 28 127
2028 29 75
Remaining years 250 180
Future minimum lease payments 412 1,289
Amount representing interest or discounts (107) (137)
Total lease liabilities $ 305 1,152
Our finance lease liabilities relate primarily to service station consignment agreements with a marketing joint venture and a crude oil terminal in the United Kingdom. The lease liability for the terminal finance lease is subject to foreign currency translation adjustments each reporting period.
Components of net lease cost for the years ended December 31, 2023, 2022 and 2021, were:
Millions of Dollars
2023 2022 2021
Finance lease cost
Amortization of right-of-use assets $ 30 24 23
Interest on lease liabilities 9 9 9
Total finance lease cost 39 33 32
Operating lease cost 390 387 461
Short-term lease cost 76 63 104
Variable lease cost 55 19 3
Sublease income (12) (13) (15)
Total net lease cost $ 548 489 585
Cash paid for amounts included in the measurement of our lease liabilities for the years ended December 31, 2023, 2022 and 2021, was:
Millions of Dollars
2023 2022 2021
Operating cash outflows-finance leases $ 15 11 9
Operating cash outflows-operating leases 390 392 438
Financing cash outflows-finance leases 19 32 21
During the years ended December 31, 2023, 2022 and 2021, we recorded noncash ROU assets and corresponding operating lease liabilities totaling $398 million, $269 million and $260 million, respectively, related to new and modified lease agreements.
At December 31, 2023 and 2022, the weighted-average remaining lease terms and discount rates for our lease liabilities were:
2023 2022
Weighted-average remaining lease term-finance leases (years) 13.4 12.5
Weighted-average remaining lease term-operating leases (years) 4.9 5.8
Weighted-average discount rate-finance leases 3.9 % 3.3
Weighted-average discount rate-operating leases 4.5 % 3.8
Note 21-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
2023 2022 2023 2022
U.S. Int’l. U.S. Int’l.
Change in Benefit Obligations
Benefit obligations at January 1 $ 2,209 675 3,033 1,409 156 197
Service cost 108 13 123 28 3 4
Interest cost 118 31 100 21 8 5
Plan participant contributions - 2 - 2 7 6
Actuarial loss (gain) 58 30 (528) (502) 2 (37)
Benefits paid (233) (33) (519) (44) (26) (19)
Settlements - - - (101) - -
Foreign currency exchange rate change - 34 - (138) - -
Benefit obligations at December 31 $ 2,260 752 2,209 675 150 156
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1 $ 1,778 707 2,547 1,280 - -
Actual return on plan assets 203 44 (375) (329) - -
Company contributions 391 20 125 23 19 13
Plan participant contributions - 2 - 2 7 6
Benefits paid (233) (33) (519) (44) (26) (19)
Settlements - - - (101) - -
Foreign currency exchange rate change - 38 - (124) - -
Fair value of plan assets at December 31 $ 2,139 778 1,778 707 - -
Funded Status at December 31 $ (121) 26 (431) 32 (150) (156)
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
2023 2022 2023 2022
U.S. Int’l. U.S. Int’l.
Amounts Recognized in the Consolidated Balance Sheet
Noncurrent assets $ - 157 - 140 - -
Current liabilities (55) - (50) - (20) (15)
Noncurrent liabilities (66) (131) (381) (108) (130) (141)
Total recognized $ (121) 26 (431) 32 (150) (156)
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
2023 2022 2023 2022
U.S. Int’l. U.S. Int’l.
Unrecognized net actuarial loss (gain)
$ 111 2 159 (27) (51) (59)
Unrecognized prior service credit
- - - - - -
Other changes in plan assets and benefit obligations recognized in other comprehensive income (loss):
Millions of Dollars
Pension Benefits Other Benefits
2023 2022 2023 2022
U.S. Int’l. U.S. Int’l.
Sources of Change in Other Comprehensive Income
Net actuarial gain (loss) arising during the period $ 20 (26) 18 136 (2) 37
Amortization of net actuarial loss (gain) and settlements
28 (3) 74 21 (6) (2)
Amortization of prior service credit - - - (1) - (2)
Total recognized in other comprehensive income $ 48 (29) 92 156 (8) 33
The accumulated benefit obligations for all U.S. and international pension plans were $2,101 million and $661 million, respectively, at December 31, 2023, and $2,055 million and $593 million, respectively, at December 31, 2022.
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
2023 2022
U.S. Int’l. U.S. Int’l.
Accumulated benefit obligations $ 101 136 2,055 114
Fair value of plan assets
- 13 1,778 13
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
2023 2022
U.S. Int’l. U.S. Int’l.
Projected benefit obligations $ 2,260 144 2,209 121
Fair value of plan assets
2,139 13 1,778 13
Components of net periodic benefit cost for all defined benefit plans are presented in the table below:
Millions of Dollars
Pension Benefits Other Benefits
2023 2022 2021 2023 2022 2021
U.S. Int’l. U.S. Int’l. U.S. Int’l.
Components of Net Periodic Benefit Cost
Service cost $ 108 13 123 28 146 36 3 4 5
Interest cost 118 31 100 21 81 19 8 5 5
Expected return on plan assets
(126) (43) (135) (56) (160) (59) - - -
Amortization of prior service credit - - - (1) - (1) - (2) (2)
Amortization of net actuarial loss (gain)
11 (3) 21 12 46 25 (6) (2) (1)
Settlements
17 - 53 9 55 - - - -
Net periodic benefit cost (credit)* $ 128 (2) 162 13 168 20 5 5 7
* Included in the “Operating expenses” and “Selling, general and administrative expenses” line items on our consolidated statement of income.
In determining net periodic benefit cost, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize 10% 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
2023 2022 2023 2022
U.S. Int’l. U.S. Int’l.
Assumptions Used to Determine Benefit Obligations:
Discount rate 5.35 % 4.36 5.70 4.64 5.45 5.70
Rate of compensation increase 4.30 3.34 4.30 3.32 - -
Interest crediting rate on cash balance plan
3.98 - 3.88 - - -
Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate 5.70 % 4.64 3.94 1.65 5.70 2.90
Expected return on plan assets 7.50 5.91 6.50 4.90 - -
Rate of compensation increase 4.30 3.32 4.30 3.05 - -
Interest crediting rate on cash balance plan
3.88 - 2.59 - - -
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, 2023, actuarial losses resulted in increases in our U.S. and international pension benefit obligations of $58 million and $30 million, respectively. For the year ended December 31, 2022, actuarial gains resulted in decreases in our U.S. and international pension benefit obligations of $528 million and $502 million, respectively. The primary driver for the actuarial losses in 2023 was decreases in the discount rates. The primary driver for the actuarial gains in 2022 was increases in the discount rates.
For the year ended December 31, 2023, the weighted-average actual return on plan assets was 10%, which resulted in an increase in our U.S. and international plan assets of $203 million and $44 million, respectively. For the year ended December 31, 2022, the weighted-average actual return on plan assets was negative 20%, which resulted in a decrease in our U.S. and international plan assets of $375 million and $329 million, respectively. The primary driver of the return on plan assets in 2023 and 2022 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 7% in 2024 that declines to 5% by 2031.
Plan Assets
The investment strategy for managing pension plan assets is to seek a reasonable rate of return relative to an appropriate level of risk and provide adequate liquidity for benefit payments and portfolio management. We follow a policy of diversifying pension plan assets across asset classes, investment managers, and individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include equities, fixed income, cash, real estate and infrastructure investments 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 47% equity securities, 37% debt securities, 8% real estate investments and 8% in all other types of investments as of December 31, 2023. Generally, the investments in the plans are publicly traded, therefore minimizing the liquidity risk in the portfolio.
The following is a description of the valuation methodologies used for the pension plan assets.
•Fair values of equity securities and government debt securities are based on quoted market prices.
•Fair values of corporate debt securities are estimated using recently executed transactions and market price quotations. If there have been no market transactions in a particular fixed income security, its fair value is calculated by pricing models that benchmark the security against other securities with actual market prices.
•Fair values of cash and cash equivalents approximate their carrying amounts.
•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 (CCT) and real estate and infrastructure investments, which include a CCT, limited partnerships, and other 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 $ 295 - - 295 - - - -
Government debt securities 388 - - 388 - - - -
Corporate debt securities - 101 - 101 - - - -
Cash and cash equivalents 31 - - 31 4 - - 4
Insurance contracts - - - - - - 13 13
Total assets in the fair value hierarchy
714 101 - 815 4 - 13 17
Common/collective trusts measured at NAV
1,013 636
Real estate and infrastructure investments measured at NAV 311 125
Total $ 714 101 - 2,139 4 - 13 778
Millions of Dollars
U.S. International
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Equity securities $ 239 - - 239 - - - -
Government debt securities 268 - - 268 - - - -
Corporate debt securities
- 89 - 89 - - - -
Cash and cash equivalents 19 - - 19 64 - - 64
Insurance contracts - - - - - - 13 13
Total assets in the fair value hierarchy
526 89 - 615 64 - 13 77
Common/collective trusts measured at NAV
841 567
Real estate and infrastructure investments measured at NAV 322 63
Total $ 526 89 - 1,778 64 - 13 707
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 2024, we expect to contribute approximately $75 million to our U.S. pension plans and other postretirement benefit plans and $5 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.
2024 $ 251 24 18
2025 207 27 17
2026 213 28 17
2027 217 30 16
2028 216 34 16
2029-2033 1,096 184 74
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. For the years ended December 31, 2023 and 2022, Phillips 66 provided a company match of participant contributions up to 8% of eligible pay, with an additional Success Share contribution ranging from 0% to 4% of eligible pay based on management discretion. For the year ended December 31, 2021, Phillips 66 provided a company match of participant contributions up to 6% of eligible pay, with an additional Success Share contribution ranging from 0% to 6% of eligible pay based on management discretion.
For the years ended December 31, 2023, 2022 and 2021, we recorded expense of $196 million, $210 million and $142 million, respectively, related to our contributions to the Savings Plan.
Note 22-Share-Based Compensation Plans
Share-based payment awards, including stock options, stock appreciation rights, stock awards (including restricted stock and RSU awards), cash awards, and performance awards, are granted to our employees, nonemployee directors and other plan participants by the Human Resources and Compensation Committee (HRCC) of our Board of Directors under the applicable Omnibus Stock and Performance Incentive Plan of Phillips 66. Prior to May 11, 2022, share-based payment awards were granted under the 2013 Omnibus Stock and Performance Incentive Plan of Phillips 66 (the 2013 P66 Omnibus Plan). On May 11, 2022, Phillips 66’s shareholders approved the 2022 Omnibus Stock and Performance Incentive Plan of Phillips 66 (the 2022 P66 Omnibus Plan), which replaced the 2013 P66 Omnibus Plan. No future awards will be made under the 2013 P66 Omnibus Plan. As of December 31, 2023, approximately 13 million shares of Phillips 66’s common stock remained available to be issued to settle share-based payment awards under the 2022 P66 Omnibus Plan.
Total share-based compensation expense recognized in income and the associated income tax benefit for the years ended December 31 were:
Millions of Dollars
2023 2022 2021
Restricted stock units $ 130 101 100
Performance share units 139 68 23
Stock options 19 17 19
Other 9 24 2
Total share-based compensation expense $ 297 210 144
Income tax benefit $ (87) (55) (33)
Restricted Stock Units
Generally, RSUs are granted annually under the provisions of the applicable Phillips 66 incentive plan, and vest either ratably over three years following the grant date or cliff vest at the end of three years for awards granted in 2023. For awards granted prior to 2023, RSUs 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 ten months after the grant date for RSUs granted in 2023 and six months after the grant date for RSUs granted prior to 2023. 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, 2023, to December 31, 2023:
Millions of Dollars
Stock Units Weighted-Average
Grant-Date
Fair Value Total Fair Value
Outstanding at January 1, 2023 3,266,475 $ 82.76
Granted 1,583,095 100.39
Forfeited (92,090) 93.04
Issued (1,225,397) 84.48 $ 126
Outstanding at December 31, 2023 3,532,083 $ 89.80
Not Vested at December 31, 2023 2,491,170 $ 90.40
At December 31, 2023, the remaining unrecognized compensation cost from unvested RSU awards was $92 million, which will be recognized over a weighted-average period of 18 months, the longest period being 35 months.
During 2022 and 2021, we granted RSUs with a weighted-average grant-date fair value of $88.16 and $75.91, respectively. During 2022 and 2021, we issued shares with an aggregate fair value of $102 million and $61 million, respectively, to settle RSUs.
Performance Share Units
Under the applicable Phillips 66 incentive plan, senior management is annually awarded restricted performance share units (PSUs) with three-year performance periods. These awards vest when the HRCC approves the three-year performance results, which represents the grant date. Retirement-eligible employees may retain a prorated share of the award if they retire prior to the grant date. PSUs are classified as liability awards and compensation expense is recognized over the three-year performance periods.
PSUs granted under the applicable Phillips 66 incentive 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, 2023, to December 31, 2023:
Millions of Dollars
Performance
Share Units Weighted-Average
Grant-Date
Fair Value Total Fair Value
Outstanding at January 1, 2023 703,169 $ 38.54
Granted 347,668 102.66
Forfeited (243) 63.64
Issued (168,665) 41.56 $ 13
Cash settled (347,668) 102.66 36
Outstanding at December 31, 2023 534,261 $ 37.57
Not Vested at December 31, 2023 - $ -
At December 31, 2023, there was no remaining unrecognized compensation cost from unvested PSU awards.
During 2022 and 2021, we granted PSUs with a weighted-average grant-date fair value of $71.82 and $68.18, respectively. During 2022 and 2021, we issued shares with an aggregate fair value of $9 million and $12 million, respectively, to settle PSUs. During 2022 and 2021, we cash settled PSUs with an aggregate fair value of $18 million and $27 million, respectively.
Stock Options
Stock options granted under the provisions of the applicable Phillips 66 incentive 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 over three years following the grant date, with one-third of the options becoming exercisable each year on the grant date anniversary. Options granted to retirement-eligible employees are not subject to forfeiture ten months after the grant date for options granted in 2023 and six months after the grant date for options granted prior to 2023.
The following table summarizes our stock option activity from January 1, 2023, to December 31, 2023:
Millions of Dollars
Options Weighted-Average
Exercise Price Weighted-Average
Grant-Date
Fair Value Aggregate
Intrinsic Value
Outstanding at January 1, 2023 5,842,915 $ 84.97
Granted 792,000 100.32 $ 27.45
Forfeited (33,372) 97.41
Exercised (1,483,629) 82.84 $ 52
Outstanding at December 31, 2023 5,117,914 $ 87.89
Vested at December 31, 2023 4,604,847 $ 87.35 $ 212
Exercisable at December 31, 2023 3,198,901 $ 86.59 $ 149
The weighted-average remaining contractual terms of vested options and exercisable options at December 31, 2023, were 6.37 years and 5.6 years, respectively. During 2023, we received $123 million in cash and realized an income tax benefit of $12 million from the exercise of options. At December 31, 2023, the remaining unrecognized compensation expense from unvested options was $6 million, which will be recognized over a weighted-average period of 21 months, the longest period being 30 months.
During 2022 and 2021, we granted options with a weighted-average grant-date fair value of $17.02 and $12.06, respectively. During 2022 and 2021, employees exercised options with an aggregate intrinsic value of $42 million and $24 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:
2023 2022 2021
Risk-free interest rate 3.84 % 1.97 0.93
Dividend yield 3.80 % 5.10 5.30
Volatility factor 35.19 % 33.67 32.11
Expected life (years) 6.78 6.61 6.76
We calculate the volatility factor using historical Phillips 66 end-of-week closing stock prices. 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.
Other
As a result of the DCP Midstream Merger, we began consolidating DCP Midstream Class A Segment starting on August 18, 2022. DCP Midstream Class A Segment had a Long-Term Incentive Plan under which phantom units, performance units and distribution equivalent rights were awarded to key employees. On June 15, 2023, DCP Midstream Class A Segment’s share-based payment awards were converted to Phillips 66 share-based payment awards and are included in the share-based payment award tables above. Share-based compensation expense recognized for DCP Midstream Class A Segment’s share-based payment awards totaled $23 million for the period from August 18, 2022, through December 31, 2022, and $6 million for the period from January 1, 2023, through June 14, 2023.
See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers and Note 4-Business Combinations for additional information regarding the merger and associated accounting treatment.
Note 23-Income Taxes
Components of income tax expense (benefit) were:
Millions of Dollars
2023 2022 2021
Income Tax Expense (Benefit)
Federal
Current $ 661 1,263 363
Deferred 830 1,171 (85)
Foreign
Current 394 492 50
Deferred (23) (109) (39)
State and local
Current 335 173 5
Deferred 33 258 (148)
$ 2,230 3,248 146
On August 16, 2022, the U.S. government enacted the Inflation Reduction Act of 2022 (IRA) that includes, among other provisions, changes to the U.S. corporate income tax system, including a 15% minimum tax based on adjusted financial statement income as defined in the IRA, which was effective after December 31, 2022. We do not owe corporate alternative minimum tax in 2023 as the regular U.S. tax liability exceeds the corporate alternative minimum tax. The IRA also included provisions that allow a company to purchase transferable tax credits. In 2023, we executed agreements to purchase eligible tax credits for a total of $262 million. In 2023, we paid $196 million to our counterparties and the remainder will be paid in 2024. These tax credits were used to offset estimated tax payments in 2023.
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
2023 2022
Deferred Tax Liabilities
Properties, plants and equipment, and intangibles $ 3,320 3,309
Investment in joint ventures 1,979 1,854
Investment in subsidiaries 2,628 1,974
Other 268 238
Total deferred tax liabilities 8,195 7,375
Deferred Tax Assets
Benefit plan accruals 362 307
Loss and credit carryforwards 151 113
Asset retirement obligations and accrued environmental costs 127 137
Other financial accruals and deferrals 68 51
Inventory 34 62
Other 274 220
Total deferred tax assets 1,016 890
Less: valuation allowance 121 97
Net deferred tax assets 895 793
Net deferred tax liabilities $ 7,300 6,582
At December 31, 2023, the loss and credit carryforward deferred tax assets were primarily related to a foreign tax credit carryforward in the United States of $113 million; a state tax net operating loss carryforward of $30 million; and capital loss and net operating loss carryforwards in the United Kingdom of $8 million. State net operating loss carryforwards begin to expire in 2040. 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, and have a full valuation allowance against them, 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, 2023, our total valuation allowance balance increased by $24 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 indefinitely reinvested. At December 31, 2023 and 2022, the unrecorded deferred tax liability related to the undistributed earnings of this foreign subsidiary was not material.
A deferred income tax liability has not been recognized on the excess of the book basis over the tax basis of an investment in a controlled foreign subsidiary that is essentially permanent in duration. Recognition of a deferred tax liability will only be required if it becomes apparent that this subsidiary will be sold or liquidated in the foreseeable future. At December 31, 2023, the temporary difference resulting from the investment book basis exceeding the tax basis was $1,430 million. Determination of the unrecognized deferred income tax liability related to this temporary difference is not practicable given the variables involved in performing such a calculation.
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
2023 2022 2021
Balance at January 1 $ 54 54 56
Additions for tax positions of current year - 1 -
Additions for tax positions of prior years 66 2 -
Reductions for tax positions of prior years (4) (3) (2)
Balance at December 31 $ 116 54 54
Included in the balance of unrecognized income tax benefits at December 31, 2023, 2022 and 2021, were $100 million, $37 million and $35 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 expect $28 million to be recognized or paid within the next twelve months.
At December 31, 2023, 2022 and 2021, accrued liabilities for interest and penalties, net of accrued income taxes, totaled $8 million, $7 million and $6 million, respectively. These accruals decreased our results for each of the years ended December 31, 2023, 2022 and 2021 by $1 million, $3 million and $3 million, respectively.
Audits in significant jurisdictions are generally complete as follows: United Kingdom (2021), Germany (2017) 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 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 (Loss) Before Income Taxes
2023 2022 2021 2023 2022 2021
Income before income taxes
United States $ 7,887 12,628 1,737 83.3 % 86.3 99.8
Foreign 1,582 2,011 3 16.7 13.7 0.2
$ 9,469 14,639 1,740 100.0 % 100.0 100.0
Federal statutory income tax $ 1,989 3,074 365 21.0 % 21.0 21.0
State income tax, net of federal income tax benefit 290 341 (65) 3.1 2.3 (3.7)
Noncontrolling interests (51) (74) (57) (0.5) (0.5) (3.3)
Non-taxable equity earnings (42) (33) (53) (0.4) (0.2) (3.0)
Tax law changes - (25) (26) - (0.2) (1.5)
Other* 44 (35) (18) 0.4 (0.2) (1.1)
$ 2,230 3,248 146 23.6 22.2 8.4
* Other includes individually immaterial items but is primarily attributable to foreign operations and change in valuation allowance.
For the year ended December 31, 2021, state income tax, net of federal income tax benefit, includes a $58 million benefit, primarily to reflect the impact of updated apportionment factors.
For the years ended December 31, 2023 and 2022, income tax benefits of $113 million and $323 million, respectively, are reflected in “Capital in Excess of Par” on the consolidated statement of changes in equity. There is no income tax reflected in “Capital in Excess of Par” for the year ended December 31, 2021.
Note 24-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, 2020 $ (809) 25 (5) (789)
Other comprehensive income (loss) before reclassifications 318 (70) 2 250
Amounts reclassified from accumulated other comprehensive loss
Defined benefit plans*
Amortization of net actuarial loss, prior service credit and settlements 93 - - 93
Foreign currency translation - - - -
Hedging - - 1 1
Net current period other comprehensive income (loss) 411 (70) 3 344
December 31, 2021 (398) (45) (2) (445)
Other comprehensive income (loss) before reclassifications 204 (291) - (87)
Amounts reclassified from accumulated other comprehensive loss
Defined benefit plans*
Amortization of net actuarial loss, prior service credit and settlements 72 - - 72
Foreign currency translation - - - -
Hedging - - - -
Net current period other comprehensive income (loss) 276 (291) - (15)
December 31, 2022 (122) (336) (2) (460)
Other comprehensive income (loss) before reclassifications (12) 179 (3) 164
Amounts reclassified from accumulated other comprehensive loss
Defined benefit plans*
Amortization of net actuarial loss and settlements 14 - - 14
Foreign currency translation - - - -
Hedging - - - -
Net current period other comprehensive income (loss) 2 179 (3) 178
December 31, 2023 $ (120) (157) (5) (282)
* Included in the computation of net periodic benefit cost. See Note 21-Pension and Postretirement Plans, for additional information.
Note 25-Cash Flow Information
Supplemental Cash Flow Information
Millions of Dollars
2023 2022 2021
Cash Payments (Receipts)
Interest $ 816 572 549
Income taxes* 1,397 2,071 (1,065)
* 2023 includes $196 million of cash paid to counterparties to purchase IRA eligible tax credits. 2021 reflects a net cash refund position. Cash payments for income taxes were $110 million in 2021.
Note 26-Other Financial Information
Millions of Dollars
2023 2022 2021
Interest and Debt Expense
Incurred
Debt
$ 842 611 567
Other
86 41 41
928 652 608
Capitalized (31) (33) (27)
Expensed $ 897 619 581
Other Income
Interest income $ 269 82 11
Unrealized investment gain (loss)-NOVONIX (38) (433) 365
Gain related to merger of businesses - 3,013 -
Other, net* 128 75 78
$ 359 2,737 454
* Includes derivatives-related activities. See Note 17-Derivatives and Financial Instruments, for additional information.
Research and Development Expenses $ 27 42 47
Advertising Expenses $ 54 56 52
Foreign Currency Transaction (Gains) Losses
Midstream $ 1 9 (5)
Chemicals - - -
Refining 19 (7) 4
Marketing and Specialties 4 (10) -
Corporate and Other (2) (1) 2
$ 22 (9) 1
Note 27-Related Party Transactions
Significant transactions with related parties were:
Millions of Dollars
2023 2022 2021
Operating revenues and other income (a)(d) $ 4,623 6,111 3,759
Purchases (b)(d) 17,208 21,244 14,645
Operating expenses and selling, general and administrative expenses (c) 295 281 284
(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 LLC (Excel Paralubes), and refined petroleum products to several of our equity affiliates in the M&S segment, including OnCue and CF United. We also sold certain feedstocks and intermediate products to WRB and acted as an 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, NGL and solvents from WRB. 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 Paralubes 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.
(d)As a result of the DCP Midstream Merger, we began consolidating DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills. As such, transactions with these parties after August 17, 2022, are not presented in the table above.
Note 28-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, gathering, processing and marketing services, mainly in the United States. As a result of the DCP Midstream Merger on August 17, 2022, we began consolidating DCP Midstream Class A Segment, as well as DCP Sand Hills and DCP Southern Hills. See Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers. This segment also includes our 16% investment in NOVONIX.
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, as well as renewable fuels. This segment includes 12 refineries in the United States and Europe.
4)Marketing and Specialties-Purchases for resale and markets refined petroleum products and renewable fuels, mainly in the United States and Europe. In addition, this segment includes the manufacturing and marketing of base oils and lubricants.
Corporate and Other includes general corporate overhead, interest income, interest expense, our investment in research of new technologies and various other corporate activities. Corporate assets include all cash, cash equivalents and income tax-related assets. Corporate and Other also includes restructuring costs related to our business transformation. See Note 31-Restructuring, for additional information regarding restructuring costs.
Intersegment sales are at prices that we believe approximate market.
Analysis of Results by Operating Segment
Millions of Dollars
2023 2022 2021
Sales and Other Operating Revenues*
Midstream
Total sales $ 18,605 19,121 11,714
Intersegment eliminations (2,825) (2,932) (2,901)
Total Midstream 15,780 16,189 8,813
Chemicals - - 3
Refining
Total sales 96,011 112,725 75,096
Intersegment eliminations (59,846) (71,127) (46,122)
Total Refining 36,165 41,598 28,974
Marketing and Specialties
Total sales 98,769 115,622 75,583
Intersegment eliminations (3,351) (3,453) (1,929)
Total Marketing and Specialties 95,418 112,169 73,654
Corporate and Other 36 34 32
Consolidated sales and other operating revenues $ 147,399 169,990 111,476
* See Note 5-Sales and Other Operating Revenues, for further details on our disaggregated sales and other operating revenues.
Equity in Earnings (Losses) of Affiliates
Midstream $ 649 916 877
Chemicals 586 842 1,832
Refining 439 747 (184)
Marketing and Specialties 343 463 379
Corporate and Other - - -
Consolidated equity in earnings of affiliates $ 2,017 2,968 2,904
Depreciation, Amortization and Impairments*
Midstream $ 926 569 634
Chemicals - - -
Refining 849 879 2,272
Marketing and Specialties 124 110 114
Corporate and Other 102 131 83
Consolidated depreciation, amortization and impairments $ 2,001 1,689 3,103
* See Note 11-Impairments, for further details on impairments by segment.
Millions of Dollars
2023 2022 2021
Interest Income and Expense
Interest income
Corporate and Other $ 269 82 11
Interest and debt expense
Corporate and Other $ 897 619 581
Income (Loss) Before Income Taxes
Midstream $ 2,774 4,734 1,500
Chemicals 600 856 1,844
Refining 5,266 7,816 (2,353)
Marketing and Specialties 2,135 2,402 1,723
Corporate and Other (1,306) (1,169) (974)
Consolidated income before income taxes $ 9,469 14,639 1,740
Investments In and Advances To Affiliates
Midstream $ 3,766 4,271 3,978
Chemicals 7,341 6,785 6,369
Refining 2,802 2,484 2,340
Marketing and Specialties 825 883 750
Corporate and Other 2 2 2
Consolidated investments in and advances to affiliates $ 14,736 14,425 13,439
Total Assets
Midstream $ 29,107 30,273 15,546
Chemicals 7,357 6,785 6,453
Refining 22,432 21,581 20,338
Marketing and Specialties 11,411 9,939 8,505
Corporate and Other 5,194 7,864 4,752
Consolidated total assets $ 75,501 76,442 55,594
Millions of Dollars
2023 2022 2021
Capital Expenditures and Investments
Midstream $ 625 1,043 733
Chemicals - - -
Refining 1,339 928 784
Marketing and Specialties 364 89 202
Corporate and Other 90 134 141
Consolidated capital expenditures and investments $ 2,418 2,194 1,860
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
2023 2022 2021
United States $ 49,124 48,286 34,882
United Kingdom 1,406 1,349 1,323
Germany 394 391 605
Other countries 90 87 96
Worldwide consolidated $ 51,014 50,113 36,906
Note 29-DCP Midstream Class A Segment
DCP Midstream Class A Segment is a VIE and we are the primary beneficiary. DCP Midstream Class A Segment is comprised of the businesses, activities, assets and liabilities of DCP LP and its subsidiaries and its general partner entities. Refer to Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers and Note 4-Business Combinations, for more details regarding the DCP Midstream Merger and related accounting.
DCP LP is a master limited partnership whose operations currently include producing and fractionating NGL, gathering, compressing, treating and processing natural gas; recovering condensate; and transporting, trading, marketing and storing natural gas and NGL.
As a result of the DCP Midstream Merger, we began consolidating DCP Midstream Class A Segment from the merger date forward, and we reflected the interests held by DCP LP’s public common and preferred unitholders’ and Enbridge’s indirect economic interest in DCP LP at the time of the merger as noncontrolling interests in our consolidated financial statements. On June 15, 2023, as part of the DCP LP Merger, we acquired all publicly held common units of DCP LP and eliminated the public common unit noncontrolling interest in our consolidated financial statements from the DCP LP Merger date, forward. The DCP LP Merger increased our aggregate direct and indirect economic interest in DCP LP from 43.3% to 86.8%. See below and Note 3-DCP Midstream, LLC and DCP Midstream, LP Mergers, for additional information about the DCP Midstream and DCP LP Mergers, as well as information on preferred unit redemptions that also decreased the “Noncontrolling interests” balance on our consolidated balance sheet since December 31, 2022.
The most significant assets of DCP Midstream Class A Segment 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, 2023 December 31, 2022
Accounts receivable, trade* $ 601 988
Net properties, plants and equipment 9,319 9,297
Investments in unconsolidated affiliates** 1,901 2,161
Accounts payable 815 1,239
Short-term debt 357 504
Long-term debt 3,759 4,248
* Included in the “Accounts and notes receivable” line item on the Phillips 66 consolidated balance sheet.
** Included in the “Investments and long-term receivables” line item on the Phillips 66 consolidated balance sheet.
DCP LP Merger
On June 15, 2023, we completed the acquisition of approximately 91 million publicly held common units of DCP LP pursuant to the terms of the DCP LP Merger Agreement. The DCP LP Merger Agreement was entered into with DCP LP, its subsidiaries and its general partner entities, pursuant to which one of our wholly owned subsidiaries merged with and into DCP LP, with DCP LP surviving as a Delaware limited partnership. Under the terms of the DCP LP Merger Agreement, at the effective time of the DCP LP Merger, each publicly held common unit representing a limited partner interest in DCP LP (other than the common units owned by DCP Midstream and its subsidiaries) issued and outstanding as of immediately prior to the effective time was converted into the right to receive $41.75 per common unit in cash. We paid $3,796 million in cash consideration to common unitholders, funded with a combination of available cash and proceeds from the offering of the Notes and borrowings under the Term Loan Agreement. See Note 11-Debt, for additional information.
The DCP LP Merger was accounted for as an equity transaction and resulted in decreases to “Cash and cash equivalents” of $3,814 million, which includes cash consideration paid to common unitholders of $3,796 million plus fees paid of $18 million, “Noncontrolling interests” of $3,343 million, “Capital in excess of par” of $361 million and “Deferred income taxes” of $110 million on our consolidated balance sheet.
Preferred Units
On October 16, 2023, DCP LP redeemed its Series C preferred units at the aggregated liquidation preference of $110 million, which approximated the book value of the preferred units. In June 2023, DCP LP redeemed its Series B preferred units at the aggregated liquidation preference of $161 million, which approximated the book value of the preferred units. In December 2022, DCP LP redeemed its Series A preferred units with an aggregate liquidation preference of $500 million, which approximated the book value of the preferred units.
Trading and Reporting Status
DCP LP’s common units, Series B preferred units and Series C preferred units have been delisted and deregistered from the New York Stock Exchange. In addition, DCP LP has suspended its reporting obligations to the Securities and Exchange Commission under Sections 13 and 15(d) of the Exchange Act.
Distributions
For the years ended December 31, 2023, and 2022, DCP LP made cash distributions of $125 million and $51 million, respectively, to common unitholders other than Phillips 66 and its subsidiaries, and $15 million and $27 million, respectively, to preferred unitholders.
Note 30-Phillips 66 Partners LP
On March 9, 2022, we completed a merger between us and Phillips 66 Partners. The merger resulted in the acquisition of all limited partnership interests in Phillips 66 Partners not already owned by us in exchange for 41.8 million shares of Phillips 66 common stock issued from treasury stock. Phillips 66 Partners common unitholders received 0.50 shares of Phillips 66 common stock for each outstanding Phillips 66 Partners common unit. Phillips 66 Partners’ perpetual convertible preferred units were converted into common units at a premium to the original issuance price prior to being exchanged for Phillips 66 common stock. Upon closing, Phillips 66 Partners became a wholly owned subsidiary of Phillips 66 and its common units are no longer publicly traded.
The merger was accounted for as an equity transaction and resulted in decreases to “Treasury stock” of $3,380 million, “Noncontrolling interests” of $2,163 million, “Capital in excess of par” of $901 million, “Deferred income taxes” of $323 million, and “Cash and cash equivalents” of $2 million, and an increase to “Other accruals” of $5 million on our consolidated balance sheet.
Note 31-Restructuring
In April 2022, we announced that we are progressing a multi-year business transformation focused on enterprise-wide opportunities to improve our cost structure. For the years ended December 31, 2023, and 2022, we recorded restructuring costs totaling $177 million and $160 million, respectively, primarily related to consulting fees and severance costs. Restructuring costs for the year ended December 31, 2022, also included an impairment related to assets held for sale. These costs are primarily recorded in the “Selling, general and administrative expenses” and “Impairments” line items on our consolidated statement of income and are reported in our Corporate segment.
In addition, for the years ended December 31, 2023 and 2022, we recorded restructuring costs of $38 million and $18 million, respectively, associated with the integration of DCP Midstream Class A Segment primarily related to severance and contract exit costs. These costs are primarily recorded in the “Selling, general and administrative expenses” line item on our consolidated statement of income and are reported in our Midstream segment.
Note 32-New Accounting Standards
In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740) - Improvements to Income Tax Disclosures,” which enhances the transparency, effectiveness, and comparability of income tax disclosures by requiring consistent categories and greater disaggregation of information related to income tax rate reconciliations and the jurisdictions in which income taxes are paid. This ASU is effective for annual periods beginning after December 15, 2024, with early adoption permitted. We are evaluating the provisions of ASU 2023-09 and the impact on our financial statement disclosures.
In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” This ASU improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. This ASU is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We are evaluating the provisions of ASU 2023-07 and the impact on our segment reporting disclosures.
In March 2023, the FASB issued ASU 2023-01, “Leases (Topic 842): Common Control Arrangements.” This ASU provides additional requirements for lessees that are a party to a lease between entities under common control in which there are leasehold improvements. This ASU is effective for fiscal years beginning after December 15, 2023, including interim periods within those fiscal years, with early adoption permitted. Effective January 1, 2024, we adopted ASU 2023-01. At the time of adoption, there was no impact on our consolidated financial statements from this ASU.

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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, 2023, with the participation of management, our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of December 31, 2023.
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, 2023, 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
During the quarter ended December 31, 2023, no director or Section 16 officer adopted, modified or terminated any “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (in each case, as defined in Item 408(a) of Regulation S-K).

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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.
We have adopted a Code of Ethics for the Principal Executive Officer and Senior Financial Officers (the “Code of Ethics”) that applies to our Principal Executive Officer, Chief Financial Officer and Controller. The Code of Ethics is posted on our website located at http://www.phillips66.com (within the Corporate Governance section) and is available in print upon request. We intend to disclose future amendments to the Code of Ethics, and any waivers of the Code of Ethics, on our website.
The remaining information required by Item 10 of Part III is incorporated herein by reference from our Definitive Proxy Statement relating to our 2024 Annual Meeting of Stockholders to be held on May 15, 2024, which will be filed within 120 days after December 31, 2023 (2024 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 2024 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 2024 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 2024 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 2024 Definitive Proxy Statement.*
_________________________
* Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing in our 2024 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 83, 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 164 to 170, are filed as part of this Annual Report on Form 10-K.