| TABLE OF CONTENTS
Unless otherwise indicated, “the company,the “company,” “we,” “our,” “us” and “Phillips 66” are used in this report to refer to the businesses of Phillips 66 and its consolidated subsidiaries. Unless the context requires otherwise, references to “DCP Midstream” include the consolidated operations of DCP Midstream, LLC, including DCP Midstream, LP, the master limited partnership formed by DCP Midstream, LLC.
This Annual Report on Form 10-K contains forward-looking statements including, without limitation, statements relating to ourthe company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions often identify forward-looking statements.statements, but the absence of these words does not mean a statement is not forward-looking. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws.pursuant to applicable law. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the headingheadings “Risk Factors” and “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.”
PART I
Items 1 and 2. BUSINESS AND PROPERTIES
CORPORATE STRUCTURE
Phillips 66, headquartered in Houston, Texas, was incorporated in Delaware in 2011 in connection with, and in anticipation of, a restructuring of ConocoPhillips that separated its downstream businesses into an independent, publicly traded company named Phillips 66. The two companies were separated by ConocoPhillips distributing to its stockholders all the shares of common stock of Phillips 66 after the market closed on April 30, 2012 (the Separation)separation). Phillips 66 stock trades on the New York Stock Exchange under the “PSX” stock symbol.
Our business isbusinesses are organized into four operating segments:
| | 1) | Midstream—Provides crude oil and refined products transportation, terminaling and processing services, as well as natural gas, natural gas liquids (NGL) and liquefied petroleum gas (LPG) transportation, storage, processing and marketing services, mainly in the United States. This segment includes our master limited partnership (MLP), Phillips 66 Partners LP (Phillips 66 Partners), as well as our 50 percent equity investment in DCP Midstream, LLC (DCP Midstream).
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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 percent equity investment in Chevron Phillips Chemical Company LLC (CPChem), which manufactures and markets petrochemicals and plastics on a worldwide basis.
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| | 3) | Refining—Refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels) at 13 refineries in the United States and Europe.
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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.
| | 4) | Marketing and Specialties—Purchases for resale and markets refined petroleum products, mainly in the United States and Europe. In addition, this segment includes the manufacturing and marketing of specialty products (such as base oils and lubricants), as well as power generation operations.
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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 cash equivalents.
At December 31, 2017, Phillips 66 had approximately 14,600 employees.
SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment and geographic information, see our business transformation. See Note 26—Segment Disclosures and Related Information,31—Restructuring, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.for additional information regarding restructuring costs.
SEGMENT AND GEOGRAPHIC INFORMATION
MIDSTREAM
The Midstream segment consists of three business lines: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—Transports, stores, fractionates and markets NGL in the United States, exports LPG and provides other fee-based processing services.
DCP Midstream—Gathers, processes, transports and markets natural gas and transports, fractionates and markets NGL.
Phillips 66 Partners•NOVONIX—Represents our 16% investment in NOVONIX, a company that develops technology and supplies materials for lithium-ion batteries.
In 2013, we formed Phillips 66 Partners, an MLP, to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum products and NGL pipelines and terminals, as well as other midstream assets.
At December 31, 2017, we owned a 55 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while the public owned a 43 percent limited partner interest and 13.8 million perpetual convertible preferred units.
Headquartered in Houston, Texas, Phillips 66 Partners’ assets and equity investments currently consist2023, our Midstream business was comprised of over 72,000 miles of crude oil, refined petroleum products and NGL transportation, terminaling and storage systems, as well as crude oil and NGL processing facilities, that are geographically dispersed throughout the United States. The majority of Phillips 66 Partners’ assets are integral to Phillips 66-operated refineries.
During 2017, Phillips 66 Partners expanded its business by acquiring from us:
A 25 percent interest in both Dakota Access, LLC (Dakota Access) and Energy Transfer Crude Oil Company, LLC (ETCO), which collectively own the Bakken Pipeline.
A 100 percent interest in Merey Sweeny, L.P. (MSLP), a limited partnership that owns a delayed coker and performs crude oil processing at our Sweeny Refinery.
This acquisition closed in October 2017. See Note 27—Phillips 66 Partners LP, in the Notes to the Consolidated Financial Statements, for more information on this transaction.
The operations and financial results of Phillips 66 Partners are included in Midstream’s Transportation andproduct, NGL and Other business lines, based on the nature of the activity within the partnership.
Transportation
We own or lease various assets to provide terminaling and storage of crude oil, refined products, natural gas and NGL. These assets include pipeline systems; petroleum products, crude oil and LPG terminals; a petroleum coke handling facility; marine vessels; railcars and trucks.
Pipelines and Terminals
At December 31, 2017, our Transportation business managed over 21,000 miles of crude oil, natural gas, NGL and petroleum product pipeline systems in the United States, including those partially owned or operated by our affiliates. We owned or operated 40 finished39 refined petroleum product terminals, 38 storage locations, 5 LPG terminals, 1936 gathering and processing plants, 17 crude oil terminals, and 1eight fractionation facilities, six NGL terminals, a petroleum coke exporting facility.facility and various other storage and loading facilities.
DCP Midstream, LLC and Gray Oak Holdings LLC Merger (DCP Midstream Merger)
TableOn August 17, 2022, we announced a realignment of Contentsour 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,
The Beaumont Terminal in Nederland, Texas, is the largest terminal in the Phillips 66 portfolio. During 2017, we continued to invest in the terminal by adding 0.9 million barrels of crude storage capacity and 1.3 million barrels of products storage. At December 31, 2017, including these additions, the terminal capacity was 11.1 million barrels, of which 7.4 million barrels was crude oil storage capacity and 3.7 million barrels was refined product storage capacity. We have 3.5 million barrels of incremental crude storage capacity under construction that will be commissioned throughout 2018. In addition, during the fourth quarter of 2017, we completed expansion of the terminal’s export facilities from 400,000 to 600,000 barrels per day (BPD). We have also initiated a variety of other projects aimed at increasing storage and throughput capabilities as we continue the expansion of the Beaumont terminal to 16 million barrels.
The Bakken Pipeline went into commercial service in June 2017. The pipeline is approximately 1,915 miles long with an estimated capacity of 525,000 BPD at December 31, 2017. Phillips 66 Partners has a 25 percent interest in the Bakken Pipeline, through its 25 percent interests in both the Dakota Access and ETCO joint ventures. Energy Transfer Partners, L.P. (ETP) and MarEn Bakken Company LLC also have 38.25 percent and 36.75 percent interests, respectively, in the Bakken Pipeline, with ETP serving as the operator. The Dakota Access section of the Bakken Pipeline is approximately 1,172 miles long and delivers crude oil from the Bakken/Three Forks production area in North Dakota to a storage and terminaling hub outside of Patoka, Illinois, which includes an interconnection with the ETCO pipeline. The ETCO pipeline section of the Bakken Pipeline is approximately 743 miles long and transports crude oil from the Midwest to Phillips 66 and ETP storage terminals located in Nederland, Texas.
The Bayou Bridge Pipeline joint venture delivers crude oil from Nederland, Texas, to Lake Charles, Louisiana. At December 31, 2017, this pipeline had capacity of approximately 480,000 BPD. Phillips 66 Partners has a 40 percent interest in the joint venture, and ETP has a 60 percent interest and serves as the operator. The remaining section of the pipeline, which is being constructed, will deliver crude oil from Lake Charles to St. James, Louisiana, and is expected to be completed in the second half of 2018.
The Sacagawea Pipeline is owned by the joint venture Sacagawea Pipeline Company, LLC, in which Paradigm Pipeline LLC holds a 99 percent interest. Phillips 66 Partners and Paradigm Energy Partners, LLC each own a 50 percent interest in Paradigm Pipeline LLC. In August 2017, a new origin point for additional information on the Sacagawea Pipeline near New Town, North Dakota, was established, enabling crude to flow from this origin point to the Bakken Pipeline at Johnson’s Corner, Keene Terminal, Palermo Terminal,DCP Midstream and North Dakota Pipeline at Stanley, North Dakota.DCP LP Mergers.
Phillips 66 Partners Merger On March 9, 2022, we completed the merger between us and Plains All American Pipeline, L.P. each ownPhillips 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 50 percentwholly 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 STACK Pipeline LLC joint venture, which ownsSouth 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 operates astorage services. These assets include crude oil, storage terminalrefined petroleum product, NGL, and a common carriernatural gas pipeline that transportssystems; crude oil, from the Sooner Trend, Anadarko Basin, Canadianrefined petroleum product and Kingfisher Counties (STACK) play in northwestern Oklahoma to Cushing, Oklahoma. During the fourth quarter of 2017, this joint venture completed an expansion project to loop the existing pipelineNGL terminals; a petroleum coke handling facility; marine vessels; railcars and extend further into the STACK play, which increased capacity by 150,000 BPD.trucks.
Pipelines and Terminals
The following table depicts our ownership interest in major pipeline systems as ofincluded in our Transportation business at December 31, 2017:2023: | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | |
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| | | | | | | | | | | | | | | | Name | | Origination/Terminus | | Interest |
| | Size | | Length (Miles) |
| | Gross Capacity (MBD) |
| | Crude and Feedstocks | | | | | | | | | | | | Bakken Pipeline † | | North Dakota/Nederland, TX
| | 25 | % | | 30” | | 1,915 |
| | 525 |
| | Bayou Bridge † | | Nederland, TX/Lake Charles, LA | | 40 |
| | 30” | | 49 |
| | 480 |
| | Clifton Ridge † | | Clifton Ridge, LA/Westlake, LA | | 100 |
| | 20” | | 10 |
| | 260 |
| | Cushing † | | Cushing, OK/Ponca City, OK | | 100 |
| | 18” | | 62 |
| | 130 |
| | Eagle Ford Gathering † | | Helena, TX | | 100 |
| | 6” | | 6 |
| | 20 |
| | Eagle Ford Gathering † | | Tilden, TX/Whitsett, TX | | 100 |
| | 6”-10” | | 22 |
| | 34 |
| | Glacier † | | Cut Bank, MT/Billings, MT | | 79 |
| | 8”-12” | | 865 |
| | 126 |
| | Line O † | | Cushing, OK/Borger, TX | | 100 |
| | 10” | | 276 |
| | 37 |
| | Line 80 † | | Gaines, TX/Borger, TX | | 100 |
| | 8”, 12” | | 237 |
| | 28 |
| | Line 100 | | Taft, CA/Lost Hills, CA | | 100 |
| | 8”, 10”, 12” | | 79 |
| | 54 |
| | Line 200 | | Lost Hills, CA/Rodeo, CA | | 100 |
| | 12”, 16” | | 228 |
| | 93 |
| | Line 300 | | Nipomo, CA/Arroyo Grande, CA | | 100 |
| | 8”, 10”, 12” | | 69 |
| | 48 |
| | Line 400 | | Arroyo Grande, CA/Lost Hills, CA | | 100 |
| | 8”, 10”, 12” | | 147 |
| | 40 |
| | Louisiana Crude Gathering | | Rayne, LA/Westlake, LA | | 100 |
| | 4”-8” | | 80 |
| | 25 |
| | North Texas Crude † | | Wichita Falls, TX | | 100 |
| | 2”-16” | | 224 |
| | 28 |
| | Oklahoma Mainline † | | Wichita Falls, TX/Ponca City, OK | | 100 |
| | 12” | | 217 |
| | 100 |
| | Sacagawea † | | Keene, ND/Stanley, ND | | 50 |
| | 16” | | 95 |
| | 175 |
| | STACK PL † | | Cashion, OK/Cushing, OK | | 50 |
| | 8”-16” | | 149 |
| | 250 |
| | Sweeny Crude | | Sweeny, TX/Freeport, TX | | 100 |
| | 12”, 24”, 30” | | 56 |
| | 265 |
| | WA Line † | | Odessa, TX/Borger, TX | | 100 |
| | 12”, 14” | | 289 |
| | 104 |
| | West Texas Gathering † | | Permian Basin | | 100 |
| | 4”-14” | | 757 |
| | 115 |
| | Petroleum Products | | | | | | | | | | | | ATA Line † | | Amarillo, TX/Albuquerque, NM | | 50 |
| | 6”, 10” | | 293 |
| | 34 |
| | Borger to Amarillo † | | Borger, TX/Amarillo, TX | | 100 |
| | 8”, 10” | | 93 |
| | 76 |
| | Borger-Denver | | McKee, TX/Denver, CO | | 70 |
| | 6”-12” | | 405 |
| | 38 |
| | Cherokee East † | | Medford, OK/Mount Vernon, MO | | 100 |
| | 10”, 12” | | 287 |
| | 55 |
| | Cherokee North † | | Ponca City, OK/Arkansas City, KS | | 100 |
| | 10” | | 29 |
| | 57 |
| | Cherokee South † | | Ponca City, OK/Oklahoma City, OK | | 100 |
| | 8” | | 90 |
| | 46 |
| | Cross Channel Connector † | | Pasadena, TX/Galena Park, TX | | 100 |
| | 20” | | 5 |
| | 180 |
| | Explorer † | | Texas Gulf Coast/Chicago, IL | | 22 |
| | 24”, 28” | | 1,830 |
| | 660 |
| | Gold Line † | | Borger, TX/East St. Louis, IL | | 100 |
| | 8”-16” | | 681 |
| | 120 |
| | Harbor | | Woodbury, NJ/Linden, NJ | | 33 |
| | 16” | | 80 |
| | 171 |
| | Heartland* | | McPherson, KS/Des Moines, IA | | 50 |
| | 8”, 6” | | 49 |
| | 30 |
| | LAX Jet Line | | Wilmington, CA/Los Angeles, CA | | 50 |
| | 8” | | 19 |
| | 50 |
| | Los Angeles Products | | Torrance, CA/Los Angeles, CA | | 100 |
| | 6”, 12” | | 22 |
| | 112 |
| | Paola Products † | | Paola, KS/Kansas City, KS | | 100 |
| | 8”, 10” | | 106 |
| | 96 |
| | Pioneer | | Sinclair, WY/Salt Lake City, UT | | 50 |
| | 8”, 12” | | 562 |
| | 63 |
| | Richmond | | Rodeo, CA/Richmond, CA | | 100 |
| | 6” | | 14 |
| | 26 |
| | SAAL † | | Amarillo, TX/Abernathy, TX | | 33 |
| | 6” | | 102 |
| | 33 |
| | SAAL † | | Abernathy, TX/Lubbock, TX | | 54 |
| | 6” | | 19 |
| | 30 |
| | Seminoe † | | Billings, MT/Sinclair, WY | | 100 |
| | 6”-10” | | 342 |
| | 33 |
| | Standish † | | Marland Junction, OK/Wichita, KS | | 100 |
| | 18” | | 92 |
| | 72 |
| | Sweeny to Pasadena † | | Sweeny, TX/Pasadena, TX | | 100 |
| | 12”, 18” | | 120 |
| | 294 |
| | Torrance Products | | Wilmington, CA/Torrance, CA | | 100 |
| | 10”, 12” | | 8 |
| | 161 |
| | Watson Products Line | | Wilmington, CA/Long Beach, CA | | 100 |
| | 20” | | 9 |
| | 238 |
| | Yellowstone | | Billings, MT/Moses Lake, WA | | 46 |
| | 6”-10” | | 710 |
| | 66 |
|
| | | | | | | | | | | | | | | | Name | | Origination/Terminus | | Interest |
| | Size | | Length (Miles) |
| | Gross Capacity (MBD) |
| | NGL | | | | | | | | | | | | Chisholm | | Kingfisher, OK/Conway, KS | | 50 | % | | 4”-10” | | 202 |
| | 42 |
| | Powder River | | Sage Creek, WY/Borger, TX | | 100 |
| | 6”-8” | | 705 |
| | 14 |
| | River Parish NGL † | | Southeast Louisiana | | 100 |
| | 4”-20” | | 510 |
| | 133 |
| | Sand Hills**† | | Permian Basin/Mont Belvieu, TX | | 33 |
| | 20” | | 1,190 |
| | 315 |
| | Skelly-Belvieu | | Skellytown, TX/Mont Belvieu, TX | | 50 |
| | 8” | | 571 |
| | 45 |
| | Southern Hills**† | | U.S. Midcontinent/Mont Belvieu, TX | | 33 |
| | 20” | | 941 |
| | 140 |
| | Sweeny NGL | | Brazoria, TX/Sweeny, TX | | 100 |
| | 20” | | 18 |
| | 204 |
| | TX Panhandle Y1/Y2 | | Sher-Han, TX/Borger, TX | | 100 |
| | 3”-10” | | 299 |
| | 61 |
| | LPG | | | | | | | | | | | | Blue Line | | Borger, TX/East St. Louis, IL | | 100 |
| | 8”-12” | | 688 |
| | 29 |
| | Brown Line † | | Ponca City, OK/Wichita, KS | | 100 |
| | 8”, 10” | | 76 |
| | 26 |
| | Conway to Wichita | | Conway, KS/Wichita, KS | | 100 |
| | 12” | | 55 |
| | 38 |
| | Medford † | | Ponca City, OK/Medford, OK | | 100 |
| | 4”-6” | | 42 |
| | 10 |
| | Sweeny LPG Lines | | Sweeny, TX/Mont Belvieu & Freeport, TX | | 100 |
| | 10”-20” | | 246 |
| | 942 |
| | Natural Gas | | | | | | | | | | | | Rockies Express*** | | | | | | | | | | | | West to East | | Meeker, CO/Clarington, OH | | 25 |
| | 36”-42” | | 1,712 |
| | 1.8 Bcf/d |
| | East to West | | Clarington, OH/Moultrie, IL | | 25 |
| | 24”, 42” | | 670 |
| | 2.6 Bcf/d |
|
† Owned by Phillips 66 Partners; Phillips 66 held a 57 percent ownership interest in Phillips 66 Partners at December 31, 2017. | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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. ** Operated by DCP Midstream, LP; Phillips 66 Partners holds a direct one-third ownership interest in the pipeline entities. *** Total pipeline system consists of three zones for a total of 1,712 miles. The third zone of the pipeline is bi-directionalbidirectional for 661 miles and can transport 2.6 Bcf/d of natural gas from east-to-west.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 finished product terminals as of December 31, 2017: | | | | | | | | | | | | | | Facility Name | | Location | | Interest |
| | Gross Storage Capacity (MBbl) |
| | Gross Rack Capacity (MBD) |
| | Albuquerque † | | New Mexico | | 100 | % | | 244 |
| | 18 |
| | Amarillo † | | Texas | | 100 |
| | 277 |
| | 29 |
| | Beaumont | | Texas | | 100 |
| | 3,700 |
| | 8 |
| | Billings | | Montana | | 100 |
| | 88 |
| | 16 |
| | Bozeman | | Montana | | 100 |
| | 113 |
| | 13 |
| | Casper † | | Montana | | 100 |
| | 365 |
| | 7 |
| | Colton | | California | | 100 |
| | 211 |
| | 21 |
| | Denver | | Colorado | | 100 |
| | 310 |
| | 43 |
| | Des Moines | | Iowa | | 50 |
| | 206 |
| | 15 |
| | East St. Louis † | | Illinois | | 100 |
| | 2,085 |
| | 78 |
| | Glenpool † | | Oklahoma | | 100 |
| | 588 |
| | 19 |
| | Great Falls | | Montana | | 100 |
| | 198 |
| | 12 |
| | Hartford † | | Illinois | | 100 |
| | 1,075 |
| | 25 |
| | Helena | | Montana | | 100 |
| | 178 |
| | 10 |
| | Jefferson City † | | Missouri | | 100 |
| | 110 |
| | 16 |
| | Kansas City † | | Kansas | | 100 |
| | 1,294 |
| | 66 |
| | La Junta | | Colorado | | 100 |
| | 101 |
| | 10 |
| | Lincoln | | Nebraska | | 100 |
| | 219 |
| | 21 |
| | Linden † | | New Jersey | | 100 |
| | 429 |
| | 121 |
| | Los Angeles | | California | | 100 |
| | 116 |
| | 75 |
| | Lubbock † | | Texas | | 100 |
| | 179 |
| | 17 |
| | Missoula | | Montana | | 50 |
| | 368 |
| | 29 |
| | Moses Lake | | Washington | | 50 |
| | 186 |
| | 13 |
| | Mount Vernon † | | Missouri | | 100 |
| | 363 |
| | 46 |
| | North Salt Lake | | Utah | | 50 |
| | 738 |
| | 41 |
| | Oklahoma City † | | Oklahoma | | 100 |
| | 352 |
| | 48 |
| | Pasadena † | | Texas | | 100 |
| | 3,210 |
| | 65 |
| | Ponca City † | | Oklahoma | | 100 |
| | 51 |
| | 23 |
| | Portland | | Oregon | | 100 |
| | 664 |
| | 33 |
| | Renton | | Washington | | 100 |
| | 228 |
| | 20 |
| | Richmond | | California | | 100 |
| | 334 |
| | 28 |
| | Rock Springs | | Wyoming | | 100 |
| | 125 |
| | 19 |
| | Sacramento | | California | | 100 |
| | 141 |
| | 13 |
| | Sheridan † | | Wyoming | | 100 |
| | 86 |
| | 15 |
| | Spokane | | Washington | | 100 |
| | 351 |
| | 24 |
| | Tacoma | | Washington | | 100 |
| | 307 |
| | 17 |
| | Tremley Point † | | New Jersey | | 100 |
| | 1,593 |
| | 39 |
| | Westlake | | Louisiana | | 100 |
| | 128 |
| | 16 |
| | Wichita Falls | | Texas | | 100 |
| | 303 |
| | 15 |
| | Wichita North † | | Kansas | | 100 |
| | 679 |
| | 19 |
|
† Owned by Phillips 66 Partners; Phillips 66 held a 57 percent ownership interestmarine, rail and petroleum coke loading and offloading facilities included in Phillips 66 Partnersour Transportation business at December 31, 2017.2023:
The following table depicts our ownership interest in crude and other terminals as of December 31, 2017: | | | | | | | | | | | | | | Facility Name | | Location | | Interest |
| | Gross Storage Capacity (MBbl) |
| | Gross Loading Capacity* |
| | Crude and Feedstocks | | | | | | | | | | Beaumont | | Texas | | 100 | % | | 7,400 |
| | N/A |
| | Billings † | | Montana | | 100 |
| | 270 |
| | N/A |
| | Borger | | Texas | | 50 |
| | 721 |
| | N/A |
| | Clifton Ridge † | | Louisiana | | 100 |
| | 3,410 |
| | N/A |
| | Cushing † | | Oklahoma | | 100 |
| | 700 |
| | N/A |
| | Freeport | | Texas | | 100 |
| | 2,144 |
| | N/A |
| | Jones Creek | | Texas | | 100 |
| | 2,577 |
| | N/A |
| | Junction | | California | | 100 |
| | 523 |
| | N/A |
| | Keene † | | North Dakota | | 50 |
| | 490 |
| | N/A |
| | McKittrick | | California | | 100 |
| | 237 |
| | N/A |
| | Odessa † | | Texas | | 100 |
| | 523 |
| | N/A |
| | Palermo † | | North Dakota | | 70 |
| | 206 |
| | N/A |
| | Pecan Grove † | | Louisiana | | 100 |
| | 142 |
| | N/A |
| | Ponca City † | | Oklahoma | | 100 |
| | 1,200 |
| | N/A |
| | Santa Margarita | | California | | 100 |
| | 335 |
| | N/A |
| | Santa Maria | | California | | 100 |
| | 112 |
| | N/A |
| | Tepetate | | Louisiana | | 100 |
| | 152 |
| | N/A |
| | Torrance | | California | | 100 |
| | 309 |
| | N/A |
| | Wichita Falls † | | Texas | | 100 |
| | 240 |
| | N/A |
| | Petroleum Coke | | | | | | | | | | Lake Charles | | Louisiana | | 50 |
| | N/A |
| | N/A |
| | Rail | | | | | | | | | | Bayway † | | New Jersey | | 100 |
| | N/A |
| | 75 |
| | Beaumont | | Texas | | 100 |
| | N/A |
| | 20 |
| | Ferndale † | | Washington | | 100 |
| | N/A |
| | 30 |
| | Missoula | | Montana | | 50 |
| | N/A |
| | 41 |
| | Palermo † | | North Dakota | | 70 |
| | N/A |
| | 100 |
| | Thompson Falls | | Montana | | 50 |
| | N/A |
| | 42 |
| | Marine | | | | | | | | | | Beaumont | | Texas | | 100 |
| | N/A |
| | 37 |
| | Clifton Ridge † | | Louisiana | | 100 |
| | N/A |
| | 48 |
| | Hartford † | | Illinois | | 100 |
| | N/A |
| | 3 |
| | Pecan Grove † | | Louisiana | | 100 |
| | N/A |
| | 6 |
| | Portland | | Oregon | | 100 |
| | N/A |
| | 10 |
| | Richmond | | California | | 100 |
| | N/A |
| | 3 |
| | Tacoma | | Washington | | 100 |
| | N/A |
| | 12 |
| | Tremley Point † | | New Jersey | | 100 |
| | N/A |
| | 7 |
| | NGL Facilities | | | | | | | | | | Freeport | | Texas | | 100 |
| | 1,000 |
| | 36 |
| | River Parish † | | Louisiana | | 100 |
| | 1,500 |
| | N/A |
| | Clemens † | | Texas | | 100 |
| | 9,000 |
| | N/A |
|
† Owned by Phillips 66 Partners; Phillips 66 held a 57 percent ownership interest in Phillips 66 Partners at December 31, 2017. | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 and NGL Facilities in thousands of barrels per hour..
Rockies Express Pipeline LLC (REX)
We own a 25 percent interest in REX, which owns a natural gas pipeline system with approximately 1,712 miles of transportation pipelines, including laterals, extending from Opal, Wyoming, and Meeker, Colorado, to Clarington, Ohio. The REX Pipeline delivers natural gas to markets, primarily in the Midwest, from both the Rocky Mountain region and the Appalachian Basin.
Marine Vessels At December 31, 2017,2023, we had 11 international-flagged crude oil, refined petroleum product and productNGL tankers under time charter contracts, with capacities ranging in size from 300,000 to 1,100,000 barrels. Additionally, we had under time charter contract two Jones Act-compliant tankersa variety of inland and 38offshore tug/barge units. These vessels are used primarily to transport feedstocks or provide product transportation for certain of our refineries, including delivery of domestic crude oil 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 Gulf Coastfractionation, transportation and East Coast refineries.storage infrastructure.
Truck and Rail Our truck and rail fleets support our feedstock and distribution operations. Rail movements are provided via a fleet of more than 10,000approximately 9,600 owned andor leased railcars. Truck movements are provided through our wholly owned subsidiary, Sentinel Transportation LLC, and through numerous third-party trucking companies, as well as through our 100-percent-owned subsidiary, Sentinel Transportation LLC.companies.
NGL and Other
OurAt December 31, 2023, our NGL and Other business includeswas comprised of natural gas processing plants, NGL and natural gas pipeline systems, and fractionators in the following: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.
ANatural 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, comprising the Freeport LPG Export Terminalconsisting of four fractionators with a total fractionation nameplate capacity of 550,000 BPD, a liquified petroleum gas (LPG) export terminal, and Phillips 66 Partners’ 100,000 BPD Sweeny Fractionator. These assetsNGL storage caverns. The fractionators are supported by 9 million barrels of gross capacity at Phillips 66 Partners’ Clemens storage facility. We refer to these facilities as the “Sweeny Hub.”
A 22.5 percent interest in Gulf Coast Fractionators, which owns an NGL fractionation plant in Mont Belvieu, Texas. We operate the facility, and our net share of its capacity is 32,625 BPD.
A 12.5 percent undivided interest in a fractionation plant in Mont Belvieu, Texas. Our net share of its capacity is 30,250 BPD.
A 40 percent undivided interest in a fractionation plant in Conway, Kansas. Our net share of its capacity is 43,200 BPD.
Phillips 66 Partners owns the River Parish NGL logistics system in southeast Louisiana, comprising approximately 500 miles of pipelines and a storage cavern connecting multiple fractionation facilities, refineries and a petrochemical facility.
Phillips 66 Partners owns a direct one-third interest in both the DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC, which own pipelines that connect Eagle Ford, Permian and Midcontinent production to the Mont Belvieu, Texas, market.
Phillips 66 Partners, through its ownership of MSLP, owns a 125,000 BPD capacity vacuum distillation unit and a 70,000 BPD capacity delayed coker unit located at our Sweeny Refinery in Old Ocean, Texas.
The Sweeny Fractionator is located adjacent to our Sweeny Refinery in Old Ocean, Texas, and suppliessupply purity ethane to the petrochemical industry and LPGpurity NGL to domestic and global markets. Raw NGL supply to the fractionatorfractionators is delivered from nearby major pipelines, including the DCP Sand Hills Pipeline. The fractionator isfractionators are supported by significant infrastructure including connectivity to two NGL supply pipelines, a pipeline connecting to the Mont Belvieu market centerhub and a multi-million-barrel salt domethe 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 two ships with refrigerateda propane vessel and a butane atvessel, and has a combined rateLPG export capacity of 36,000 barrels per hour. In support of the terminal, a 100,000 BPD unit to upgrade domestic propane for export was installed near the Sweeny Fractionator.260,000 BPD. In addition, the terminal exports 10,000has the capability to 15,000 BPD ofexport natural gasoline (C5+) produced atby the Sweeny Fractionator.Hub fractionators.
MSLP processes long residue, which is produced from heavy sour crude oil, for a processing fee. The fuel-grade petroleum coke and other by-products produced as a result of the processing are retained by our Sweeny Refinery.
During 2017, Phillips 66 Partners continued development of a new 25,000 BPD isomerization unit atThe following table depicts our Lake Charles Refinery to increase production of higher octane gasoline blend components. The project is expected to be completed by the end of 2019.
DCP Midstream
Our Midstream segment includes our 50 percent equity investmentownership interest in DCP Midstream, which is headquartered in Denver, Colorado. As of December 31, 2017, DCP Midstream owned or operated 61 natural gas processing facilities, with a net processing capacity of approximately 7.8 billion cubic feet per day (Bcf/d). DCP Midstream’s owned or operated natural gasmajor pipeline systems included gathering services for these facilities,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 natural gas transmission,its 86.8% aggregate direct and totaled approximately 63,000 miles of pipeline.indirect economic interest in DCP Midstream also owned or operated 12 NGL fractionation plants, along with natural gasLP, which owns a direct two-thirds interest.
The following table depicts our ownership interest in terminal and NGL 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 propane wholesale marketingmarine facility included in our NGL and Other business and NGL pipeline assets.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 residual natural gas, primarily methane, which results from processing raw natural gas, is soldfollowing 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 Midstream at market-based pricesLP. 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 marketers and end users, including large industrial companies, natural gas distribution companies and electric utilities. DCP Midstream purchases or takes custody of substantially all of its raw natural gas from producers, principally under contractual arrangements that expose DCP Midstream to the prices of NGL, natural gas and condensate. DCP Midstream also has fee-based arrangements with producers to provide midstream services such as gathering and processing.
DCP Midstream markets a portion of its NGL to us and CPChem under existing contracts. The primary commitment on certain contracts began a ratable wind-down periodrestart in December 2014 and expires in January 2019. These purchase commitments are on an “if-produced, will-purchase” basis.
During 2017, DCP Midstream completed or advanced the following growth projects:
In the first quarter of 2017, DCP Midstream announced the construction of a 200-million-cubic-feet-per-day (MMcf/d) natural gas processing plant, the Mewbourn 3 plant, and further expansion of its Grand Parkway gathering system. Both are located in the Denver-Julesburg (DJ) Basin and are expected to be in service in the third quarter of 2018.
In the second quarter of 2017,2024.
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 Midstream approved the 200 MMcf/d O'Connor 2 natural gas processing plant in the DJ Basin. The O'Connor 2 plantLP’s proportional ownership. At December 31, 2023, Phillips 66 held an aggregate 86.8% direct and associated gathering infrastructure are expected to be in service in 2019. In the second quarter of 2017, DCP Midstream increased capacity in the DJ Basin by up to 40 MMcf/d by placing additional field compression and plant bypass infrastructure in service.
In the third quarter of 2017, DCP Midstream executed definitive joint-venture agreements on its 25 percentindirect economic interest in the developmentDCP 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 the Gulf Coast Express pipeline project (GCX project). The GCX project is designed to transport up to 1.98 Bcf/d of natural gas. The mostly 42-inch pipeline would traverse approximately 500 miles and be placed in service in 2019, pending regulatory approvals.synthetic graphite production capacity at NOVONIX’s Chattanooga, Tennessee, plant. DCP Midstream is jointly developing the Cheyenne Connector pipeline with Tallgrass Energy Partners, LP (Tallgrass) and Western Gas Partners, LP (Western Gas). Tallgrass serves as the operator, and both DCP Midstream and Western Gas hold an option to invest in this pipeline at a later date. The Cheyenne Connector pipeline will provide takeaway solutions with capacity of at least 600 MMcf/d for DCP Midstream's DJ Basin assets, connecting natural gas to REX’s Cheyenne Hub, where it can then be delivered to numerous demand markets across the country.
DCP Midstream is currently expanding the Sand Hills Pipeline to 365,000 BPD, which is expected to be completed in the first quarter of 2018. Further expansion to 450,000 BPD is progressing and is expected to be in service during the second half of 2018. This expansion includes a partial looping of the pipeline and the addition of new pump stations.
Effective January 1, 2017, DCP Midstream and its master limited partnership (then named DCP Midstream Partners, LP, subsequently renamed DCP Midstream, LP on January 11, 2017, and referred to herein as DCP Partners) closed a transaction in which DCP Midstream contributed subsidiaries owning all of its operating assets and its existing debt to DCP Partners, in exchange for approximately 31.1 million DCP Partners units. Following the transaction, we and our co-venturer retained our 50/50 investment in DCP Midstream, DCP Midstream retained its incentive distribution rights in DCP Partners through its ownership of the general partner of DCP Partners, and DCP Midstream held a 36 percent limited partner interest and a 2 percent general partner interest in DCP Partners. See the “Equity Affiliates” section of “Significant Sources of Capital” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information on this transaction.
CHEMICALS
The Chemicals segment consists of our 50 percent50% equity investment in CPChem, which is headquartered in The Woodlands, Texas. At the end of 2017,December 31, 2023, CPChem owned or had joint-venturejoint venture interests in 30 global manufacturing facilities located in Belgium, Colombia, Qatar, Saudi Arabia, Singapore and the United States. Additionally, CPChem has two U.S. research and development centers.centers in the United States.
We structure our reporting of CPChem’s operations around two primary business segments: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P business segmentCPChem produces and markets ethylene and other olefin products; theproducts. The ethylene produced is primarily consumed withinused by CPChem for the production ofto produce polyethylene, normal alpha olefins (NAO) and polyethylene pipe. The SA&S business segmentCPChem manufactures and markets aromatics and styrenics products, such as benzene, cyclohexane, styrene paraxylene and cyclohexane,polystyrene, as well as polystyrene. SA&S also manufactures and/or markets a variety of specialty chemical products including organosulfur chemicals, solvents, catalysts, and chemicals used in drilling chemicals and mining chemicals.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 fromby cracking the feedstocks ethane, propane, butane, natural gasoline or certain refinery liquids, such as naphtha and gas oil. The produced ethylene has a number of uses,Ethylene primarily is used as a raw material in the production of plastics, such as polyethylene and polyvinyl chloride.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.
CPChem and its equity affiliates have manufacturing facilities located in Belgium, China, Colombia, Qatar, Saudi Arabia, Singapore and the United States.
The following table reflects CPChem’s petrochemicals and plastics product capacities at December 31, 2017:2023: | | | | | | | | | | | | | | 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 | |
| | | | | | | | | Millions of Pounds per Year | | | | U.S. |
| | Worldwide |
| | O&P | | | | | Ethylene | 8,110 |
| | 10,585 |
| | Propylene | 2,675 |
| | 3,180 |
| | High-density polyethylene | 5,305 |
| | 7,600 |
| | Low-density polyethylene | 620 |
| | 620 |
| | Linear low-density polyethylene | 1,590 |
| | 1,590 |
| | Polypropylene | — |
| | 310 |
| | Normal alpha olefins | 2,335 |
| | 2,850 |
| | Polyalphaolefins | 125 |
| | 255 |
| | Polyethylene pipe | 590 |
| | 590 |
| | Total O&P | 21,350 |
| | 27,580 |
| | | | | | | SA&S | | | | | Benzene | 1,600 |
| | 2,530 |
| | Cyclohexane | 1,060 |
| | 1,455 |
| | Paraxylene | 1,000 |
| | 1,000 |
| | Styrene | 1,050 |
| | 1,875 |
| | Polystyrene | 835 |
| | 1,070 |
| | Specialty chemicals | 439 |
| | 574 |
| | Total SA&S | 5,984 |
| | 8,504 |
| | Total O&P and SA&S | 27,334 |
| | 36,084 |
|
* Capacities include CPChem’s share in equity affiliates and excludes CPChem’s NGL fractionation capacity.
In 2017,During 2023, CPChem continuedcompleted construction and began operations of two polyethylenea 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 and an ethane cracker inon the U.S. Gulf Coast region. This project leveragesand in Ras Laffan, Qatar. On the development ofU.S. Gulf Coast, the significant shale resources in the United States. The polyethylene facilities successfully completed commissioning and start-up in September 2017. The two polyethylene units, each with an annual capacity of 1.1Golden Triangle Polymers (GTP) facility will include a 4.6 billion pounds, are located near CPChem’s Sweeny facility in Old Ocean, Texas. CPChem’s Cedar Bayou facility in Baytown, Texas, is the location of the 3.3 billion-pound-per-year ethane cracker. Mechanical completion of the ethane cracker was achieved in December 2017, and commissioning is expected to be completed in the first quarter of 2018, with a transition to full production during the second quarter of 2018. In February 2017, CPChem completed the sale of its K-Resin® styrene-butadiene copolymers (SBC) business, which included the K-Resin® SBC plant in the Yeosu Petrochemical Complex in South Korea.
In April 2017, CPChem completed expansion of the polyalphaolefins capacity at its Cedar Bayou plant by 20 million pounds per year or 20 percent. This expansion, togetherethane 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 NAOjoint 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 addedof 3.7 billion pounds per year. CPChem owns a 30% equity share in 2015, allows CPChemthe joint venture. Both facilities are expected to meet the increasing demand for high-performance lubricants feedstocks. start up in 2026.
In October 2017, CPChem completed the sale of its equity investment in Petrochemical Conversion Company, which included nylon 6,6, nylon compounding, and polymer conversion assets.
REFINING
Our Refining segment refines crude oil and other feedstocks into petroleum products, (suchsuch as gasoline, distillates and aviation fuels) at 13fuels, 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 U.S.owned and internationaljoint venture refineries at December 31, 2017:2023: | | | | | | | | | Thousands of Barrels Daily | | | | | | | Thousands of Barrels Daily | | | | Region/Refinery | | Location | | Interest |
| | Net Crude Throughput Capacity | | Net Clean Product Capacity** | | Clean Product Yield Capability |
| Region/Refinery | | Location | | Interest | | Net Crude Throughput
Capacity | | Net Clean Product
Capacity** | | Clean
Product
Yield
Capability | At December 31 2017 |
| Effective January 1 2018 |
| | Gasolines |
| | Distillates |
| | | Atlantic Basin/Europe | | | | | | | | | | | | Atlantic Basin/Europe | | | Atlantic Basin/Europe | | | Bayway | | | Bayway | | | Bayway | | Linden, NJ | | 100.00 | % | | 241 |
| 258 |
| | 155 |
| | 130 |
| | 92 | % | | Linden, NJ | | 100 | % | | 258 | | 258 | 258 | | | 155 | | 155 | | | 130 | | 130 | | | 92 | | 92 | % | | Humber | | N. Lincolnshire, United Kingdom | | 100.00 |
| | 221 |
| 221 |
| | 95 |
| | 115 |
| | 81 |
| | MiRO* | | Karlsruhe, Germany | | 18.75 |
| | 58 |
| 58 |
| | 25 |
| | 25 |
| | 87 |
| | | | | | 520 |
| 537 |
| | | | | | | | | | | | | 537 | | | | | | | | | | | | | | | Gulf Coast | | | | | | | | | | | | Alliance | | Belle Chasse, LA | | 100.00 |
| | 247 |
| 247 |
| | 130 |
| | 120 |
| | 87 |
| | | Gulf Coast | | | | Gulf Coast | | | | Lake Charles | | | | Lake Charles | | | | Lake Charles | | Westlake, LA | | 100.00 |
| | 249 |
| 249 |
| | 100 |
| | 115 |
| | 70 |
| | Sweeny | | Old Ocean, TX | | 100.00 |
| | 247 |
| 256 |
| | 135 |
| | 120 |
| | 86 |
| | | | | | 743 |
| 752 |
| | | | | | | | | | | | | 529 | | | | | | | | | | | | | | | Central Corridor | | | | | | | | | | | | | Central Corridor | | | | Central Corridor | | | Ponca City | | | Ponca City | | | Ponca City | | | Billings | | | Wood River | | Roxana, IL | | 50.00 |
| | 157 |
| 157 |
| | 85 |
| | 60 |
| | 81 |
| | Borger | | Borger, TX | | 50.00 |
| | 73 |
| 73 |
| | 50 |
| | 30 |
| | 91 |
| | Ponca City | | Ponca City, OK | | 100.00 |
| | 203 |
| 203 |
| | 120 |
| | 95 |
| | 93 |
| | Billings | | Billings, MT | | 100.00 |
| | 60 |
| 60 |
| | 35 |
| | 30 |
| | 90 |
| | | | | | | 531 | | | | | | | 493 |
| 493 |
| | | | | | | | West Coast | | | | West Coast | | | | | | | | | | | | | | | West Coast | | | | | | | | | | | | Ferndale | | Ferndale, WA | | 100.00 |
| | 101 |
| 105 |
| | 65 |
| | 35 |
| | 81 |
| | Ferndale | | | Ferndale | | | Los Angeles | | Carson/Wilmington, CA | | 100.00 |
| | 139 |
| 139 |
| | 85 |
| | 65 |
| | 90 |
| | San Francisco | | Arroyo Grande/San Francisco, CA | | 100.00 |
| | 120 |
| 120 |
| | 60 |
| | 65 |
| | 85 |
| | | | | | 360 |
| 364 |
| | | | | | | | | | | | 2,116 |
| 2,146 |
| | | | | | | | San Francisco*** | | | | | | | | 296 | | | | | | | | 1,893 | | | | | | | | 1,893 | | | | | | | | 1,893 | |
* 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 | | | | | | | | | | Characteristics | | Sources | | Sweet | Medium
Heavy
Sour | Heavy
Sour
| High TAN* | | United
States | United
States
Canada | CanadaSouth and Central
America | South
America
Europe | Europe | Middle East
& Africa
| | Bayway | l | l | | | | l | l | l
| l | | | l | | Humber | l | | l | l | | l | | | l | l | | | l | l | | MiRO | l | l | l | | | l | | | l | | | | l | l | | Alliance | | | | | | | | | | | Lake Charles | l | l | l | l | | l | l | l | l | | l | Lake CharlesSweeny | l | l | l | l | | l | l | l | l | | | Wood River | l | | l | l | | l | l | | | | | Borger | l | l | l | | | l | l | | | | SweenyPonca City | l | l | l | l | | l | l | | l | l | | | Wood RiverBillings | l | l | l | l | | l | l | l | | | | BorgerFerndale | l | l | l | | | l | l | l | | | l | Ponca CityLos Angeles | l | l | l | l | | l | l | l | | | l | Billings | | l | l | l | | | l | | | | Ferndale | l | l | | | | l | l | | | | Los Angeles | | l | l | l | | l | l | l | | l | San Francisco** | l | l | l | l | | l | l | l | 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 railcar and truck.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, United Kingdom.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, which produce high-value graphite and anode petroleum cokes. The refinery produces a high percentage of transportation fuels.plants. Humber is the only coking refinery in the United Kingdom, and a major producer of high-quality specialty graphite cokes and anode coke. Approximately 70 percentanode-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 tothroughout the rest of Europe, West Africa and the United States by waterborne cargo.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 percent18.75% 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, anode-gradeand anode- and fuel-grade petroleum coke andcokes. Refined petroleum coke. Refined products are distributed to customers in Germany, Switzerland, France, and Austria by truck, railcar and barge.
Gulf Coast Region
Alliance Refinery
The Alliance Refinery is located on the Mississippi River in Belle Chasse, Louisiana, approximately 25 miles southeast of New Orleans, Louisiana. The single-train facility includes crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrodesulfurization, aromatics and delayed coking units. Alliance produces a high percentage of transportation fuels. Other products include petrochemical feedstocks, home heating oil and anode-grade petroleum coke. Refined products are distributed to customers in the southeastern and eastern United States through major common-carrier pipeline systems and by barge. Refined products are exported primarily to customers in Latin America by waterborne cargo.
Lake Charles Refinery The Lake Charles Refinery is located in Westlake, Louisiana, approximately 150 miles east of Houston, Texas. Refinery facilities include crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrocracking, hydrodesulfurization, 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 M&SMarketing and Specialties (M&S) segment, and high-quality specialty graphite and fuel-grade petroleum coke and petroleum coke. Thecokes. 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. RefinedAdditionally, refined petroleum products are also exported primarily to customers primarily in Latin America and West AfricaEurope 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, and aromatics units, as well as access to the on-sitea vacuum towerdistillation unit, and a delayed coking unit, which effective October 2017 became an asset owned by Phillips 66 Partners.unit. The refinery produces a high percentage of transportation fuels. Other products include petrochemical feedstocks, home heating oil and fuel-grade petroleum coke. The refinery receives crude oil by pipeline and via tankers, through wholly and jointly owned terminals onA majority of the Gulf Coast, including a deepwater terminal at Freeport, Texas. Refinedrefined petroleum products are distributed to customers throughout the Midcontinent region, southeastern and eastern United States by pipeline, barge and railcar. RefinedAdditionally, refined petroleum products are also exported primarily 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 50/50 percent-owned joint venture with Cenovus Energy Inc., which consists ofthat 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 and are shipped to markets throughout the Midcontinent region.truck. •Borger Refinery The Borger Refinery is located in Borger, Texas, in the Texas Panhandle, approximately 50 miles north of Amarillo, Texas. Refinery facilities include crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrodesulfurization, and delayed coking units, as well as an NGL fractionation facility. Itunits. The refinery produces a high percentage of transportation fuels, as well as fuel-grade petroleum coke, NGL’sNGL and solvents. Refined petroleum products are distributed to customers via pipelines from the refinery toin West Texas, New Mexico, Colorado and the Midcontinent region.
region by company-owned and common carrier pipelines.
Ponca City Refinery
The Ponca City Refinery is located in Ponca City, Oklahoma, approximately 95 miles northwest of Tulsa, Oklahoma. Its facilities include crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrodesulfurization, and delayed coking units. It produces a high percentage of transportation fuels and anode-grade petroleum coke. Refined products are primarily distributed to customers by company-owned and common-carrier pipelines to markets throughout the Midcontinent region.
Billings Refinery
The Billings Refinery is located in Billings, Montana. Its facilities include crude distilling, naphtha reforming, fluid catalytic cracking, alkylation, hydrodesulfurization and delayed coking units. The refinery produces a high percentage of transportation fuels and petroleum coke. Finished petroleum products from the refinery are distributed to customers by pipeline, railcar and truck. Pipelines transport most of the refined products to markets in Montana, Wyoming, Idaho, Utah, Colorado and Washington.
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 by pipeline and barge to major markets in the northwest United States.States by pipeline and barge.
Los Angeles Refinery The Los Angeles Refinery consists of two facilities linked facilitiesby 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. TheRefinery 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 TheHistorically, our San Francisco Refinery consistsconsisted of two facilities linked by a 200-mile pipeline. Theour pipelines: the Santa Maria facility, is located in Arroyo Grande, California, 200 miles south of San Francisco, California, whileand the Rodeo facility, islocated in the San Francisco Bay Area. Semi-refined liquid products fromWe 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 are shipped by pipelineFacility, 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 for upgrading into finished petroleum products. Facilities includeby 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, as well as a calciner.units. The refinery produces a high percentage of transportation fuels. It also producesfuels, 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. AdditionalAdditionally, refined petroleum products are also 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, (suchsuch as gasolines,gasoline, distillates and aviation fuels),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, (suchsuch as base oils and lubricants), as well as power generation operations.lubricants.
Marketing
Marketing—United States In the United States, as of December 31, 2017, we marketedWe 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 7,550 independently owned7,260 branded outlets in 48 states. These sites utilize the Phillips 66, Conoco or 76 brands.states and Puerto Rico.
At December 31, 2017, ourOur wholesale operations utilizedutilize a network of marketers operating approximately 5,7005,090 outlets. We place a strong emphasis on the wholesale channel of trade because of its relatively lower capital requirements. In addition, we heldhold brand-licensing agreements covering approximately 1,0501,390 sites. Our refined petroleum products are marketed on both a branded and unbranded basis. A high percentage of our branded marketing sales are made in the Midcontinent, Rockies and West Coast regions, where our wholesale marketing operations providenetwork secures efficient off-takeofftake from our refineries. We continue toalso utilize consignment fuel arrangements with several marketers whereby we own the fuel inventory and pay the marketers a fixed monthly fee.
In the Gulf Coast and East Coast regions, most sales are conducted via the unbranded saleschannel of trade, which dodoes not require a highly integrated marketing and distribution infrastructurenetwork to secure product placement for refinery pull through. We are expanding ourhave export capability at our U.S. coastal refineries to meet growing international demand and increase flexibility to provide product to the highest-value markets.demand.
In addition to automotive gasoline and diesel, we produce and market jet fuel and aviation gasoline. At December 31, 2017, aviation gasoline and jet fuel. Aviation gasoline and jet fuel wereare sold through dealers and independent marketers at approximately 800 780 Phillips 66-branded locationsbranded locations.
We participate in joint ventures engaged in retail convenience store operations in the United States.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-venturejoint venture retail sites using a low-cost, high-volume approach. We use the JET brand name to market retail and wholesale products in Austria, Germany and the United Kingdom. In addition, a joint venture in which we have an equity interest in a joint venture that markets refined petroleum products in Switzerland under the COOPCoop brand name.
We also market aviation fuels, LPG, heating oils, transportation fuels, marine bunker fuels, bitumen and fuel coke specialtyother secondary refined products to commercial customers and into the bulk or spot markets in the above countries.
At December 31, 2017,2023, we had 1,324approximately 1,270 marketing outlets in our European operations,Europe, of which 993approximately 980 were company owned and 331approximately 290 were dealer owned. In addition,We had interests in 330 additional sites through our COOP joint-ventureCoop joint venture operations in Switzerland, and we have interestsheld brand-licensing agreements covering approximately 70 sites in 306 additional sites.Mexico.
Specialties
Lubricants We manufacture and sell a variety ofautomotive, commercial, industrial and specialty products, including petroleum coke products, waxes, solvents and polypropylene. Certain manufacturing operationslubricants which are included in the Refining segment, while the marketing function for these products is included in the Specialties business.
Premium Coke, Polypropylene & Solvents
We market high-quality graphite and anode-grade petroleum cokes in the United States, Europe and Asia for use in a variety of industries that include steel, aluminum, titanium dioxide and battery manufacturing. We also market polypropylene in North Americamarketed worldwide under the COPYLENE brand name for use in consumer products, Phillips 66, Kendall,Red Line and market specialty solvents that include pentane, iso-pentane, hexane, heptane and odorless mineral spirits for use in the petrochemical, agriculture and consumer markets.other private label brands.
Excel Paralubes
WeIn addition, we own a 50 percent50% interest in Excel Paralubes aLLC (Excel Paralubes), an operated joint venture whichthat owns a hydrocracked lubricant base oil manufacturing plant located adjacent to the Lake Charles Refinery. The facility has a nameplate capacity to produce 22,200 BPD of high-quality Group II clear hydrocracked base oils. Excel Paralubes markets the produced base oil under the Pure Performance brand. The facility’s feedstock is sourced primarily from our Lake Charles Refinery.
Lubricants
We manufacture
ENERGY RESEARCH & INNOVATION
Our Energy Research & Innovation organization, located in Bartlesville, Oklahoma, includes scientists and sell automotive, commercial, industrialengineers working in over 200 laboratories and specialty lubricants which are marketed worldwide under the 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 Kendall employees, our human capital, are guided by our values of safety, honor and Red Line brands,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 other private label brands. 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 Group II Pure Performance base oils globally,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 importindependent 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 Group III Ultra-S base oils through an agreement with South Korea’s S-Oil corporation.
Other
Power Generation
We own a cogeneration power plant located adjacent tohubs. In addition, the Sweeny Refinery. The plant generates electricity and provides process steam to the refinery, as well as merchant power into the Texas market. The plant has a net electrical output of 440 megawatts and is capable of generating up to 3.6 million pounds per hour of process steam.
TECHNOLOGY DEVELOPMENT
Our Technology organization conducts applied and fundamental research in three areas: 1) support for our current business, 2) new environmental solutions to address governmental regulations and 3) future growth. Technology programs include evaluating advantaged crudes; and modeling to reduce energy consumption, increase product yield and increase reliability. Our sustainability group is focusing efforts on organic photovoltaic polymers, solid oxide fuel cells, atmospheric modeling and air chemistry, water use and reuse and renewable fuels. Additionally, we monitor emerging technologies such as electric vehicles and impacts of the digital space on energy consumption, and perform research and monitoring of developments in battery technology.
COMPETITION
The Midstream segment through our equity investment in DCP Midstream and our other operations, competes with numerous integrated petroleum companies, as well as natural gas processing, transmission and distribution companies, to deliver components of natural gas and NGL to end users in commodity natural gas markets. DCP Midstream is one of the leading natural gas gatherers and processors in the United States based on wellhead volumes, and one of the largest U.S. producers and marketers of NGL, based on published industry sources.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.
In the Chemicals segment, CPChem is ranked among the top 10 producers of many of its major product lines according to published industry sources, based on average 2017 production capacity. Petroleum products, petrochemicals and plastics are typically delivered into the worldwide commodity markets. Our Refining and M&S segments compete primarily in the United States and Europe. We are one of the largest refiners of petroleum products in the United States based on published industry sources. Elements of competition for both our Chemicals and Refining segments include product improvement, new product development, low-cost structures, ability to source adequate feedstock supply and run advantaged feedstocks, and efficient manufacturing and distribution systems. In the marketing portion of the business,M&S segment, competitive factors include product properties, and processibility, reliability of supply, customer service, price and credit terms, advertising and sales promotion, and development of customer loyalty to branded products.
GENERAL
At December 31, 2017,2023, we held a total of 356518 active patents in 18 countries worldwide, including 275415 active U.S. patents. The overall profitability of any business segment is not dependent on any single patent, trademark, license or franchise.
Company-sponsored research and development activities charged against earnings were $60 million in both 2017 and 2016 and $65 million in 2015.
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 ensure thatidentify and mitigate the risks of personal safety, process safety, and environmental impact risks are identified and mitigation steps are taken to reduce the risk.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.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 “Management’s“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 20172023 and those expected for 20182024 and 2019.2025.
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.
Item 1A. RISK FACTORS
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as affect the value of an investment in our common stock. 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 operating resultsManufacturing and future rate of growth are exposed to the effects of changingOperations
Market conditions, including volatile commodity prices, margins and refining, marketingdemand 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 margins.
Our revenues, operating results and future rate of growth are highly dependent on a number of factors, including fixedplastics products and variable expenses (including the cost ofprices for crude oil NGL, and other refiningfeedstocks used in manufacturing these products. Historically, margins have been volatile, and petrochemical feedstocks) andwe expect they will continue to be volatile in the margin we can derive from selling refined and Chemicals segment products. future.
The pricescost of feedstocks and the prices at which we can ultimately sell our products fluctuate substantially. These prices depend on numerous factors beyond our control, including theregional and global supply and demand, for feedstocks and our products, which are subject to, among other things: Changesthings, production levels, levels of refined petroleum product inventories, productivity and growth of economies, geopolitical risks, such as turmoil in the global economyMiddle East, Eastern Europe, and other producing regions, technology advancements and the levelpace of foreignthe energy transition, weather-related damage and domestic production of crude oil,disruptions due to other natural gas and NGL and refined, petrochemical and plastics products.
Availability of feedstocks and refined productsor human causes, consumer preferences and the infrastructure to transport them.
Local factors, including market conditions, the leveluse and availability of operations of other facilities in our markets, substitute products,and the volume of products imported and exported.
Threatened or actual terrorist incidents, acts of war and other global political conditions.
Government regulations.
Weather conditions, hurricanes or other natural disasters.
The price of crude oil influences prices for refined products.governmental regulation. We do not produce crude oil and other feedstocks and must purchase all of the crude oilfeedstocks we process. Many crude oils available on the world market will not meet the quality restrictions for use in our refineries. Others are not economical to use due to high transportation costs or for other reasons. The prices for crude oil and refined petroleum products can fluctuate differently based on global, regional and local market conditions. In addition, the timing of the relative movement of the prices (both among different classes of refined products and among various global markets for similar refined products),conditions, as well as the overall change in refined product prices,by type and class of products, which can reduce refining margins and could have a significant impact on our refining, wholesale marketing and retail operations, revenues, operating income and cash flows. 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-responsivemarket-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 whenthe time we purchase feedstocks or products and when we sell the refined petroleum products produced from these feedstocks 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 also purchaseare 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 produced by others for saleto and from our facilities. In addition to our customers. Price changes that occur between whenown operational risks, we purchase and sell thesecould experience interruptions of supply or increases in costs to deliver refined petroleum products alsoto 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, and results of operations.
The price of feedstocks also influences prices for petrochemical and plastics products. Although our Chemicals segment transports and fractionates feedstocks to meet a portion of their demand and has certain long-term feedstock supply contracts with others, it is still subject to volatile feedstock prices. In addition, the petrochemicals industry is both cyclical and volatile. Cyclicality occurs when periods of tight supply, resulting in increased prices and profit margins, are followed by periods of capacity expansion, resulting in oversupply and declining prices and profit margins. Volatility occurs as a result of changes in supply and demand for products, changes in energy prices, and changes in various other economic conditions around the world.
Uncertainty and illiquidity in credit and capital markets can impair our ability to obtain credit and financing on acceptable terms and can adversely affect the financial strength of our business partners.
Our ability to obtain credit and capital depends in large measure on the state of the credit and capital markets, which is beyond our control. Our ability to access credit and capital markets may be restricted at a time when we would like, or need, access to those markets, which could constrain our flexibility to react to changing economic and business conditions. In addition, the cost and availability of debt and equity financing may be adversely impacted by unstable or illiquid market conditions. Protracted uncertainty and illiquidity in these markets also could have an adverse impact on our lenders, commodity hedging counterparties, or our customers, preventing them from meeting their obligations to us.
From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially and adversely affected if we are unable to obtain necessary funds from financing activities. From time to time, we may need to supplement cash generated from operations with proceeds from financing activities. Uncertainty and illiquidity in financial markets may materially impact the ability of the participating financial institutions to fund their commitments to us under our liquidity facilities. Accordingly, we may not be able to obtain the full amount of the funds available under our liquidity facilities to satisfy our cash requirements, and our failure to do so could have a material adverse effect on our operations and financial position.
Deterioration in our credit profile could increase our costs of borrowing money and limit our access to the capital markets and commercial credit, and could trigger co-venturer rights under joint-venture arrangements.
Our or Phillips 66 Partners’ credit ratings could be lowered or withdrawn entirely by a rating agency if, in its judgment, the circumstances warrant. If a rating agency were to downgrade our rating below investment grade, our or Phillips 66 Partners’ borrowing costs would increase, and our funding sources could decrease. In addition, a failure by us to maintain an investment grade rating could affect our business relationships with suppliers and operating partners. For example, our agreement with Chevron regarding CPChem permits Chevron to buy our 50 percent interest in CPChem for fair market value if we experience a change in control or if both Standard & Poor’s and Moody’s lower our credit ratings below investment grade and the credit rating from either rating agency remains below investment grade for 365 days thereafter, with fair market value determined by agreement or by nationally recognized investment banks. As a result of these factors, a downgrade of credit ratings could have a materially adverse impact on our future operations and financial position.
We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations. Likewise, future environmental laws and regulations may impact or limit our current business plans and reduce demand for our products.
Our business is subject to numerous laws and regulations relating to the protection of the environment. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:
The discharge of pollutants into the environment.
Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury emissions, and greenhouse gas emissions as they are, or may become, regulated).
The quantity of renewable fuels that must be blended into motor fuels.
The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous and nonhazardous wastes.
The dismantlement and abandonment of our facilities and restoration of our properties at the end of their useful lives.
We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our business, financial condition, results of operations and cash flows in future periods could be materially adversely affected.
The U.S. Environmental Protection Agency (EPA) has implemented a Renewable Fuel Standard (RFS) pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007. The RFS program sets annual quotas for the quantity of renewable fuels (such as ethanol) that must be blended into motor fuels consumed in the United States. To provide certain flexibility in compliance options available to the industry, a Renewable Identification Number (RIN) is assigned to each gallon of renewable fuel produced in, or imported into, the United States. As a producer of petroleum-based motor fuels, we are obligated to blend renewable fuels into the products we produce at a rate that is at least commensurate to the EPA’s quota and, to the extent we do not, we must purchase RINs in the open market to satisfy our obligation under the RFS program. To the extent the EPA mandates a blending quantity of renewable fuel that exceeds the amount that is commercially feasible to blend into motor fuel (a situation commonly referred to as “the blend wall”), our operations could be materially adversely impacted, up to and including a reduction in produced motor fuel.
The adoption of climate change legislation or regulation could result in increased operating costs and reduced demand for the refined products we produce.
The U.S. government, including the EPA, as well as several state and international governments, have either considered or adopted legislation or regulations in an effort to reduce greenhouse gas (GHG) emissions. These proposed or promulgated laws apply or could apply in states and/or countries where we have interests or may have interests in the future. In addition, various groups suggest that additional laws may be needed in an effort to address climate change, as illustrated by the Paris Agreement negotiated at the 2015 United Nations Conference on Climate Change, referred to as COP 21, which entered into force on November 4, 2016. We cannot predict the extent to which any such legislation or regulation will be enacted and, if so, what its provisions would be. To the extent we incur additional costs required to comply with the adoption of new laws and regulations that are not ultimately reflected in the prices of our products and services, our business, financial condition, results of operations and cash flows in future periods could be materially adversely affected. In addition, demand for the refined products we produce could be adversely affected.
Climate change may adversely affect our facilities and our ongoing operations.
The potential physical effects of climate change on our operations are highly uncertain and depend upon the unique geographic and environmental factors present. Examples of such effects include rising sea levels at our coastal facilities, changing storm patterns and intensities, and changing temperature levels. As many of our facilities are located near coastal areas, rising sea levels may disrupt our ability to operate those facilities or transport crude oil and refined petroleum products. Extended periods of such disruption could have an adverse effect on our results of operation. We could also incur substantial costs to prevent or repair damage to these facilities.
Domestic and worldwide political and economic developments could affect our operations and materially reduce our profitability and cash flows.
Actions of the U.S., state, local and international governments through tax and other legislation or regulation, executive order, permit or other review of infrastructure or facility development, and commercial restrictions could delay projects, increase costs, limit development, or otherwise reduce our operating profitability both in the United States and abroad. Any such actions may affect many aspects of our operations, including requiring permits or other approvals that may impose unforeseen or unduly burdensome conditions or potentially cause delays in our operations; further limiting or prohibiting construction or other activities in environmentally sensitive or other areas; requiring increased capital costs to construct, maintain or upgrade equipment or facilities; or restricting the locations where we may construct facilities or requiring the relocation of facilities. In addition, the U.S. government can prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments could limit our ability to operate in, or gain access to various countries, as well as limit our ability to obtain the optimum slate of crude oil and other refinery feedstocks. Our foreign operations and those of our joint ventures are further subject to risks of loss of revenue, equipment and property as a result of expropriation, acts of terrorism, war, civil unrest and other political risks; unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities; and difficulties enforcing rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations. Our foreign operations and those of our joint ventures are also subject to fluctuations in currency exchange rates. Actions by both the United States and host governments may affect our operations significantly in the future.
Renewable fuels, alternative energy mandates and energy conservation efforts could reduce demand for refined products. Tax incentives and other subsidies can make renewable fuels and alternative energy more competitive with refined products than they otherwise might be, which may reduce refined product margins and hinder the ability of refined products to compete with renewable fuels.
Large capital projects can take many years to complete, and market conditions could deteriorate significantly between the project approval date and the project startup date, negatively impacting project returns.
Our basis for approving a large-scale capital project is the expectation that it will deliver an acceptable level of return on the capital invested. We base these forecasted project economics on our best estimate of future market conditions. Most large-scale projects take several years to complete. During this multi-year period, market conditions can change from those we forecast, and these changes could be significant. Accordingly, we may not be able to realize our expected
returns from a large investment in a capital project, and this could negatively impact our results of operations, cash flows and our return on capital employed.
Our investments in joint ventures decrease our ability to manage risk.
We conduct some of our operations, including parts of our Midstream, Refining and M&SMarketing and Specialties (M&S) segments, and our entire Chemicals segment, through joint ventures in which we share control with our joint-venture participants.joint venture partners. Our joint-venture participantsjoint 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-venturejoint 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-venturejoint venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.
Activities in our ChemicalsPublic health crises, epidemics and Midstream segments involve numerous risks that may result in accidents that could affect the ability of our equity affiliates to make distributions to us.
There are a variety of hazards and operating risks inherent in the manufacturing of petrochemicals and the gathering, processing, transmission, storage, and distribution of natural gas and NGL,pandemics, such as spills, leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in significant injury, loss of human life, damage to property, environmental pollution and impairment of operations, any of which could result in substantial losses. For assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. Should any of these risks materialize, it couldCOVID-19 pandemic, have a material adverse effect on the business and financial condition of our equity affiliates in these segments and negatively impact their ability to make future distributions to us.
Our operations present hazards and risks, which may not be fully covered by insurance, if insured. If a significant accident or event occurs for which we are not adequately insured, our operations and financial results could be adversely affected.
The scope and nature of our operations present a variety of operational hazards and risks, including explosions, fires, toxic emissions, maritime hazards and natural catastrophes, that must be managed through continual oversight and control. For example, the operation of refineries, power plants, fractionators, pipelines, terminals and vessels is inherently subject to the risks of spills, discharges or other inadvertent releases of petroleum or hazardous substances. If any of these events had previously occurred or occurs in the future in connection with any of our refineries, pipelines or refined products terminals, or in connection with any facilities that receive our wastes or by-products for treatment or disposal, other than events for which we are indemnified, we could be liable for all costs and penalties associated with their remediation under federal, state, local and international environmental laws or common law, and could be liable for property damagecontinue to third parties caused by contamination from releases and spills. These and other risks are present throughout our operations. As protection against these hazards and risks, we maintain insurance against many, but not all, potential losses or liabilities arising from such operating risks. As such, our insurance coverage may not be sufficient to fully cover us against potential losses arising from such risks. Uninsured losses and liabilities arising from operating risks could reduce the funds available to us for capital and investment spending and could have a material adverse effect on our business. Any future widespread health crises could materially and adversely impact our business financial condition, resultsin the future.
Our global operations expose us to risks associated with public health crises and outbreaks of operationsepidemics, pandemics, or contagious diseases, such as COVID-19. The COVID-19 pandemic and cash flows.
We are subject to interruptions of supplythe associated containment efforts had a serious adverse impact on the economy and increased costs as a result of our reliance on third-party transportation of crude oil, NGL and refined products.
We often utilize the services of third parties to transport crude oil, NGL and refined products to and from our facilities. In addition to our own operational risks discussed above, we could experience interruptions of supply or increases in costs to deliver refined products to market if the ability of the pipelines or vessels to transport crude oil or refined products is disrupted because of weather events, accidents, governmental regulations or third-party actions. A prolonged disruption of the ability of a pipeline or vessel to transport crude oil, NGL or refined products to or from one or more of our refineries or other facilities could have a material adverse effect on our business, financial condition, resultsas 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 operations and cash flows.any future health crises, epidemics, or pandemics.
Increased regulationEven if a virus or other illness does not spread significantly, the perceived risk of hydraulic fracturing couldinfection or health risk may result in reductionsreduced demand for our products and materially affect our business. As we cannot predict the duration or delays in U.S. productionscope of crude oil and natural gas, which could adverselyany 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 operations.
An increasing percentagesuch events, including the virulence of crude oil supplied tothe 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 refineriesoperations, and the crude oilgeneral economic consequences of public health crises, epidemics and gas productionpandemics, 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 our Midstream segment’s customers is being produced from unconventional oil shale reservoirs. These reservoirs require hydraulic fracturing completion processes to releaseheightening many of the hydrocarbons from the rock so they can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate hydrocarbon production. The 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 suggestedother risks that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed to provide for such regulation. In addition, some communities have adopted measures to ban hydraulic fracturing in their communities. We cannot predict whether any such legislation will ever be enacted and, if so, what its provisions would be. Any additional levels of regulation and permits required with the adoption of new laws and regulations at the federal or state level could result in our having to rely on higher priced crude oil for our refineries. This could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through DCP Midstream’s gathering systems and could reduce supplies and increase costs of NGL feedstocks to CPChem ethylene facilities. This could materially adversely affect our results of operations and the ability of DCP Midstream and CPChem to make cash distributions to us.
DCP Midstream’s success depends on its ability to obtain new sources of natural gas and NGL. Any decreasebusiness described in this Annual Report, such as risks associated with industry capacity utilization, volatility in the volumesprice and availability of natural gas DCP Midstream gathers could adversely affectraw materials, supply chain interruptions, material adverse changes in customer relationships including any failure of a customer to perform its businessobligations under agreements with us, and operating results.
DCP Midstream’s gathering and transportation pipeline systems are connected to or dependent on the level of production from natural gas wells, which naturally declines over time. As a result, its cash flowsrisks associated with these wells will also decline over time. In order to maintainworldwide or increase throughput levels on its gatheringregional economic conditions.
Competition Risks
Refining and transportation pipeline systems and NGL pipelines and the asset utilization rates at its natural gas processing plants, DCP Midstream must continually obtain new supplies. The primary factors affecting DCP Midstream’s ability to obtain new supplies of natural gas and NGL, and to attract new customers to its assets, include the level of successful drilling activity near these assets, prices of, and the demand for, natural gas and crude oil, producers’ desire and ability to obtain necessary permits in an efficient manner, natural gas field characteristics and production performance, surface access and infrastructure issues, and its ability to compete for volumes from successful new wells. If DCP Midstream is not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells or because of competition, throughput on its pipelines and the utilization rates of its treating and processing facilities would decline. This could have a material adverse effect on its business, results of operations, financial position and cash flows, and its ability to make cash distributions to us.
Competitorsmarketing competitors that produce their own supply of feedstocks, have more extensive retail outlets, or have greater financial resources may have a competitive advantage.
The refining and marketing industry is highly competitive with respect to both feedstock supply and refined petroleum product markets. We compete with many companies for available supplies of crude oil and other feedstocks and for outlets for our refined petroleum products. We do not produce any of our crude oil feedstocks. Some of our competitors, however, obtain a portion of their feedstocks from their own production and some have more extensive retail outlets than we have. Competitors that have their own production or extensive retail outlets (and greater brand-name recognition) are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.
Some of our competitors also have materially greater financial and other resources than we have. Such competitors have a greater ability to bear the economic risks inherent in all phasesaspects 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, lossescosts 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 forward-contract activitiescompliance with existing and derivative transactions.future environmental laws and regulations.
We currentlyOur 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, commodity derivative instruments,storage, transportation, disposal and we expect to use themcleanup 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 future.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 instrumentscosts of compliance on to our customers, sufficient credits are unavailable for purchase, we utilizehave to hedgepay a significantly higher price for credits, or if we are otherwise unable to meet our exposurecompliance 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 various typeschange and impose considerable uncertainty due to a number of riskfactors 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 not effective,adopted and result in more stringent limitations on the production and development of crude oil and natural gas, we may incur losses. Derivative transactions involvesignificant costs to comply with the risk that counterpartiesrequirements, and producers may be unable to satisfy their obligations to us. The riskexperience delays or curtailment in the permitting or pursuit of counterparty default is heightened in a poor economic environment.
One of our subsidiaries acts as the general partner of a publicly traded master limited partnership, Phillips 66 Partners, which may involve a greater exposure to legal liability than our historic business operations.
One of our subsidiaries acts as the general partner of Phillips 66 Partners, a publicly traded master limited partnership. Our control of the general partner of Phillips 66 Partners may increase the possibility that we could be subject to claims of breach of fiduciary duties, including claims of conflicts of interest, related to Phillips 66 Partners. Any liability resulting from such claimsexploration, 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.
AContinuing political and social concerns about climate change and other Environmental, Social and Governance (ESG) matters may result in changes to our business and significant interruptionexpenditures, including litigation-related expenses.
Increasing attention to global climate change has resulted in oneincreased investor attention and an increased risk of public and private litigation, which could increase our costs or more of our facilities couldotherwise 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.
OurAdditionally, 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 be subjecthave 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 of our facilities wererestrictive regulations and rules related to experience a major accident, mechanical failure, or power outage, encounter work stoppages relating to organized labor issues, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any facility were to experience an interruption in operations, earnings from the facilityplastic waste could be materially adversely affected (to the extent not recoverable through insurance, if insured) because of lost production and repair costs. A significant interruption in one or more of our facilities could also lead to increased volatility in pricesreduce demand for feedstocks and refinedCPChem’s plastic products and could increase instabilitynegatively 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 insurance markets, making it more difficult for us to access capitalcash flows, thereby negatively impacting our equity earnings, and to obtain insurance coveragecash distributions that we consider adequate.receive, from CPChem.
Our performance depends on the uninterrupted operation of our facilities, which are becoming increasingly dependent on our information technology systems.Cybersecurity and Data Privacy Risks
Our performance depends on the efficient and uninterrupted operation of the manufacturing equipment in our production facilities. The inability to operate one or more of our facilities due to a natural disaster; power outage; labor dispute; or failure of one or more of our information technology, telecommunications, or other systems could significantly impair our ability to manufacture our products. Our manufacturing equipment is becoming increasingly dependent on our information technology systems. A disruption in our information technology systems due to a catastrophic event or security breach could interrupt or damage our operations.
Security breachesCybersecurity incidents and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of our business, we collect sensitive data, including personally identifiable information of our customers using credit cards at our branded retail outlets. Despite our security measures, ourOur 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 hackersmalicious actors or breached due to employeehuman error, malfeasance or other disruptions. Although we have experienced occasional, actualdisruptions, including ransomware and other malware, phishing and social engineering schemes, malicious software, data privacy breaches by employees, insiders or attempted breaches ofothers with authorized access, attempts to gain unauthorized access to our data and systems; and other cybersecurity none of these breaches has had a material effect on our business, operations or reputation (or compromised any customer data).incidents. Any such breachesincidents 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 lawsour liquidity facilities that protectare supported by a broad syndicate of financial institutions. Accordingly, we may not be able to obtain the privacyfull amount of customer information, disrupt 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 providemay 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 customers,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 damagelenders 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 our business.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 planplans 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 Separation,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 liabilities and we have agreed to indemnify ConocoPhillips for certain liabilities. If we are required to act on these indemnities to ConocoPhillips, we may need to use cash to meet those obligations and our financial results could be negatively impacted. The ConocoPhillips indemnity may not be sufficient to insure us against the full amount of liabilities for which it has been allocated responsibility, and ConocoPhillipsmatters, but may not be able to satisfy its indemnification obligations to us in the future.
Pursuant to theIn connection with our separation from ConocoPhillips in 2012, we entered into an Indemnification and Release Agreement and certain other agreements with ConocoPhillips entered into in connection with the Separation,pursuant to which ConocoPhillips agreed to indemnify us for certain liabilities, and we agreed to indemnify ConocoPhillips for certain liabilities. Indemnities that we may be required to provide ConocoPhillips are not subject to any cap and may be significant and could negatively impact our business, particularly indemnities relating to our actions that could impact the tax-free nature of the distribution of Phillips 66 stock.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. Moreover, even if we ultimately succeed in recovering from ConocoPhillips any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves. Each of these risks could negatively affect our business, results of operations and financial condition.
We are subject to continuing contingent liabilities of ConocoPhillips following the Separation.
Notwithstanding the Separation, there are several significant areas where the liabilities of ConocoPhillips may become our obligations. For example, under the Internal Revenue Code and the related rules and regulations, each corporation that was a member of the ConocoPhillips consolidated U.S. federal income tax reporting group during any taxable period or portion of any taxable period ending on or before the effective time of the Separation is jointly and severally liable for the U.S. federal income tax liability of the entire ConocoPhillips consolidated tax reporting group for that taxable period. In connection with the Separation, we entered into the Tax Sharing Agreement with ConocoPhillips that allocates the responsibility for prior period taxes of the ConocoPhillips consolidated tax reporting group between us and ConocoPhillips. ConocoPhillips may be unable to pay any prior period taxes for which it is responsible, and we could be required to pay the entire amount of such taxes. Other provisions of federal law establish similar liability for other matters, including laws governing tax-qualified pension plans as well as other contingent liabilities.
If the distribution in connection with the Separation, together with certain related transactions, does not qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, our stockholders and ConocoPhillips could be subject to significant tax liability and, in certain circumstances, we could be required to indemnify ConocoPhillips for material taxes pursuant to indemnification obligations under the Tax Sharing Agreement.
ConocoPhillips received a private letter ruling from the Internal Revenue Service (IRS) substantially to the effect that, among other things, the distribution, together with certain related transactions, qualified as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. The private letter ruling and the tax opinion that ConocoPhillips received relied on certain representations, assumptions and undertakings, including those relating to the past and future conduct of our business, and neither the private letter ruling nor the opinion would be valid if such representations, assumptions and undertakings were incorrect. Moreover, the private letter ruling does not address all the issues that are relevant to determining whether the distribution qualified for tax-free treatment. Notwithstanding the private letter ruling and the tax opinion, the IRS could determine the distribution should be treated as a taxable transaction for U.S. federal income tax purposes if it determines any of the representations, assumptions or
undertakings that were included in the request for the private letter ruling are false or have been violated or if it disagrees with the conclusions in the opinion that are not covered by the IRS ruling.
If the IRS were to determine that the distribution failed to qualify for tax-free treatment, in general, ConocoPhillips would be subject to tax as if it had sold the Phillips 66 common stock in a taxable sale for its fair market value, and ConocoPhillips stockholders who received shares of Phillips 66 common stock in the distribution would be subject to tax as if they had received a taxable distribution equal to the fair market value of such shares.
Under the Tax Sharing Agreement, we would generally be required to indemnify ConocoPhillips against any tax resulting from the distribution to the extent that such tax resulted from (i) any of our representations or undertakings being incorrect or violated, or (ii) other actions or failures to act by us. Our indemnification obligations to ConocoPhillips and its subsidiaries, officers and directors are not limited by any maximum amount. If we are required to indemnify ConocoPhillips or such other persons under the circumstances set forth in the Tax Sharing Agreement, we may be subject to substantial liabilities.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 1C. CYBERSECURITY
Management has implemented a comprehensive cybersecurity program that is designed to protect our information, and that of our customers and suppliers, against cybersecurity threats that may materially and adversely affect the confidentiality, integrity, and availability of our information systems. Our cybersecurity program includes processes and standards that leverage recognized cybersecurity frameworks, industry best practices and guidance from U.S. Government security directives that focus on cybersecurity and critical infrastructure.
Cybersecurity Governance
Board of Directors
The Audit and Finance Committee of the Board of Directors (the Audit and Finance Committee) is responsible for overseeing the company’s Enterprise Risk Management (ERM) program, including oversight of the processes management has implemented to assess, identify and manage risks associated with cybersecurity and information technology. In carrying out this responsibility, the Audit and Finance Committee regularly receives written reports from the company’s Chief Information Security Officer (CISO) and periodic briefings from the CISO. These presentations may address a wide range of topics, such as the results of recent vulnerability assessments and third-party independent reviews, changes to the threat environment, technological trends and other recent developments, and peer and other third-party benchmarking. The Audit and Finance Committee makes regular reports to the Board of Directors on data protection and cybersecurity matters. The company maintains an Enterprise Cybersecurity Incident Response Plan (ECIRP) which provides the framework for management’s response to cyber-related incidents and escalation protocols, including, when appropriate, prompt reporting to the Board of Directors.
Management
At the management level, our CISO has extensive cybersecurity knowledge and skills gained from work experience at the company and with a law enforcement agency, as well as from obtaining advanced professional certifications. The CISO is responsible for the assessment and management of risks from cybersecurity threats and leads a team responsible for implementing, monitoring and maintaining cybersecurity and data protection practices across the company. The individuals who report directly to our CISO possess relevant educational and industry experience in the areas of cyber threat hunting and intelligence, digital standards, data privacy, cyber training, and cybersecurity operations center management. In addition to our internal cybersecurity capabilities, we also regularly engage consultants, or other third parties to assist with assessing, identifying, and managing cybersecurity risks. The CISO receives reports on cybersecurity threats on an ongoing basis, and in conjunction with management, regularly reviews risk management measures implemented by the company to identify, assess and mitigate data protection and cybersecurity risks. Our CISO works closely with the company’s Senior Counsel, Intellectual Property and Data Protection, to oversee compliance with legal, regulatory and contractual security requirements.
Risk Management and Strategy
On an annual basis, we conduct an evaluation of our cybersecurity risks as part of the ERM program. Through the ERM program, the CISO and other internal subject matter experts review potential cybersecurity threat scenarios, such as data theft, cash theft, widespread outages and business disruptions, and the potential consequences of such scenarios. The results of the risk assessment are shared with management and the Audit and Finance Committee.
We have a continuous monitoring program to detect and respond to potential cybersecurity threats in real-time. Log data from our technical controls are collected, aggregated, and correlated in a Security Information and Event Management (SIEM) system that identifies and categorizes events, as well as analyzes them. If the SIEM system identifies a potential security event, it can direct other controls to stop the activity and also generate alerts for detection and response. These alerts are monitored by a managed security service provider that augments a dedicated internal Security Operations Center team.
In addition, we utilize a third-party risk management (TPRM) program to identify, assess, monitor, and mitigate risks associated with third-party relationships, including cybersecurity risks. The TPRM program is designed to help ensure proper controls and measures are in place to manage the potential risks and vulnerabilities associated with third parties. Our policies and procedures aid in the governance from initial due diligence, selection, and contracting to termination.
With respect to cybersecurity incident response, our ECIRP provides a standardized framework for responding to cybersecurity incidents. The ECIRP sets out a coordinated approach to investigating, containing, documenting and mitigating incidents, including reporting findings and keeping senior management and other key stakeholders informed and involved as appropriate.
Internal audit performs audits of our cybersecurity program. Each year, we conduct audits across the company’s information technology and operation technology infrastructure, networks, systems, applications, and operational processes and procedures to evaluate compliance with our information security policies and standards. Process control network assurance audits are conducted on a rotating schedule that is risk-based and provides coverage across each operational business area no greater than five years. In addition to the internal audits, we also engage external cybersecurity experts and auditors to conduct assessments, penetration testing, and cybersecurity maturity assessments. Although we have experienced actual and attempted cybersecurity events and incidents on our networks and systems in the past, we do not believe that the risks from any of these events or incidents, individually or in the aggregate, have materially affected our business, operations, or financial condition, or are reasonably likely to have such an effect. For more information concerning cybersecurity risks we face, see the discussion in “Item 1A. Risk Factors” in this report.
Item 3. LEGAL PROCEEDINGS
The following isFrom 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 description of reportable legal$300,000 threshold to disclose certain proceedings including those involving governmental authoritiesarising under federal, state andor local environmental laws regulatingwhen a governmental authority is a party to the discharge of materials intoproceedings. The below matters are disclosed in accordance with that requirement. We do not currently believe that the environment. While it is not possible to accurately predict the finaleventual outcome of these pending proceedings, if any onematters previously reported, but still unresolved, individually or more of such proceedings were decided adversely to Phillips 66, we expect there would be noin the aggregate, could have a material adverse effect on our consolidatedbusiness, financial position. Nevertheless, such proceedings are reported pursuant to Securities and Exchange Commission (SEC) regulations.condition, results of operations or cash flows.
OurFurther, our U.S. refineries are implementing two separate consent decrees, regarding alleged violations of the Federal Clean Air Act, with the U.S. Environmental Protection Agency (EPA),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 ThereThe 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 no new mattersworking with SCAQMD to report.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, 2017)2023) The California Air Resources BoardIn 2018, the Colorado Department of Public Health and Environment (CDPHE) issued four separate Noticesa Compliance Advisory in relation to an improperly permitted facility flare and related air emissions from flare operations at one of Violation (NOV)DCP Operating Company LP’s (DCP Operating LP) gas processing plants, which DCP Operating LP self-disclosed to the company alleging violations of fuel specification requirements at our Los Angeles Refinery and Torrance Tank Farm. This matter was resolved with a payment of $190,000CDPHE in December 2017.
On June 27, 2017, Phillips 66 reached settlement Following information exchanges and discussions with CDPHE, a resolution was proposed pursuant to which the San Francisco Regional Water Quality Control Board for certain exceedances of copperplant’s air permit would be revised, and chlorine underDCP Operating LP would be assessed an administrative penalty and economic benefit payment. A revised air permit was issued in May 2019, but the Rodeo Refinery’s National Pollutant Discharge Elimination System permit. The settlement was finalized and payment of $109,000 to resolve the matter was made following a 30-day public comment period that ended in November 2017.
In October 2016, after receiving a Notice of Intent to Sue from the Sierra Club, weparties had not yet entered into a voluntaryfinal settlement withagreement to complete the Illinois Environmental Protection Agency for alleged violations of wastewater requirementsmatter. 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 Wood River Refinery. The settlement involves certain capital projects and payment of $125,000. After the settlement was filed with the Court for final approval, the Sierra Club sought and was granted approval to intervene in the case. The settlement andCDPHE have reached a first modification have been entered by the Court, but the Sierra Club still seeks to reopen and challenge the settlement.
In September 2014, the EPA issued an NOV alleging a violation of hazardous air pollution regulations at the Wood River Refinery during 2014. We are working with the EPA to resolve this NOV.
In July 2014, Phillips 66 received an NOV from the EPA alleging various flaring-related violations between 2009 and 2013 at the Wood River Refinery. We are working with the EPA to resolve this NOV.
In May 2012, the Illinois Attorney General’s office filed and notified us of a complaint with respect to operations at the Wood River Refinery alleging violations of the Illinois groundwater standards and a third-party’s hazardous waste permit. The complaint seeks as relief remediation of area groundwater; compliance with the hazardous waste permit; enhanced pipeline and tank integrity measures; additional spill reporting; and fines and penalties exceeding $100,000. We are working with the Illinois Environmental Protection Agency and Attorney General’s officetentative agreement to resolve these allegations.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.
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS OF THE REGISTRANT | | | | | | | | | | Name | Position Held | Age* | | | | | NameMark E. Lashier | Position Held | Age* |
| | | | Greg C. Garland | ChairmanPresident and Chief Executive Officer | 6062 | |
Robert A. HermanKevin 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 | |
Paula A. JohnsonBrian M. Mandell | Executive Vice President, LegalMarketing 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 | 5452 | |
Kevin J. MitchellScott Pruitt | Executive Vice President, Finance and Chief Financial Officer | 51 |
| Chukwuemeka A. Oyolu | Vice President and Controller | 4859 | |
* OnAs of February 23, 2018.21, 2024.
There are no family relationships among any of the executive officers named above.above or any member of our Board of Directors. The Board of Directors annually elects the officers to serve until a successor is elected and qualified or as otherwise provided in our By-Laws. Set forth below is information about the executive officers identified above.
Greg C. GarlandMark E. Lashier is the ChairmanPresident and Chief Executive Officer, of Phillips 66, a position he has held since June 2014.July 2022. Previously, Mr. GarlandLashier served as Phillips 66’s Chairman, President and Chief ExecutiveOperating Officer of Phillips 66 from April 20122021 to June 2014. Mr. Garland previously served as ConocoPhillips’ Senior Vice President, Exploration and Production—Americas from October 2010 to April 2012, and asJuly 2022; President and Chief Executive Officer of CPChem from 2008August 2017 to 2010.April 2021; and as Executive Vice President, Commercial of CPChem from August 2015 to August 2017.
Robert A. HermanKevin J. Mitchell is Executive Vice President Refining for Phillips 66, a position he has held since September 2017. Previously, Mr. Herman served Phillips 66 as Executive Vice President, Midstream from June 2014 to September 2017, Senior Vice President, HSE, Projects and Procurement from February 2014 to June 2014, and Senior Vice President, Health, Safety, and Environment from April 2012 to February 2014.
Paula A. Johnson is Executive Vice President, Legal and Government Affairs, General Counsel and Corporate Secretary of Phillips 66, a position she has held since October 2016. Previously, Ms. Johnson served as Executive Vice President, Legal, General Counsel and Corporate Secretary of Phillips 66 from May 2013 to October 2016, and Senior Vice President, Legal, General Counsel and Corporate Secretary of Phillips 66 from April 2012 to May 2013.
Kevin J. Mitchell is Executive Vice President, Finance and Chief Financial Officer, of Phillips 66, a position he has held since January 2016. Previously, Mr. Mitchell served as Phillips 66’s Vice President, Investor Relations from September 2014 when he joined the company, to January 2016. Prior to joining the company, he
Zhanna Golodryga is Executive Vice President, Emerging Energy and Sustainability, a position she has held since October 2022. Previously, Ms. Golodryga served as the General Auditor of ConocoPhillips from May 2010 until September 2014.
Chukwuemeka A. Oyolu isSenior Vice President, Chief Digital and Controller of Phillips 66,Administrative Officer from April 2017 to October 2022.
Richard G. Harbison is Executive Vice President, Refining, a position he has held since December 2014.June 2022. Mr. Oyolu was Phillips 66’sHarbison previously served as Vice President, San Francisco Refinery from March 2021 to May 2022; General Manager, Finance for Refining,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 TransportationCommercial, 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 February 2014 when he became General Manager, Planning and Optimization.
September 2020.
PART II
| | Item 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Quarterly Common Stock Prices and Cash Dividends Per ShareItem 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 following table reflects intraday high and low sales pricesabove performance graph represents cumulative total stockholder return, which assumes reinvestment of and dividends, declared on,of a $100 investment in our common stock, our self-constructed peer group for each quarter presented: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.
| | | | | | | | | | | | | Stock Price | | | | | High | | Low |
| | Dividends |
| | 2017 | | | | | | First Quarter | $ | 88.26 | | 76.28 |
| | 0.63 |
| | Second Quarter | 83.11 | | 75.14 |
| | 0.70 |
| | Third Quarter | 92.19 | | 80.73 |
| | 0.70 |
| | Fourth Quarter | 102.43 | | 89.26 |
| | 0.70 |
| | | | | | | | 2016 | | | | | | First Quarter | $ | 90.87 | | 71.74 |
| | 0.56 |
| | Second Quarter | 89.31 | | 76.40 |
| | 0.63 |
| | Third Quarter | 81.31 | | 73.67 |
| | 0.63 |
| | Fourth Quarter | 88.87 | | 77.66 |
| | 0.63 |
|
| | | | | | | | | Closing Stock Price at December 29, 2017 | | | | $ | 101.15 |
| | Closing Stock Price at January 31, 2018 | | | | $ | 102.40 |
| | Number of Stockholders of Record at January 31, 2018 | | | | 38,605 |
|
Performance Graph
 In our 2016 annual report, the performance graph included a peer index (the “Previous Peer Group”) composed of Celanese Corporation;CVR Energy, Inc.; Delek US Holdings, Inc.; Dow Chemical Company; Eastman Chemical Co.; Energy Transfer Equity, LP; Enterprise Products Partners, LP; HollyFrontier Corporation; Huntsman Corporation; Marathon Petroleum Corporation; Oneok, Inc.; PBF Energy Inc.; Targa Resources Corp.; Tesoro Corporation; Valero Energy Corporation; Western Refining, Inc.; and Westlake Chemical Corp. To more appropriately weight our peers with our business segments and utilize peers with more comparable market capitalizations, we have removed Energy Transfer from the peer group and replaced Dow with LyondellBasell Industries N.V. Additionally, Tesoro acquired Western Refining (subsequently renamed Andeavor). Accordingly, the New Peer Index is composed of Andeavor; Celanese Corporation; Delek US Holdings, Inc.; Eastman Chemical Co.; Enterprise Products Partners, LP; HollyFrontier Corporation; HuntsmanHF Sinclair Corporation; LyondellBasell Industries N.V.; Marathon Petroleum Corporation; Oneok,ONEOK, Inc.; PBF Energy Inc.; Targa Resources Corp.; Valero Energy Corporation; and Westlake Chemical Corp.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
| | | | | | | | | | | | | | | | | | | | | | | 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, 2017 | 1,717,513 |
| | $ | 92.25 |
| | 1,717,513 |
| | $ | 3,277 |
| | November 1-30, 2017 | 1,675,652 |
| | 93.30 |
| | 1,675,652 |
| | 3,120 |
| | December 1-31, 2017 | 1,492,675 |
| | 99.17 |
| | 1,492,675 |
| | 2,972 |
| | Total | 4,885,840 |
| | $ | 94.72 |
| | 4,885,840 |
| | |
* Includes repurchase of shares of common stock from company employees in connection with the company’s broad-based employee incentive plans, when applicable.
** As of December 31, 2017,
On October 25, 2023, our Board of Directors has authorized repurchases totaling upapproved a $5 billion increase to $12 billion of our outstanding common stock, including the authorization in October 2017 toshare repurchase $3 billion of additional shares. The authorizations from the Board of Directors do not have expiration dates. Theauthorization.Any future share repurchases are expected to be funded primarily through available cash. The authorized shares will be repurchased from time to time in the open marketmade at the company’s discretion subject to market conditionsof management and otherwill depend on various factors including our share price, results of operations, financial condition and in accordance with applicable regulatory requirements. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Shares of stock repurchased are held as treasury shares.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. |
Item 6. [RESERVED]
Item 6. SELECTED FINANCIAL DATA
| | | | | | | | | | | | | | | | | | | Millions of Dollars Except Per Share Amounts | | | 2017 |
| | 2016 |
| | 2015 |
| | 2014 |
| | 2013 |
| | | | | | | | | | | | | Sales and other operating revenues | $ | 102,354 |
| | 84,279 |
| | 98,975 |
| | 161,212 |
| | 171,596 |
| | Income from continuing operations | 5,248 |
| | 1,644 |
| | 4,280 |
| | 4,091 |
| | 3,682 |
| | Income from continuing operations attributable to Phillips 66 | 5,106 |
| | 1,555 |
| | 4,227 |
| | 4,056 |
| | 3,665 |
| | Per common share | | | | | | | | | | | Basic | 9.90 |
| | 2.94 |
| | 7.78 |
| | 7.15 |
| | 5.97 |
| | Diluted | 9.85 |
| | 2.92 |
| | 7.73 |
| | 7.10 |
| | 5.92 |
| | Net income | 5,248 |
| | 1,644 |
| | 4,280 |
| | 4,797 |
| | 3,743 |
| | Net income attributable to Phillips 66 | 5,106 |
| | 1,555 |
| | 4,227 |
| | 4,762 |
| | 3,726 |
| | Per common share | | | | | | | | | | | Basic | 9.90 |
| | 2.94 |
| | 7.78 |
| | 8.40 |
| | 6.07 |
| | Diluted | 9.85 |
| | 2.92 |
| | 7.73 |
| | 8.33 |
| | 6.02 |
| | Total assets | 54,371 |
| | 51,653 |
| | 48,580 |
| | 48,692 |
| | 49,769 |
| | Long-term debt | 10,069 |
| | 9,588 |
| | 8,843 |
| | 7,793 |
| | 6,101 |
| | Cash dividends declared per common share | 2.7300 |
| | 2.4500 |
| | 2.1800 |
| | 1.8900 |
| | 1.3275 |
|
In December 2013, we entered into an agreement to exchange the stock of Phillips Specialty Products Inc. (PSPI), a flow improver business, which was included in our Marketing and Specialties segment, for shares of Phillips 66 common stock owned by the other party. The PSPI share exchange was completed in February 2014. Accordingly, the selected income from continuing operations data above for the years ended December 31, 2014 and 2013, exclude income from PSPI’s discontinued operations of $706 million and $61 million, respectively.
To ensure full understanding, you should read the selected financial data presented above in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and accompanying notes included elsewhere in this Annual Report on Form 10-K.
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis is the company’s analysis of its financial performance, financial condition, and significant trends that may affect future performance. It should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.”
The term “earnings” as used in Management’s Discussion and Analysis refers to net income attributable to Phillips 66. The terms “earnings” and “loss”“results,” “before-tax income” or “before-tax loss” as used in Management’s Discussion and Analysis refer to net income (loss) attributable to Phillips 66.before income taxes.
EXECUTIVE OVERVIEW AND BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
Phillips 66 is anuniquely positioned as a diversified and integrated downstream energy manufacturingcompany operating with Midstream, Chemicals, Refining, and logistics company with midstream, chemicals, refining,Marketing and marketing and specialties businesses.Specialties (M&S) segments. At December 31, 2017,2023, we had total assets of $54.4$75.5 billion.
Executive Overview WeDuring 2023, we reported earnings of $5.1$7 billion, and generated $3.6$7 billion in cash from operating activities in 2017. Our reported earnings included a $2.7 billion provisional income tax benefitand received proceeds from the U.S. Tax Cuts and Jobs Act (the Tax Act) enacted on December 22, 2017. Phillips 66 Partners LP (Phillips 66 Partners) raiseddebt offerings, net proceeds totaling $1.8 billion from equity andof debt offerings.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 $1.8$2.4 billion, repurchase $1.6shares of common stock for $4 billion ofand pay dividends on our common stock and pay dividends of $1.4$1.9 billion. We ended 20172023 with $3.1$3.3 billion of cash and cash equivalents and approximately $5.8$6.4 billion of total committed capacity available under both our and Phillips 66 Partners’ 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 continuealso plan to focus onmonetize 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 followingdisposition of these non-core assets, which we plan to use to further advance our strategic priorities: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.
Operating Excellence. Our commitment to operating excellence guides everything we do. •Improve Refining Performance – We are committed to protecting the healthfocused on optimizing utilization rates and safety of everyone who has a role in our operations and the communities in which we operate. Continuous improvement in safety, environmental stewardship, reliability and cost efficiency is a fundamental requirement for our company and employees. We employ rigorous training and audit programs to drive ongoing improvement in both personal and process safety as we strive for zero incidents. We achieved a record-low combined injury rate in 2017. Since we cannot control commodity prices, controlling operating expenses and overhead costs, within the context of our commitment to safety and environmental stewardship, is a high priority. Senior management actively monitors these costs. We are committed to protecting the environment and strive to reduce our environmental footprint throughout our operations.Optimizing utilization ratesproduct yield at our refineries through reliable and safe operations, enableswhich 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 2017,2023, our worldwide refining crude oil capacity utilization rate was 95 percent.92% and our worldwide refining clean product yield was 85%, compared to 90% and 84%, respectively, in 2022.
Growth.•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 $2.3 billion in$985 million of capital expenditures and investments in 2018, including $0.6 billion for Phillips 66 Partners. Additionally, 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 expectedDakota 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 spendingreduction of $300 million per year by joint venturesthe 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 Midstream, LLC (DCP Midstream), Chevron Phillips Chemical Company LLC (CPChem) and WRB Refining LP, (WRB) in 2018 is $0.9 billion. In Midstream, we plan to invest inrepurchase shares of our Transportation and NGL businesses, focusingcommon stock, pay dividends on projects integrated with our existing assets and infrastructure. In Chemicals, CPChem’scommon stock, fund capital expenditures are expected to decrease due to completionand investments and repay a portion of its U.S. Gulf Coast Petrochemicals Project. The two polyethylene units started up in September 2017, while commissioning of the ethane cracker is expected to begin in the first DCP LP’s debt.
quarter of 2018.•Drive Disciplined Growth capital in Refining will be directed toward small, high-return, quick-payout projects primarily to increase clean product yields, while in Marketing and Specialties (M&S) it will be directed primarily towards increasing our retail sites in Europe.
Returns. We plan to improve refining returns by increasing throughput of advantaged feedstocks, disciplined capital allocation and portfolio optimization. Returns – A disciplined capital allocation process ensures we focus investmentsinvest in projects that are expected to generate competitive returns throughout the business cycle. In 2017, we improved clean product yield in Refining, and in M&S, we continued to enhance our network and brand by re-imaging sitesreturns. Our strategy remains focused on investing growth capital in the United States, while growing our numberMidstream 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 sites in Europe.
growth capital.
Distributions. We believe shareholder value is enhanced through, among other things, consistent growth of regular dividends, complemented by share repurchases. We increased our quarterly dividend rate by 11 percent during 2017,DCP Midstream, LLC and have increased it 250 percent since the company’s inception in 2012. Regular dividends demonstrate the confidence our Board of Directors and management have in our capital structure and operations’ capability to generate free cash flow throughout the business cycle. In 2017,Gray Oak Holdings LLC Merger (DCP Midstream Merger)
On August 17, 2022, we repurchased $1.6 billion, or approximately 18.7 million shares,announced a realignment of our common stock. Also,economic and governance interests in October 2017, our BoardDCP LP and Gray Oak Pipeline, LLC (Gray Oak Pipeline) resulting from the merger of Directors authorized up to $3 billion of additional share repurchases. At the discretion of our Board of Directors, we plan to increase dividends annuallyDCP Midstream, LLC (DCP Midstream) and fund our share repurchase program while continuing to invest in the growth of our business.
High-Performing Organization. We strive to attract, develop and retain individualsGray Oak Holdings LLC (Gray Oak Holdings). In connection with the knowledgeDCP Midstream Merger, we were delegated DCP Midstream’s governance rights over DCP LP and skillsits general partner entities, referred to implementas DCP Midstream Class A Segment, and our business strategy and who supportindirect economic interest in DCP LP increased to 43.3%.
Starting on August 18, 2022, our values and culture. Throughoutfinancial results reflect the company, we focus on getting results in the right way and believe success is both what we do and how we do it. We encourage collaboration throughout our company, while valuing differences, respecting diversity, and creating a great place to work. We foster an environmentconsolidation of learning and development through structured programs focused on enhancing functional and technical skills where employees are engaged in our business and committed to their own,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 company’s, success. 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 Commodity prices rose significantly during 2017, compared with 2016. The discount for the U.S. crude oil benchmark West Texas Intermediate (WTI) versus the international benchmark Brent widened over much of 2017, initially related to extended production cuts by the Organization of the Petroleum Exporting Countries (OPEC) and certain non-OPEC countries, but further widened with Hurricane Harvey and logistical issues at the Cushing, Oklahoma, trading hub. Over the course of 2017, commodity prices had both favorable and unfavorable impacts on our businesses that vary by segment.
Net income in the Midstream segment which includes our 50 percent equity investment inTransportation and NGL businesses. Our Transportation business contains fee-based operations not directly exposed to commodity price risk. Our NGL business, including DCP Midstream is closely linked toClass 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 liquids (NGL) prices,prices. During 2023, NGL and natural gas prices and crude oil prices. Average natural gas prices increased in 2017,decreased, compared with 2016, due to higher demand and low production in early 2017. In2022, as the fourth quarterresult of 2017, natural gas prices gained momentum with colder temperatures and increased residential and commercial heating demand. Total U.S. natural gas production also increased through the fourth quarter of 2017, largely from dry gas in the Marcellus play and associated gas from the Permian Basin. NGL prices improved throughout 2017 due to international demand.production.
The Chemicals segment consists of our 50 percent50% equity investment in CPChem.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. During 2017,Compared with 2022, the chemicals and plastics industry continued to benefit from feedstock cost advantages associated with manufacturing ethylene in regions of the world with significant NGL production. The price of crude oil is rising faster than NGL prices and thus the petrochemicals industry continues to experience lower ethylene cash costs in regions of the world where ethylene manufacturing is based upon NGL rather than crude oil-derived feedstocks. In particular, companies with North American ethane-based crackers have benefited and have captured a somewhat higherbenchmark high-density polyethylene chain margin. The ethylene-to-polyethylene chain margins expandedmargin decreased in 2017 because2023, due to lower polyethylene sales prices as a result of the crude oil price recovery after the significant decline in oil prices that began in 2014.industry oversupply driven by recent capacity additions.
Our Refining segment results are driven by several factors, including refining margins, cost control,market crack spreads, refinery throughput, feedstock costs, product yields, turnaround activity, and turnaround activity. Industryother operating costs. Market crack spreadspreads are used as indicators of refining margins and measure the difference between market prices for refined petroleum products and crude oil, are used to estimate refining margins. During 2017, the U.S.oil. The composite 3:2:1 market crack spread (three barrelsfor 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, producing two barrelsWest Texas Intermediate (WTI) at Cushing, Oklahoma, decreased to an average of gasoline and one$77.69 per barrel during 2023, from an average of diesel) strengthened across all quarters, compared with 2016, largely attributable to higher product demand and lower product inventories$94.44 per barrel in 2022. The decrease in crude oil prices was primarily driven by increased production in the last halfUnited States and other countries outside of 2017 due to Hurricane Harvey. Northwest European crack spreads on average increased in 2017, compared with 2016, also due to higher demand.the Organization of Petroleum Exporting Countries (OPEC).
Results for our M&S segment depend largely on marketing fuel margins,and lubricant margins and other specialty product margins.sales volumes of our refined petroleum products. While M&Smarketing 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 the trendtrends in spot prices, and where applicable, retail prices for refined products. Generally speaking, a downward trend of spot prices has a favorable impact on marketing fuel margins, while an upward trend of spot prices has an unfavorable impact on marketing fuel margins. Spot prices moved upwardpetroleum products in 2017, following the increase in crude oil prices.regions and countries where we operate.
RESULTS OF OPERATIONS
BasisOur business segment and consolidated results reflect the consolidation of PresentationDCP 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.
During the fourth quarter of 2017, the segment performance measure used by our chief executive officer to assess performance and allocate resources was changed from “net income attributable to Phillips 66” to “net income.” This change reflects the recognition that management does not differentiate between those earnings attributable to Phillips 66 and those attributable to noncontrolling interests when making operating and resource allocation decisions impacting segment performance. Prior period segment information has been recast to conform to the current presentation.
Consolidated Results
A summary of net income (loss)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 | |
| | | | | | | | | | | | | Millions of Dollars | | | Year Ended December 31 | | | 2017 |
| | 2016 |
| | 2015 |
| | | | | | | | | Midstream | $ | 464 |
| | 280 |
| | 74 |
| | Chemicals | 525 |
| | 583 |
| | 962 |
| | Refining | 1,404 |
| | 374 |
| | 2,555 |
| | Marketing and Specialties | 686 |
| | 891 |
| | 1,187 |
| | Corporate and Other | 2,169 |
| | (484 | ) | | (498 | ) | | Net income | 5,248 |
| | 1,644 |
| | 4,280 |
| | Less: net income attributable to noncontrolling interests | 142 |
| | 89 |
| | 53 |
| | Net income attributable to Phillips 66 | $ | 5,106 |
| | 1,555 |
| | 4,227 |
|
2023 vs. 2022
2017 vs. 2016
Our earnings increased $3,551Net income attributable to Phillips 66 for the year ended December 31, 2023, was $7,015 million, or 228 percent,compared with $11,024 million for the year ended December 31, 2022. The decrease in 2017, mainly reflecting:
Recognition2023 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 $2,735 million provisionaldecline in realized refining margins, partially offset by a decrease in income tax benefit fromexpense and lower unrealized investment losses related to our investment in NOVONIX Limited (NOVONIX).
2022 vs. 2021
Net income attributable to Phillips 66 for the enactment ofyear ended December 31, 2022, was $11,024 million, compared with $1,317 million for the Tax Act inyear ended December 2017. Higher31, 2021. The improvement was primarily due to higher realized refining margins.
Recognitionmargins, an aggregate before-tax gain of a $261$3,013 million after-tax gain fromrecognized in our Midstream segment in connection with the consolidation of Merey Sweeny, L.P. (MSLP).
ImprovedDCP 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 affiliatesCPChem, and an unrealized decrease in the fair value of our Midstream segment.investment in NOVONIX.
These increases were partially offset by:
Increased costs due to Hurricane Harvey, primarily impacting CPChem in our Chemicals segment.
Lower realized marketing margins.
Higher interest and debt expense.
2016 vs. 2015
Our earnings decreased$2,672 million, or 63 percent, in 2016, primarily resulting from:
Lower realized refining margins.
Lower olefins and polyolefins margins.
Recognition in 2015 of $242 million of the deferred gain related to the sale in 2013 of the Immingham Combined Heat and Power Plant (ICHP).
These decreases were partially offset by:
Improved results from DCP Midstream, primarily as a result of goodwill and other asset impairments recorded in 2015.
See the “Segment Results” section for additional information on our segment results.
results and Note 23—Income Statement Analysis
2017 vs. 2016
Sales and other operating revenues and purchased crude oil and products increased 21 percent and 27 percent, respectively, in 2017. The increases were primarily due to higher prices for petroleum products, crude oil and NGL.
Equity in earnings of affiliates increased 22 percent in 2017, primarily resulting from higher equity in earnings from DCP Midstream and other affiliates in our Midstream segment, as well as WRB, partially offset by lower results from CPChem.
Equity in earnings from our Midstream segment increased $270 million due to improved results from DCP Midstream, primarily driven by improved margins, as well as higher equity in earnings from our Transportation affiliates, including our joint ventures that own the Bakken Pipeline, which started commercial operations in June 2017.
Equity in earnings of WRB increased $207 million, primarily due to higher market crack spreads, partially offset by lower feedstock advantage.
Equity in earnings of CPChem decreased $120 million, primarily due to hurricane-related costs and downtime.
Other income increased $447 million in 2017. We recognized a noncash, pre-tax gain of $423 million in February 2017 related to the consolidation of MSLP. See Note 5—Business Combinations,Taxes, in the Notes to Consolidated Financial Statements, for additional information.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.
Operating expenses increased 10 percent
Statement of Income Analysis
2023 vs. 2022
Sales and other operating revenues and purchased crude oil and products decreased 13% and 15%, respectively, in 2017. This increase was2023. 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 a transportation joint ventureDCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills starting in December 2016, as well asAugust 2022 and higher refining turnaround expenses and utility costs, pension settlement expense, and costs associated with a full year of operations at the Freeport LPG Export Terminal.our business transformation. These increases were partially offset by lower costsselling expenses due to decreased refined petroleum product prices. See Note 31—Restructuring, in the sale of the Whitegate Refinery in 2016.Notes to Consolidated Financial Statements, for additional information regarding restructuring costs.
Depreciation and amortization increased 13 percent21% in 20172023, primarily due to the Freeport LPG Export Terminal beginning operationsadditional 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 late 2016, as well asAugust 2022.
Taxes other assets placedthan income taxes increased 33% in service2023, primarily due to consolidating DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills starting in 2017.August 2022 and an increase in environmental taxes.
Interest and debt expense increased 30 percent45% in 2017. This increase was2023, 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 capitalized interest from the completion of major projects, including the startup of the Freeport LPG Export Terminal in late 2016, as well as higher average debt principal balances.
Income tax expense (benefit) was a benefit in 2017, compared with expense in 2016, primarily due to the $2,735 million provisional income tax benefit from the enactment of the Tax Act in December 2017. This benefit was partially offset by higher income tax expense from increased income before income taxes. See Note 21—23—Income Taxes, in the Notes to Consolidated Financial Statements, for more information regarding our income taxes.
Net income attributable to noncontrolling interest increased $53 millioninterests decreased 39% in 2017, reflecting2023. The decrease reflects the contributionimpacts of assetsthe 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 during 2017 and late 2016.in March 2022. See Note 27—3—DCP Midstream, LLC and DCP Midstream, LP Mergers, and Note 30—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for more information.additional information on the DCP Midstream Merger and the Phillips 66 Partners merger, respectively.
2016
2022 vs. 20152021
Sales and other operating revenues and purchased crude oil and products both decreased 15 percent increased 52% and 47%, respectively, in 2016. The decreases2022. 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 lower average prices for petroleum products and crude oil, while average NGL prices were slightly improved during 2016.
Equityan aggregate before-tax gain of $3,013 million recognized in earningsour Midstream segment in connection with the DCP Midstream Merger. The impact of affiliates decreased 10 percent in 2016, primarily resulting from decreased earnings from CPChem and WRB,this gain was partially offset by improved results from DCP Midstream.
Equityan unrealized investment loss on our investment in earnings of CPChem decreased 37 percent, primarily due to lower realized olefins and polyolefins margins.
EquityNOVONIX, compared with an unrealized gain in earnings of WRB decreased $186 million, mainly resulting from lower market crack spreads, partially offset by higher feedstock advantage.
Equity in earnings of DCP Midstream improved $426 million in 2016, primarily driven by goodwill and other asset impairments recorded by DCP Midstream in 2015.
Net gain on dispositions decreased $273 million in 2016. In 2015, we recognized a $242 million deferred gain related to the sale of ICHP.2021. See Note 6—Assets Held for Sale or Sold,4—Business Combinations, and Note 18—Fair Value Measurements, in the Notes to Consolidated Financial Statements, for additional information.
information on the aggregate before-tax gain. See Note 21—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 tax expensetaxes.
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 effective tax rates.
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 | |
| | | | | | | | | | | | | Year Ended December 31 | | | 2017 |
| | 2016 |
| | 2015 |
| | | Millions of Dollars | | Net Income (Loss) | | | | | | | Transportation | $ | 376 |
| | 311 |
| | 335 |
| | NGL and Other | 43 |
| | 2 |
| | 63 |
| | DCP Midstream | 45 |
| | (33 | ) | | (324 | ) | | Total Midstream | $ | 464 |
| | 280 |
| | 74 |
|
| | | | Thousands of Barrels Daily | | Thousands of Barrels Daily | | | Thousands of Barrels Daily | | Transportation Volumes | | | | | | | Pipelines* | | | Pipelines* | | | Pipelines* | 3,501 |
| | 3,511 |
| | 3,264 |
| | Terminals | 2,665 |
| | 2,422 |
| | 1,981 |
| | Operating Statistics | | | | | | | NGL fractionated** | 186 |
| | 170 |
| | 112 |
| | NGL extracted*** | 374 |
| | 393 |
| | 410 |
| | NGL fractionated** | | | NGL fractionated** | | | NGL production*** | | | Wellhead Volume (Bcf/D)*** | |
* Pipelines represent the sum of volumes transported through each separately tariffed consolidated pipeline segment, including our shareexcluding NGL pipelines. ** Includes 100% of equityDCP Midstream Class A Segment’s volumes from Yellowstone Pipe Line Company and Lake Charles Pipe Line Company. ** Excludes DCP Midstream.August 18, 2022, forward.
*** Represents 100 percentIncludes 100% of DCP Midstream’sMidstream Class A Segment’s volumes.
| | | | | | | | | | Dollars Per Gallon | | | Dollars Per Gallon | | Market Indicator | | | Weighted-Average NGL Price* | | | | | | | DCP Midstream | $ | 0.62 |
| | 0.46 |
| | 0.45 |
| | Weighted-Average NGL Price* | | | Weighted-Average NGL Price* | |
* Based on index prices from the Mont Belvieu and Conway market hubs thathub, which are weighted by NGL component and location mix.
The Midstream segment provides crude oil and refined productspetroleum product transportation, terminaling and processing services, as well as natural gas,services; NGL and liquefied petroleum gas (LPG)production, transportation, storage, fractionation, processing and marketing services,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 master limited partnership (MLP), Phillips 66 Partners,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 50 percent25% 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 investmentinvestments in DCP Midstream, which includesDCP Sand Hills and DCP Southern Hills to their fair values in connection with the operations of its MLP, DCP Midstream LP (DCP Partners).
2017 vs. 2016
Net incomeMerger. The decrease was partially offset by the consolidation of DCP Midstream Class A Segment, DCP Sand Hills and DCP Southern Hills from the Midstream segment increased $184 million in 2017, compared with 2016, due to improved results across all business lines.
Transportation net income increased $65 million in 2017, compared with 2016. The improvement was mainly driven by increased equity in earnings from affiliates, including our joint ventures that own the Bakken Pipeline, which started commercial operations in June 2017,August 18, 2022, forward, as well as Rockies Express Pipeline LLC (REX)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 our sharea 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 favorable breach35.75% indirect economic interest in Gray Oak Pipeline to our co-venturer as part of contract settlement claim. These increasesthe DCP Midstream Merger, and lower depreciation and amortization expense from logistic assets that were partially offset by higher operating costs.retired in the fourth quarter of 2021 as part of the planned conversion of the Alliance Refinery to a terminal.
Net incomeResults from our NGL and Other business increased $41$3,548 million in 2017,2022, compared with 2016. The increase reflects a full year of operations at the Freeport LPG Export Terminal, the contribution of MSLP to Phillips 66 Partners in October 2017, and higher equity earnings from DCP Sand Hills Pipeline, LLC (Sand Hills), partially offset by lower realized margins.
Net income from our investment in DCP Midstream improved $78 million in 2017, compared with 2016.2021. The increase was primarily due to improved margins driven by higher average NGL and natural gas prices, and improved resultsbefore-tax gains totaling $2,831 million recognized from DCP Midstream’s hedging program.
See the “Business Environment and Executive Overview” section for information on market factors impacting 2017 results.
2016 vs. 2015
Net income from the Midstream segment increased $206 millionremeasuring our previously held equity investments in 2016, compared with 2015. The increase was primarily due to improved results from DCP Midstream, partially offset by lower net incomeDCP 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 our Transportation and NGL and Other businesses.
Transportation net income decreased $24 million in 2016, compared with 2015. Lower net income primarily resulted from higher operating costs and increased depreciation expense due to growth projects. These items were partially offset by higher revenues from increased throughput volumes and higher tariffs.
Net income from our NGL and Other business decreased $61 million in 2016, compared with 2015. The decrease was primarily driven by lower realized margins,August 18, 2022, forward, as well as increased depreciation and operating expenses associated withimproved Sweeny Hub results.
In 2022, the Sweeny Fractionator and, late in the year, the Freeport LPG Export Terminal. These items were partially offset by higher fractionated volumes, reflecting the operationfair value of the Sweeny Fractionator for a full year in 2016, and the benefit of the first liquefied petroleum gas cargos exported from the Freeport LPG Export Terminal in late 2016.
Improved results from 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 increased our net income by $291 million in 2016, compared with 2015. In 2015, DCP Midstream recorded goodwill and other asset impairments, which reduced our net income by $232 million. In addition, favorable contract restructuring efforts, improved asset performance, higher equity in earnings from DCP Midstream’s equity affiliates, lower operating costs and higher NGL prices contributed to better results in 2016. These improvements were partially offset by lower natural gas and crude oil prices.
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 | |
| | | | | | | | | | | | | Year Ended December 31 | | | 2017 |
| | 2016 |
| | 2015 |
| | | Millions of Dollars | | | | | | | | | Net Income | $ | 525 |
| | 583 |
| | 962 |
| | | | | | | | | | Millions of Pounds | | CPChem Externally Marketed Sales Volumes* | | | | | | | Olefins and Polyolefins | 15,870 |
| | 16,011 |
| | 16,916 |
| | Specialties, Aromatics and Styrenics | 4,618 |
| | 4,911 |
| | 5,301 |
| | | 20,488 |
| | 20,922 |
| | 22,217 |
| | * Represents 100 percent of CPChem’s outside sales of produced petrochemical products, as well as commission sales from equity affiliates. | | | | | | | | | Olefins and Polyolefins Capacity Utilization (percent)* | 87 | % | | 91 |
| | 92 |
|
The Chemicals segment consists of our 50 percent50% interest in CPChem, which we account for under the equity method. CPChem uses NGL and other feedstocks to produce petrochemicals. These products are then marketed and sold or used as feedstocks to produce plastics and other chemicals. We structure our reporting of CPChem’s operations around two primary business segments: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P business segmentCPChem produces and markets ethylene and other olefin products. Ethylene produced is primarily consumed within CPChem for the production of polyethylene, normal alpha olefins and polyethylene pipe. The SA&S business segmentCPChem manufactures and markets aromatics and styrenics products, such as benzene, cyclohexane, styrene paraxylene and cyclohexane,polystyrene, as well as polystyrene. SA&S also manufactures and/or markets a variety of specialty chemical products. Unless otherwise noted, amounts referenced below reflect our net 50 percent50% interest in CPChem.
20172023 vs. 20162022
Net incomeResults from the Chemicals segment decreased $58$256 million in 2017,2023, compared with 2016.2022. The decrease was primarily due to lower margins driven by higher costs and lower volumes due to Hurricane Harvey, as well as lower margins. These items weredecreased sales prices, partially offset by lower impairment charges, higher equity in earnings from an O&P affiliateutility costs due to lower turnaround costs and a gain on the sale of CPChem’s K-Resin® styrene-butadiene copolymers business. CPChem recognized impairment charges of $127 million and $177 milliondecline in 2017 and 2016, respectively, due to lower demand and margin factors. As a result of these impairments, net income of the Chemicals segment was reduced by $39 million and $89 million in 2017 and 2016, respectively.natural gas prices.
As a result of Hurricane Harvey, CPChem’s Cedar Bayou facility in Baytown, Texas, experienced severe flooding, which caused it to shut down operations in the third quarter of 2017. This facility restarted in phases during the fourth quarter of 2017. CPChem’s U.S. Gulf Coast Petrochemicals Project, which consists of an ethane cracker at Cedar Bayou and two polyethylene units at Old Ocean, Texas, was also impacted by the flooding. CPChem achieved mechanical completion of its ethane cracker at the Cedar Bayou facility in December 2017, and is expected to complete commissioning of the ethane cracker in the first quarter of 2018, with a transition to full production in the second quarter of 2018.
See the “Business Environment“Executive Overview and Executive Overview”Business Environment” section for information on market factors impacting CPChem’s 2023 results.
2016 vs. 2015
Net incomeResults from the Chemicals segment decreased $379$988 million in 2016,2022, compared with 2015.2021. The decrease in net income was primarily due to lower realized margins from the O&P business, driven by a decline indecreased sales prices, for polyethylenehigher feedstock and normal alpha olefins (NAO) and higher feedstockutility costs, as well as impacts from increased turnaround activity. Lower equity earningsdecreased results from CPChem’s equity affiliates and lower SA&S volumes further reduced net income in 2016.affiliates.
In addition, CPChem recognized a $177 million impairment in 2016 due
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 | |
| | | | | | | | | | | | | Year Ended December 31 | | | 2017 |
| | 2016 |
| | 2015 |
| | | Millions of Dollars | | Net Income (Loss) | | | | | | | Atlantic Basin/Europe | $ | 370 |
| | 204 |
| | 569 |
| | Gulf Coast | 512 |
| | 52 |
| | 551 |
| | Central Corridor | 477 |
| | 234 |
| | 857 |
| | West Coast | 45 |
| | (116 | ) | | 578 |
| | Worldwide | $ | 1,404 |
| | 374 |
| | 2,555 |
| | | | | | | | | | Dollars Per Barrel | | Net Income (Loss) | | | | | | | Atlantic Basin/Europe | $ | 1.86 |
| | 0.93 |
| | 2.68 |
| | Gulf Coast | 1.79 |
| | 0.18 |
| | 2.08 |
| | Central Corridor | 5.18 |
| | 2.38 |
| | 8.96 |
| | West Coast | 0.34 |
| | (0.92 | ) | | 4.42 |
| | Worldwide | 1.97 |
| | 0.51 |
| | 3.63 |
| | | | | | | | | Realized Refining Margins | | | | | | | Atlantic Basin/Europe | $ | 8.25 |
| | 6.26 |
| | 9.39 |
| | Gulf Coast | 7.07 |
| | 5.49 |
| | 9.29 |
| | Central Corridor | 12.44 |
| | 8.70 |
| | 14.88 |
| | West Coast | 10.49 |
| | 9.15 |
| | 16.86 |
| | Worldwide | 9.13 |
| | 6.99 |
| | 11.84 |
|
| | | | | | | | | | | | | | | | | | | 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. |
| | | | | | | | | | | | Thousands of Barrels Daily | | | Year Ended December 31 | | | 2017 |
| | 2016 |
| | 2015 |
| | Operating Statistics | | | | | | | Refining operations* | | | | | | | Atlantic Basin/Europe | | | | | | | Crude oil capacity | 520 |
| | 566 |
| | 588 |
| | Crude oil processed | 494 |
| | 568 |
| | 539 |
| | Capacity utilization (percent) | 95 | % | | 100 |
| | 92 |
| | Refinery production | 553 |
| | 607 |
| | 587 |
| | Gulf Coast | | | | | | | Crude oil capacity | 743 |
| | 743 |
| | 738 |
| | Crude oil processed | 709 |
| | 704 |
| | 654 |
| | Capacity utilization (percent) | 95 | % | | 95 |
| | 89 |
| | Refinery production | 789 |
| | 783 |
| | 733 |
| | Central Corridor | | | | | | | Crude oil capacity | 493 |
| | 493 |
| | 492 |
| | Crude oil processed | 467 |
| | 485 |
| | 465 |
| | Capacity utilization (percent) | 95 | % | | 98 |
| | 95 |
| | Refinery production | 489 |
| | 506 |
| | 486 |
| | West Coast | | | | | | | Crude oil capacity | 360 |
| | 360 |
| | 360 |
| | Crude oil processed | 342 |
| | 318 |
| | 330 |
| | Capacity utilization (percent) | 95 | % | | 88 |
| | 92 |
| | Refinery production | 368 |
| | 345 |
| | 359 |
| | Worldwide | | | | | | | Crude oil capacity | 2,116 |
| | 2,162 |
| | 2,178 |
| | Crude oil processed | 2,012 |
| | 2,075 |
| | 1,988 |
| | Capacity utilization (percent) | 95 | % | | 96 |
| | 91 |
| | Refinery production | 2,199 |
| | 2,241 |
| | 2,165 |
| | * Includes our share of equity affiliates. | | | | | |
TheOur Refining segment refines crude oil and other feedstocks into petroleum products, (suchsuch as gasoline, distillates and aviation fuels) at 13fuels, 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.
20172023 vs. 20162022
Net income forResults from the Refining segment increased $1,030decreased $2,550 million in 2017,2023, compared with 2016.2022. The increasedecrease was primarily due to higherlower realized refining margins and West Coast volumes, as well as an after-tax gain of $261 million recognized on the consolidation of MSLP, partially offset by higher turnaround expenses, utilities costs and pension settlement expense. The higher realized refining margins primarily resulted from improved market crack spreads and secondary product margins, partially offset by lower utility costs. The decrease in realized margins was primarily driven by a decline in market crack spreads, partially offset by increased feedstock advantage.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 “Business Environment“Executive Overview and Executive Overview”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, see2021 included a before-tax impairment of $1,288 million associated with our Alliance Refinery. See Note 5—Business Combinations and Note 27—Phillips 66 Partners LP,11—Impairments, in the Notes to Consolidated Financial Statements, for additional information on the consolidation of MSLP in February 2017 and the subsequent contribution of our ownership interest in MSLP to Phillips 66 Partners in October 2017, respectively.regarding this impairment.
Our worldwide refining crude oil capacity utilization rate was 95 percent90% and 84% in 2017, compared with 96 percent2022 and 2021, respectively. The increase in 2016. The decrease2022 was primarily attributable to higher turnaround activities and unplanned downtime, partially offsetdriven by improved market conditions.
2016 vs. 2015
Net income for the Refining segment decreased $2,181 million in 2016, compared with 2015. Lower net income in 2016 reflected lower realized refining margins resulting from decreased market crack spreads, higher costs associated with renewable fuels blending activities, lower clean product differentials and lower feedstock advantage. These items were partially offset by higher volumes due to lower turnaround activities and less unplanned downtime.
Our worldwide refining crude oil capacity utilization rate was 96 percent in 2016, compared with 91 percent in 2015. The increase was primarily attributable to lower turnaround activities and less unplanned downtime.
Non-GAAP Reconciliations
Our realized refining margins measure the difference between a) sales and other operating revenues derived from the sale of petroleum products manufactured at our refineries and b) purchase costs of feedstocks, primarily crude oil, used to produce the petroleum products. The margins are adjusted to include our proportional share of our joint-venture refineries’ realized margins, as well as to exclude those items that are not representative of the underlying operating performance of a period, which we call “special items.” The realized refining margins are converted to a per-barrel basis by dividing them by total refinery processed inputs (primarily crude oil) measured on a barrel basis, including our share of inputs processed by our joint-venture refineries. Our realized refining margin per barrel is intended to be comparable with industry refining margins, which are known as “crack spreads.” As discussed in “Business Environment,” industry crack spreads measure the difference between market pricesdemand for refined petroleum products due to supply constraints caused by the conflict between Russia and crude oil. Realized refining margin per barrel calculated on a similar basis as industry crack spreads provides a useful measureUkraine and easing of how well we performed relative to benchmark industry margins.restrictions from the COVID-19 pandemic.
Under generally accepted accounting principles in the United States (GAAP), the performance measure most directly comparable to refining margin per barrel is the Refining segment’s “net income per barrel.” 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 net income, such as general and administrative expenses and income taxes. It also includes our proportional share of joint-venture refineries’ realized margins and excludes special items. Because refining margin per barrel is calculated in this manner, and because 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 net income 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, 2017 | | | | | | | Net income | $ | 370 |
| 512 |
| 477 |
| 45 |
| 1,404 |
| | Plus: | | | | | | | Income tax expense | 78 |
| 297 |
| 278 |
| 19 |
| 672 |
| | Taxes other than income taxes | 56 |
| 97 |
| 46 |
| 64 |
| 263 |
| | Depreciation, amortization and impairments | 192 |
| 273 |
| 129 |
| 244 |
| 838 |
| | Selling, general and administrative expenses | 61 |
| 55 |
| 34 |
| 48 |
| 198 |
| | Operating expenses | 847 |
| 1,212 |
| 593 |
| 982 |
| 3,634 |
| | Equity in (earnings) losses of affiliates | 11 |
| (4 | ) | (329 | ) | — |
| (322 | ) | | Other segment (income) expense, net | (10 | ) | (421 | ) | 13 |
| 5 |
| (413 | ) | | Proportional share of refining gross margins contributed by equity affiliates | 59 |
| 1 |
| 959 |
| — |
| 1,019 |
| | Special items: | | | | | | | Certain tax impacts | (23 | ) | — |
| — |
| — |
| (23 | ) | | Realized refining margins | $ | 1,641 |
| 2,022 |
| 2,200 |
| 1,407 |
| 7,270 |
| | | | | | | | Total processed inputs (thousands of barrels) | 199,068 |
| 285,951 |
| 92,146 |
| 134,089 |
| 711,254 |
| Adjusted total processed inputs (thousands of barrels)* | 199,068 |
| 285,951 |
| 176,823 |
| 134,089 |
| 795,931 |
| | | | | | | | Net income per barrel (dollars per barrel)** | $ | 1.86 |
| 1.79 |
| 5.18 |
| 0.34 |
| 1.97 |
| Realized refining margins (dollars per barrel)*** | 8.25 |
| 7.07 |
| 12.44 |
| 10.49 |
| 9.13 |
| | | | | | | | | Year Ended December 31, 2016 | | | | | | | Net income (loss) | $ | 204 |
| 52 |
| 234 |
| (116 | ) | 374 |
| | Plus: | | | | | | | Income tax expense (benefit) | (17 | ) | 17 |
| 133 |
| (72 | ) | 61 |
| | Taxes other than income taxes | 58 |
| 73 |
| 42 |
| 80 |
| 253 |
| | Depreciation, amortization and impairments | 200 |
| 234 |
| 106 |
| 230 |
| 770 |
| | Selling, general and administrative expenses | 64 |
| 51 |
| 31 |
| 49 |
| 195 |
| | Operating expenses | 817 |
| 1,234 |
| 465 |
| 979 |
| 3,495 |
| | Equity in (earnings) losses of affiliates | 8 |
| (50 | ) | (122 | ) | — |
| (164 | ) | | Other segment (income) expense, net | (11 | ) | 3 |
| (6 | ) | (2 | ) | (16 | ) | | Proportional share of refining gross margins contributed by equity affiliates | 55 |
| (4 | ) | 705 |
| — |
| 756 |
| | Special items: | | | | | | | Pending claims and settlements | — |
| (70 | ) | — |
| — |
| (70 | ) | | Certain tax impacts | (32 | ) | — |
| — |
| — |
| (32 | ) | | Railcar lease residual value deficiencies and related costs | 5 |
| 16 |
| 11 |
| 8 |
| 40 |
| | Recognition of deferred logistics commitments | 30 |
| — |
| — |
| — |
| 30 |
| | Realized refining margins | $ | 1,381 |
| 1,556 |
| 1,599 |
| 1,156 |
| 5,692 |
| | | | | | | | Total processed inputs (thousands of barrels) | 220,519 |
| 283,574 |
| 98,217 |
| 126,329 |
| 728,639 |
| Adjusted total processed inputs (thousands of barrels)* | 220,519 |
| 283,574 |
| 183,691 |
| 126,329 |
| 814,113 |
| | | | | | | | Net income (loss) per barrel (dollars per barrel)** | $ | 0.93 |
| 0.18 |
| 2.38 |
| (0.92 | ) | 0.51 |
| Realized refining margins (dollars per barrel)*** | 6.26 |
| 5.49 |
| 8.70 |
| 9.15 |
| 6.99 |
| | * Adjusted total processed inputs include our proportional share of processed inputs of an equity affiliate. | | ** Net income (loss) 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 due to rounding. |
| | | | | | | | | | | | | | | Millions of Dollars, Except as Indicated | | Realized Refining Margins | Atlantic Basin/Europe |
| Gulf Coast |
| Central Corridor |
| West Coast |
| Worldwide |
| | | | | | | | | Year Ended December 31, 2015 | | | | | | | Net income | $ | 569 |
| 551 |
| 857 |
| 578 |
| 2,555 |
| | Plus: | | | | | | | Income tax expense (benefit) | (15 | ) | 338 |
| 469 |
| 312 |
| 1,104 |
| | Taxes other than income taxes | 57 |
| 76 |
| 42 |
| 84 |
| 259 |
| | Depreciation, amortization and impairments | 197 |
| 226 |
| 102 |
| 216 |
| 741 |
| | Selling, general and administrative expenses | 67 |
| 60 |
| 35 |
| 59 |
| 221 |
| | Operating expenses | 995 |
| 1,241 |
| 447 |
| 961 |
| 3,644 |
| | Equity in (earnings) losses of affiliates | 8 |
| (25 | ) | (308 | ) | — |
| (325 | ) | | Other segment (income) expense, net | 30 |
| 2 |
| 8 |
| (5 | ) | 35 |
| | Proportional share of refining gross margins contributed by equity affiliates | 89 |
| (9 | ) | 977 |
| — |
| 1,057 |
| | Realized refining margins | $ | 1,997 |
| 2,460 |
| 2,629 |
| 2,205 |
| 9,291 |
| | | | | | | | Total processed inputs (thousands of barrels) | 212,627 |
| 264,874 |
| 95,682 |
| 130,799 |
| 703,982 |
| Adjusted total processed inputs (thousands of barrels)* | 212,627 |
| 264,874 |
| 176,641 |
| 130,799 |
| 784,941 |
| | | | | | | | Net income per barrel (dollars per barrel)** | $ | 2.68 |
| 2.08 |
| 8.96 |
| 4.42 |
| 3.63 |
| Realized refining margins (dollars per barrel)*** | 9.39 |
| 9.29 |
| 14.88 |
| 16.86 |
| 11.84 |
| | * Adjusted total processed inputs include our proportional share of processed inputs of an equity affiliate. | | ** Net income 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 due to rounding. |
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 | |
| | | | | | | | | | | | | Year Ended December 31 | | | 2017 |
| | 2016 |
| | 2015 |
| | | Millions of Dollars | | Net Income | | | | | | | Marketing and Other | $ | 551 |
| | 747 |
| | 1,004 |
| | Specialties | 135 |
| | 144 |
| | 183 |
| | Total Marketing and Specialties | $ | 686 |
| | 891 |
| | 1,187 |
| | | | | | | | | | Dollars Per Barrel | | Net Income | | | | | | | U.S. | $ | 0.56 |
| | 0.74 |
| | 0.76 |
| | International | 1.81 |
| | 2.21 |
| | 1.98 |
| | | | | | | | | Realized Marketing Fuel Margins | | | | | | | U.S. | $ | 1.48 |
| | 1.64 |
| | 1.65 |
| | International | 4.21 |
| | 4.05 |
| | 4.40 |
| | | | | | | | | | Dollars Per Gallon | | U.S. Average Wholesale Prices* | | | | | | | Gasoline | $ | 1.87 |
| | 1.62 |
| | 1.92 |
| | Distillates | 1.85 |
| | 1.48 |
| | 1.77 |
| | * On third-party branded petroleum products sales, excluding excise taxes. | | | | | | | | | | | | | | | Thousands of Barrels Daily | | Marketing Petroleum Products Sales | | | | | | | Gasoline | 1,246 |
| | 1,238 |
| | 1,205 |
| | Distillates | 931 |
| | 947 |
| | 953 |
| | Other | 18 |
| | 16 |
| | 16 |
| | | 2,195 |
| | 2,201 |
| | 2,174 |
|
The M&S segment purchases for resale and markets refined petroleum products, (suchsuch as gasoline, distillates and aviation fuels),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), as well as power generation operations.lubricants.
20172023 vs. 20162022
NetBefore-tax income from the M&S segment decreased $205$267 million in 2017,2023, compared with 2016.2022. The decrease in 2023 was primarily due todriven by lower international realized marketing fuel margins as well as the absence of biofuel tax credits and a favorable income tax adjustment recognized in 2016.decreased equity earnings from affiliates, partially offset by higher U.S. realized marketing fuel margins.
See the “Business Environment“Executive Overview and Executive Overview”Business Environment” section for information on marketing fuel margins and other market factors impacting 20162023 results.
20162022 vs. 20152021
NetBefore-tax income from the M&S segment decreased $296increased $679 million in 2016,2022, compared with 2015.2021. The decreaseincrease in 2022 was mainly attributable to the $242 million deferred gain recognized in 2015 related to the 2013 ICHP sale. See Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information.
primarily driven by improved realized international marketing fuel margins and higher results from our specialty lubricants and other businesses.
Also contributing to the lower net income in 2016 were lower realized marketing margins driven by an upward trend of spot prices during most of 2016, and lower margins and volumes in lubricants. These decreases were partially offset by favorable tax adjustments and higher marketing volumes.
Non-GAAP Reconciliations
Our realized marketing fuel margins measure the difference between a) sales and other operating revenues derived from the sale of fuels in our M&S segment and b) purchase costs of those fuels. These margins are converted to a per-barrel basis by dividing them by sales volumes measured on a barrel basis. 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 marketing fuel margin per barrel is the marketing business’ “net income per barrel.” 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 net income, such as general and administrative expenses and income taxes. Because marketing fuel margin per barrel excludes these items, and because 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 net income to realized marketing fuel margins:
| | | | | | | | | | | | | | | | | | Millions of Dollars, Except as Indicated | | | U.S. | | International | | | 2017 |
| 2016 |
| 2015 |
| | 2017 |
| 2016 |
| 2015 |
| | Realized Marketing Fuel Margins | | | | | | | | | | | | | | | | | | Net income | $ | 395 |
| 519 |
| 518 |
| | 176 |
| 235 |
| 217 |
| | Plus: | | | | | | | | | Income tax expense | 233 |
| 285 |
| 292 |
| | 41 |
| 17 |
| 57 |
| | Taxes other than income taxes | 5,481 |
| 5,187 |
| 5,208 |
| | 7,579 |
| 8,132 |
| 8,499 |
| | Depreciation, amortization and impairment | 14 |
| 12 |
| 9 |
| | 67 |
| 63 |
| 62 |
| | Selling, general and administrative expenses | 751 |
| 708 |
| 732 |
| | 264 |
| 259 |
| 269 |
| | Equity in earnings of affiliates | (5 | ) | (4 | ) | (4 | ) | | (83 | ) | (75 | ) | (78 | ) | | Other operating revenues* | (5,815 | ) | (5,558 | ) | (5,614 | ) | | (7,594 | ) | (8,157 | ) | (8,507 | ) | | Other segment (income) expense, net | (15 | ) | — |
| (15 | ) | | 2 |
| 3 |
| 6 |
| | Marketing margins | 1,039 |
| 1,149 |
| 1,126 |
| | 452 |
| 477 |
| 525 |
| | Less: margin for non-fuel related sales | — |
| — |
| — |
| | 42 |
| 45 |
| 44 |
| | Realized marketing fuel margins | $ | 1,039 |
| 1,149 |
| 1,126 |
|
| 410 |
| 432 |
| 481 |
| | | | | | | | | | Total fuel sales volumes (thousands of barrels) | 703,928 |
| 699,111 |
| 684,045 |
| | 97,346 |
| 106,574 |
| 109,332 |
| | | | | | | | | | Net income per barrel (dollars per barrel) | $ | 0.56 |
| 0.74 |
| 0.76 |
| | 1.81 |
| 2.21 |
| 1.98 |
| Realized marketing fuel margins (dollars per barrel)** | 1.48 |
| 1.64 |
| 1.65 |
|
| 4.21 |
| 4.05 |
| 4.40 |
| * Primarily excise taxes and other non-fuel revenues. | ** Realized marketing fuel margins per barrel, as presented, are calculated using the underlying realized marketing fuel margin amounts, in dollars, divided by sales volumes, in barrels. As such, recalculated per barrel amounts using the rounded margins and barrels presented may differ from the presented per barrel amounts due to rounding.
|
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) | |
| | | | | | | | | | | | | Millions of Dollars | | | Year Ended December 31 | | | 2017 |
| | 2016 |
| | 2015 |
| | Net Income (Loss) | | | | | | | Net interest expense | $ | (266 | ) | | (210 | ) | | (186 | ) | | Corporate general and administrative expenses | (175 | ) | | (161 | ) | | (157 | ) | | Technology | (62 | ) | | (58 | ) | | (60 | ) | | U.S. tax reform | 2,735 |
| | — |
| | — |
| | Other | (63 | ) | | (55 | ) | | (95 | ) | | Total Corporate and Other | $ | 2,169 |
| | (484 | ) | | (498 | ) |
2017 vs. 2016
Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense increased $56 million in 2017, compared with 2016, primarily due to lower capitalized interest as a result of the Freeport LPG Export Terminal beginning operations in late 2016,Corporate overhead and higher interest expense driven by higher average debt principal balances, reflecting Phillips 66 Partners’ debt issuances in October 2017other includes general and 2016.
The Tax Act was enacted on December 22, 2017. The material provisions of the Tax Act i) reduced the U.S. federal corporate income tax rate from 35 percent to 21 percent beginning January 1, 2018, ii) imposed a one-time deemed repatriation tax on foreign-sourced earnings that were previously tax deferred, and iii) created a new tax regime on post-2017 foreign-sourced earnings. We have not yet completed our accounting for the income tax effects of the Tax Act as of December 31, 2017, but have made reasonable estimates of those effects on our existing deferred income tax balances and the one-time deemed repatriation tax. We recognized a provisional income tax benefit of $2,735 million, which is included in the “Income tax expense (benefit)” line on our consolidated statement of income. We have included these one-time impacts of the Tax Act in Corporate and Other. Of the provisional income tax benefit recognized, $2,870 million was associated with the revaluation of our existing deferred tax assets and liabilities, and $14 million reflected higher manufacturing deductions, which was an indirect benefit of the Tax Act. These benefits were partially offset by the one-time deemed repatriation tax estimate of $149 million. We expect the Tax Act to significantly lower our effective tax rates in 2018 and future years for both our consolidated operations and each of our operating segments. See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for more information.
2016 vs. 2015
Net interest expense increased $24 million in 2016, compared with 2015, mainly due to lower capitalized interest.
The category “Other” includes certain income taxadministrative 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 decreaseincrease in other costsinterest expense in 20162023 was primarily attributable to favorable tax impacts and the write-off of certain fixed assets during 2015, 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 environmental accruals.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. |
| | | | | | | | | | | | | Millions of Dollars, Except as Indicated | | | 2017 |
| | 2016 |
| | 2015 |
| | | | | | | | | Cash and cash equivalents | $ | 3,119 |
| | 2,711 |
| | 3,074 |
| | Net cash provided by operating activities | 3,648 |
| | 2,963 |
| | 5,713 |
| | Short-term debt | 41 |
| | 550 |
| | 44 |
| | Total debt | 10,110 |
| | 10,138 |
| | 8,887 |
| | Total equity | 27,428 |
| | 23,725 |
| | 23,938 |
| | Percent of total debt to capital* | 27 | % | | 30 |
| | 27 |
| | Percent of floating-rate debt to total debt | 11 | % | | 3 |
| | 1 |
| | * Capital includes total debt and total equity. |
To meet our short- and long-term liquidity requirements, we look touse a variety of funding sources but rely primarily on cash generated from operating activities. Additionally, Phillips 66 Partners raises funds for its growth activities throughand debt and equity financings.financing. During 2017,2023, we generated $3.6$7 billion in cash from operations. Phillips 66 Partners completed the private placementoperations and received proceeds from debt offerings, net of perpetual convertible preferred units and common units and the public offeringdebt repayments, of senior notes and common units for net proceeds totaling $1.8$2 billion. We used this 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 $1.8 billion; repurchases of our common stock of $1.6 billion;$2.4 billion, and dividend paymentspay dividends on our common stock of $1.4$1.9 billion. During 2017,2023, cash and cash equivalents increased by $0.4decreased $2.8 billion to $3.1$3.3 billion.
In addition to cash flows from operating activities, we rely on our commercial paper and credit facility programs, asset sales and our ability to issue securities using our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash and cash equivalents and cash generated by operations, together with access to external sources of funds as described below under “Significant Sources of Capital,” will be sufficient to meet our funding requirements in the near and long term, including our capital spending, dividend payments, defined benefit plan contributions, debt repayment and share repurchases.
Significant Sources of Capital
Operating Activities During 2017,2023, cash of $3,648 million was providedgenerated by operating activities was $7 billion, a 23 percent$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 2016.2021. The increase was primarily attributable to increased operating results due to higher earnings resulting from improved realized refining margins, and distributions from our equity affiliates. This increase was partially offset by working capital changes, reflecting the negative impact of building inventory at higher commodity pricesimpacts and timing of refining payables payments, as well as lower marketing margins.
During 2016, cash of $2,963 million was provided by operating activities, a 48 percent decrease compared with 2015. The decrease was primarily attributable to lower realized refining margins, as well as a reduction in distributions from our equity affiliates. This decrease was partially offset by positive working capital of $501 million in 2016 compared to a negative working capital impact of $221 million in 2015. The positive working capital impact in 2016 was primarily driven by increased refining payables, due to an increase in feedstock costs at the end of 2016 as compared with 2015, and the timing of tax payments and refunds, partially offset by an increase in receivables, resulting from higher commodity prices.
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 95 percent92%, 90% and 84% in 2017, compared with 96 percent2023, 2022 and 2021, respectively. Our worldwide refining clean product yield was 85%, 84% and 83% in 2016.2023, 2022 and 2021, respectively.
Equity AffiliatesAffiliate Operating Distributions Our operating cash flows are also impacted by distribution decisions made by our equity affiliates, including DCP Midstream, CPChem and WRB.CPChem. Over the three years ended December 31, 2017, we received2023, our operating cash flows included aggregate distributions from our equity affiliates of $107 million$5.6 billion, including $2.2 billion from DCP Midstream, $1,854 million from CPChem and $300 million from WRB.CPChem. We cannot control the amount or timing of future distributionsdividends from equity affiliates; therefore, future distributionsdividend payments by these and other 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, 2017, 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, and DCP Partners closed a transaction in which DCP Midstream contributed subsidiaries owning all of its operating assets, $424 million of cash and $3.15 billion of debt to DCP Partners, in exchange for DCP Partners units which had an estimated fair value of $1.125 billion at the time of the transaction. We and our co-venturer retained our 50/50 investment in DCP Midstream,LLC and DCP Midstream, retained its incentive distribution rights (IDRs) in DCP Partners through its ownership of the general partner of DCP Partners. After the transaction, DCP Midstream held a 36 percent limited partner interest and a 2 percent general partner interest in DCP Partners. DCP Midstream, through its ownership of the general partner, has agreed, if required, to forgo receipt of IDRs up to $100 million annually (100 percent basis) through 2019, to support a minimum distribution coverage ratio for DCP Partners. In connection with the transaction, DCP Midstream terminated its revolving credit agreement, which had previously served to limit distributions to its owners while amounts had been borrowed under the facility. As a result, distributions to the owners of DCP Midstream resumed in 2017.
In 2015, CPChem made a special distribution to its owners, with our share totaling $696 million. CPChem funded the distribution by issuing $1.4 billion of senior notes with maturities ranging from three to five years, with a combination of fixed and floating interest rates. This cash inflow from CPChem was included in operating cash flows, as we had cumulative undistributed equity earnings attributable to CPChem in excess of the amount distributed. We did not receive any distributions from CPChem in the second half of 2017 due to the impacts of Hurricane Harvey on its Gulf Coast operations and its U.S. Gulf Coast Petrochemicals Project. We expect distributions from CPChem to resume in 2018.
Foreign Cash Holdings
With the passage of the Tax Act in December 2017, we are subject to a one-time deemed repatriation tax on foreign-sourced earnings. For a portion of those foreign earnings, we had previously deferred any associated U.S. income taxes. As a result of the Tax Act, we now have the ability to utilize a greater percentage of our worldwide cash and cash equivalents for domestic purposes without incurring additional material U.S. income taxes beyond those imposed by the one-time deemed repatriation tax, thereby improving the flexibility of our worldwide cash management system. We expect a portion of our foreign cash holdings will be reserved exclusively for foreign use in support of those operations and local statutory and regulatory requirements; however, that amount is not expected to materially impact our liquidity. Additionally, we do not expect the payment of the one-time deemed repatriation tax to materially impact our liquidity.
Phillips 66 Partners
In 2013, we formed Phillips 66 Partners, a publicly traded MLP, to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum products, and NGL pipelines and terminals, as well as other Midstream assets.
Ownership
At December 31, 2017, we owned a 55 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while its public unitholders owned a 43 percent limited partner interest and 13.8 million perpetual convertible preferred units. We consolidate Phillips 66 Partners as a variable interest entity for financial reporting purposes. See Note 3—Variable Interest Entities,LP Mergers, in the Notes to Consolidated Financial Statements, for additional information on why we consolidateregarding the partnership. As a result of this consolidation, the public common and preferred unitholders’ interests in Phillips 66 Partners are reflected as noncontrolling interests in our consolidated balance sheet, and totaled $2,314DCP 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, 2017. Generally, drop down transactions2022, to Phillips 66 Partners will eliminate$290 million at December 31, 2023. Borrowings under these agreements are due in consolidation, except for third-party debt or third-party equity offerings made by Phillips 66 Partners to finance such transactions. As2035 and 2038 and bear interest at a resultfloating rate based on the adjusted term SOFR plus an applicable margin, payable on the last day of Phillips 66 Partners’ third-party debt and equity offerings in 2017, primarilyeach month.
related to the contribution of assets in October 2017, our consolidated cash increased by $1,848 million and consolidated debt increased by $643 million.
Debt and Equity Financings
During the three years ended December 31, 2017, Phillips 66 Partners raised net proceeds of approximately $5.4 billion from the following third-party debt and equity offerings:
In October 2017, Phillips 66 Partners received net proceeds of $643 million from the issuance of $500 million of 3.750% Senior Notes due 2028 and $150 million of 4.680% Senior Notes due 2045.
In October 2017, Phillips 66 Partners received net proceeds of $737 million from a private placement of 13,819,791 perpetual convertible preferred units, at a price of $54.27 per unit.
In October 2017, Phillips 66 Partners received net proceeds of $295 million from a private placement of 6,304,204 common units, at a price of $47.59 per unit.
In October 2016, Phillips 66 Partners received net proceeds of $1,111 million from the issuance of $500 million of 3.550% Senior Notes due 2026 and $625 million of 4.900% Senior Notes due 2046.
In August 2016, Phillips 66 Partners received net proceeds of $299 million from a public offering of 6,000,000 common units, at a price of $50.22 per unit.
In June 2016, Phillips 66 Partners began issuing common units under a continuous offering program, which allows for the offering of up to $250 million of common units. Through December 31, 2017, net proceeds of $192 million had been received under this program.
In May 2016, Phillips 66 Partners received net proceeds of $656 million from a public offering of 12,650,000 common units, at a price of $52.40 per unit.
In February 2015, Phillips 66 Partners received net proceeds of $1,092 million from the issuance of $300 million of 2.646% Senior Notes due 2020, $500 million of 3.605% Senior Notes due 2025, and $300 million of 4.680% Senior Notes due 2045.
In February 2015, Phillips 66 Partners received net proceeds of $384 million from a public offering of 5,250,000 million common units, at a price of $75.50 per unit.
Phillips 66 Partners primarily used these net proceeds to fund the cash portion of acquisitions of assets from Phillips 66. See Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on Phillips 66 Partners and additional details on assets contributed to the partnership by us during 2017.
Phillips 66 Partners filed a new shelf registration statement for a second continuous offering program that became effective with the Securities and Exchange Commission (SEC) on January 23, 2018, related to the continuous offering of up to an aggregate of $250 million of common units, in amounts, at prices and on terms to be determined by the market conditions and other factors at the time of the offerings.
Credit Facilities and Commercial Paper
Phillips 66 hasand Phillips 66 Company
On June 23, 2022, we entered into a $5.0$5 billion revolving credit facility that extends until October 2021. This(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 may be used for direct bank borrowings,with Phillips 66 as support for issuances of letters of credit, orthe borrower and Phillips 66 Company as support for our commercial paper program.the guarantor. The facility is with a broad syndicate of financial institutions andFacility contains covenants that we consider usual and customary for an agreement of this type for comparable commercial borrowers,covenants that are similar to the previous revolving credit facility, including a maximum consolidated net debt-to-capitalization ratio of 60 percent. The agreement has customary events65% as of default, such as nonpaymentthe last day of principal when due; nonpaymenteach 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 interest, fees orthe Facility for up to two additional one-year terms, subject to, among other amounts; violationthings, the consent of covenants; cross-payment defaultthe lenders holding the majority of the commitments and cross-acceleration (inof each case, to indebtedness in excess of a threshold amount); and a change of control. Borrowingslender extending its commitment. Outstanding borrowings under the facility will incurFacility bear interest at either (a) the London Interbank Offered Rate (LIBOR) plus a margin based onadjusted term SOFR (as described in the credit rating of our senior unsecured long-term debt as determinedFacility) in effect from time to time by Standard & Poor’s (S&P) Ratings
Services and Moody’s Investors Service.plus the applicable margin; or (b) the reference rate (as described in the Facility) plus the applicable margin. The facilityFacility also provides for customary fees, including administrative agentcommitment fees. The pricing levels for the commitment fees and commitment fees.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, 2017,2023 and 2022, no amount had been drawn under this revolving credit agreement.the Facility.
We havePhillips 66 also has a $5.0$5 billion uncommitted commercial paper program for short-term working capital needs that is supported by our revolving credit facility.the Facility. Commercial paper maturities are generallycontractually limited to 90365 days. At December 31, 2017, we had2023 and 2022, no borrowings were outstanding under our commercial paperthe program.
Phillips 66 Partners has a
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 that extends until October 2021. The Phillips 66 Partners facility isunder its amended credit agreement (the Credit Agreement), with a broad syndicateborrowing capacity of financial institutions.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, 2017, Phillips 66 Partners2023, DCP LP had $25 million in borrowings outstanding under the Credit Agreement. At December 31, 2022, DCP LP had no borrowings outstanding under this facility.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 April 2017,November 2021, Phillips 66 completed a privateclosed its public offering of $600 million$1 billion aggregate principal amount of 3.300% senior unsecured notes consisting of $300 million of Notes due 2019 and $300 million of Notes due 2020.2052. Interest on the notes is a floating rate equal to three-month LIBOR plus 0.65% per annum for the 2019Senior Notes and three-month LIBOR plus 0.75% per annum for the 2020 Notes. Interest on both series of notesdue 2052 is payable quarterly in arrearssemiannually on January 15, April 15, JulyMarch 15 and OctoberSeptember 15 of each year, commencing in July 2017. The 2019 Notes mature on AprilMarch 15, 2019,2022. Proceeds received from the public offering were $982 million, net of underwriters’ discounts and the 2020 Notes mature on April 15, 2020.
Also in April 2017, Phillips 66 entered into term loan facilities with an aggregate borrowing amount of $900 million, consisting of a $450 million 364-day facility and a $450 million three-year facility. Interest on the term loans is a floating rate based on either the Eurodollar rate or the reference rate, plus a margin determined by our long-term credit ratings.
commissions, as well as debt issuance costs. In December 2021, Phillips 66 used the net proceeds from the issuance of the notes,this offering, together with the proceeds from the term loans, and cash on-handon hand, to repay $1 billion in aggregate principal amount of its outstanding 2.950%$2 billion 4.300% Senior Notes upon maturity in May 2017.due April 2022.
In October 2017, as part of the contribution of assets to Phillips 66 Partners discussed above,Term Loan
In April 2021, Phillips 66 Partners assumed theentered into a $450 million term loan outstanding underagreement with a one-year term and borrowed the 364-day facility originally issuedfull amount. The term loan agreement was repaid upon maturity in April 2017, and subsequently repaid the loan.2022 without premium or penalty.
In addition, we have capital lease obligations related to equipment and transportation assets, and the use of an oil terminal in the United Kingdom. These leases mature within the next sixteen years. The present value of our minimum capital lease payments for these obligations as of December 31, 2017, was $192 million.
Phillips 66 Availability of Debt and Equity Financing The $6.0 billion of outstanding Senior NotesWe have an A3 credit rating, with a stable outlook, from Moody’s Investors Service and $600 million of floating-rate notes issued by Phillips 66 are guaranteed by Phillips 66 Company, a 100-percent-owned subsidiary. Our senior unsecured long-term debt has been ratedBBB+ credit rating, with a stable outlook, from Standard & Poor’s. These investment grade by S&P (BBB+)ratings have served to lower our borrowing costs and Moody’s (A3).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 of our credit rating. If our creditby one or both rating deterioratedagencies. Failure to a level prohibitingmaintain 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.
In addition, weDCP 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 universal shelf registration statement on file with the SEC under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.rating downgrade by one or more rating agencies.
Off-Balance Sheet Arrangements
Lease Residual Value Guarantees Under the operating lease agreement onfor our headquarters facility in Houston, Texas, we have a residual value guarantee with a maximum future exposure of $554 million. The operating lease has a term of five years and provides us 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 airplanetruck leases with maximum potential future potential payments of $305exposures totaling $168 million. For information on our need to perform under the railcar lease guarantee, see the “Capital Requirements” section to follow.
In addition, we have guarantees outstanding related to certain joint-venture debt obligations, whichThese leases have remaining terms of upone to eightten 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 amountequity 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 futureoperations 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 third partiesthe potential obligations under these guarantees is approximately $308 million.the CECU at December 31, 2023.
See Note 13—15—Guarantees, in the Notes to Consolidated Financial Statements, for additional information on ourregarding 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, 2017,2023, was $10.1$19.4 billion and our total debt-to-capital ratio was 27 percent.38%. See Note 12—14—Debt, in the Notes to Consolidated Financial Statements, for our annual debt maturities over the next five years.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, 2018,2024, our Board of Directors declared a quarterly cash dividend of $0.70$1.05 per common share,share. The dividend is payable March 1, 2018,2024, to holders of record at the close of business on February 20, 2018.2024.
Share Repurchases On October 25, 2023, our Board of Directors approved a $5 billion increase to our share repurchase authorization. Since Julythe inception of our share repurchase program in 2012, our Board of Directors has at various times, authorized an aggregate of $25 billion of repurchases of our outstanding common stock, which aggregate to a total authorization of up to $12.0 billion. The share repurchases are expected to be funded primarily through available cash. The shares will be repurchased from time to time in the open market at our discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Since the inception of our share repurchases in 2012, through December 31, 2017, we have repurchased a total of 124,142,530213.8 million shares at an aggregate cost of $9.0$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 February 13, 2018,August 1, 2023, we entered intoacquired a Stock Purchase and Sale Agreement (Purchase Agreement) with Berkshire Hathaway Inc. and National Indemnity Company, a wholly owned subsidiary of Berkshire Hathaway, to repurchase 35 million shares of Phillips 66 common stock for an aggregate purchase price of approximately $3.3 billion. Pursuant to the Purchase Agreement, the purchase price per share of $93.725 was basedmarketing business on the volume-weighted-average priceU.S. West Coast for total consideration of our common stock on$269 million. This acquisition supports the New York Stock Exchange on February 13, 2018. The transaction closed on February 14, 2018. We funded the repurchase with cash on handplacement of approximately $1.9 billion and borrowings of approximately $1.4 billion under our commercial paper program. This specific share repurchase transaction was separately authorized by our Board of Directors and therefore does not impact previously announced authorizations which total up to $12.0 billion.
Railcar and Airplane Leases Residual Value Guarantees
On May 1, 2015, the U.S. Department of Transportation issued a final rule focused on the safe transportation of flammable liquids by rail. The final rule, which is being challenged, subjects new and existing railcars transporting crude oil in high volumes to heightened design standards, including thicker tank walls and heat shields, improved pressure relief valves and enhanced braking systems. We are currently evaluating the impact of the new regulations on our crude oil railcar fleet, which is mostly held under operating leases. The regulations become effective subsequent to the expiration dates of a portion of our leases. Some of our leases require a portion of the leased railcars to be retrofitted. Certain leases are subject to residual value guarantees. Under the lease terms, we have the option to either purchase the railcars or return them to the lessors. If railcars are returned to the lessors, we may be required to make the lessors whole under the residual value guarantees, which are subject to a cap. The current market demand for crude oil railcars is low, which has resulted in a decline in crude oil railcar prices. Based on third-party appraisals of the railcars’ fair value at the end of their lease terms, we estimated a total residual value deficiency of $109 millionrenewable diesel that would be payable at the end of the lease terms, with approximately one-half paid in late 2017 and the other half due in 2019. During 2017 and 2016, we recognized $73 million of expense related to the residual value deficiency of our leased railcars. In October 2017, upon maturity of one of our railcar leases, $53 million of the total residual value deficiency of $109 million was settled. The residual value deficiency of $36 million remaining at December 31, 2017, will be recognized on a straight-line basis through May 2019. Due to current market uncertainties, changes inproduced by the estimated fair values of railcars could occur, which could increase or decrease our currently estimated residual value deficiency. As of December 31, 2017, our maximum future exposure for residual value guarantees associated with our railcar and airplane leases was approximately $305 million. See Note 13—Guarantees, in the Notes to Consolidated Financial Statements.Rodeo renewable fuels facility.
Contractual ObligationsMarketing 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 following table summarizesM&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 aggregate contractual fixedspecialty lubricants and variable obligations as of December 31, 2017:
other businesses.
| | | | | | | | | | | | | | | | | | | Millions of Dollars | | | Payments Due by Period | | | Total |
| | Up to 1 Year |
| | Years 2-3 |
| | Years 4-5 |
| | After 5 Years |
| | | | | | | | | | | | | Debt obligations (a) | $ | 10,026 |
| | 25 |
| | 1,375 |
| | 2,050 |
| | 6,576 |
| | Capital lease obligations | 192 |
| | 16 |
| | 27 |
| | 22 |
| | 127 |
| | Total debt | 10,218 |
| | 41 |
| | 1,402 |
| | 2,072 |
| | 6,703 |
| | Interest on debt | 7,371 |
| | 436 |
| | 839 |
| | 765 |
| | 5,331 |
| | Operating lease obligations | 1,826 |
| | 533 |
| | 726 |
| | 241 |
| | 326 |
| | Purchase obligations (b) | 77,683 |
| | 32,236 |
| | 9,554 |
| | 6,698 |
| | 29,195 |
| | Other long-term liabilities (c) | | | | | | | | | | | Asset retirement obligations | 268 |
| | 7 |
| | 30 |
| | 18 |
| | 213 |
| | Accrued environmental costs | 458 |
| | 78 |
| | 117 |
| | 72 |
| | 191 |
| | Unrecognized income tax benefits (d) | 1 |
| | 1 |
| | (d) |
| | (d) |
| | (d) |
| | Total | $ | 97,825 |
| | 33,332 |
| | 12,668 |
| | 9,866 |
| | 41,959 |
|
| | (a) | For additional information, see Note 12—Debt, in the Notes to Consolidated Financial Statements. |
| | (b) | Represents any agreement to purchase goods or services that is enforceable, legally binding and specifies all significant terms. We expect these purchase obligations will be fulfilled by operating cash flows in the applicable maturity period. The majority of the purchase obligations are market-based contracts, including exchanges and futures, for the purchase of products such as crude oil and unfractionated NGL. The products are mostly used to supply our refineries and fractionators, optimize the supply chain, and resell to customers. Product purchase commitments with third parties totaled $35,480 million. In addition, $24,230 million are product purchases from CPChem, mostly for natural gas and NGL over the remaining contractual term of 82 years, and product purchases of $1,652 million from DCP entities for NGL over the remaining contractual term of three years. |
Purchase obligations of $5,097 million are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and product terminals, to transport, process, treat, and store products. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned facilities where we are the operator.
| | (c) | Excludes pensions. From 2018 through 2022, we expect to contribute an average of $70 million per year to our qualified and nonqualified pension and other postretirement benefit plans in the United States and an average of $34 million per year to our non-U.S. plans, which are expected to be in excess of required minimums in many cases. The U.S. five-year average consists of $60 million for 2018 and then approximately $75 million per year for the remaining four years. Our minimum funding in 2018 is expected to be $60 million in the United States and $35 million outside the United States. |
| | (d) | Excludes unrecognized income tax benefits of $33 million because the ultimate disposition and timing of any payments to be made with regard to such amounts are not reasonably estimable or the amounts relate to potential refunds. Also excludes interest and penalties of $8 million. Although unrecognized income tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity. |
Capital SpendingCorporate 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. | | | | | | | | | | | | | | | | Millions of Dollars | | | 2018 Budget |
| | 2017 |
| | 2016 |
| | 2015 |
| | Capital Expenditures and Investments | | | | | | | | | Midstream | $ | 1,218 |
| | 771 |
| | 1,453 |
| | 4,457 |
| | Chemicals | — |
| | — |
| | — |
| | — |
| | Refining | 827 |
| | 853 |
| | 1,149 |
| | 1,069 |
| | Marketing and Specialties | 140 |
| | 108 |
| | 98 |
| | 122 |
| | Corporate and Other | 116 |
| | 100 |
| | 144 |
| | 116 |
|
| $ | 2,301 |
| | 1,832 |
| | 2,844 |
| | 5,764 |
| | | | | | | | | | | Selected Equity Affiliates* | | | | | | | | | DCP Midstream | $ | 405 |
| | 268 |
| | 99 |
| | 438 |
| | CPChem | 398 |
| | 776 |
| | 987 |
| | 1,319 |
| | WRB | 143 |
| | 126 |
| | 164 |
| | 175 |
| | | $ | 946 |
| | 1,170 |
| | 1,250 |
| | 1,932 |
|
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 share of capital spending.
Midstream
Capital spendingshort- and long-term operating cash flows are highly dependent upon refining and marketing margins, NGL prices and chemicals margins. Prices and margins in our Midstream segment duringindustry 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 three-year periodoperations 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, 2017, included: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 Sweeny Fractionatorprevious 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 Freeport LPG Export Terminal projects.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. Bakken Pipeline project, developed
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 25-percent-owned joint ventures, 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 LLC and Energy Transfer Crude Oil Company.Company, LLC (ETCO) Construction activities relatedIn 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 increasing storage capacityprepare 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 crude oilcapital expenditures and petroleum products terminal located near Beaumont, Texas.investments, see the “Capital Spending” section below. Acquisition
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 certain southeast Louisiana NGL logistics assets comprising approximately 500 miles of pipelines and a storage cavern connecting multiple fractionation facilities, refineries and a petrochemical facility. Development of the Bayou Bridge Pipeline$3.5 billion, for notes issued by Phillips 66 Partners’ 40-percent-owned joint venture.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.
Construction activities
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 joint venturesDCP 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 in the Bakken production areacommon unitholders received 0.50 shares of North Dakota, including the Palermo Rail Terminal, Sacagawea Crude Pipeline, the New Town injection point, Keene CDP Terminal and Sacagawea Gas Pipeline. Expansion activities on thePhillips 66 common stock for each outstanding Phillips 66 Partners common unit. Phillips 66 Partners’ 33-percent-owned Sand Hills Pipeline including investmentperpetual 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 transportation of NGL from the Permian BasinNotes to the Texas Gulf Coast.
Expansion activitiesConsolidated Financial Statements, for additional information on the Phillips 66 Partners’ 50-percent-owned STACK Pipeline joint venture.merger transaction.
Spending associated with return, reliability and maintenance projects in
Dividends On February 7, 2024, our Transportation and NGL and Other businesses.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.
During the three-year period ended December 31, 2017, DCP Midstream’s capital expenditures and investments were $1.6 billion on a 100 percent basis. In 2015, we contributed $1.5 billion of cash to DCP Midstream and our co-venturer contributed its interests in certain operating assets of equal value, that are held as equity investments. Upon completion of this transaction, our interest in DCP Midstream remained at 50 percent.
In 2015, REX repaid $450 million of its debt, reducing its long-term debt to approximately $2.6 billion. REX funded the repayment through member cash contributions. Our 25 percent share was approximately $112 million, which we contributed to REX in 2015.
Share Repurchases
ChemicalsOn 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 three-year periodyear ended December 31, 2017, CPChem had2023, 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 self-funded capital program, and thus required no new capital infusions from us or our co-venturer. During this period,marketing business on a 100 percent basis, CPChem’s capital expenditures and investments were $6.2 billion. In addition, CPChem’s advances to its equity affiliates, primarily usedthe U.S. West Coast for project construction and start-up activities, were $139 million and its repayments received from equity affiliates were $140total consideration of $269 million. This acquisition supports the placement of renewable diesel that will be produced by the Rodeo renewable fuels facility.
Refining
Capital spending for the Refining segment during the three-year period ended December 31, 2017, was $3.1 billion, primarily for air emission reduction and clean fuels projects to meet new environmental standards, refinery upgrade projects to increase accessibility of advantaged crudes and improve product yields, improvements to the operating integrity of key processing units, and safety-related projects.
Key projects completed during the three-year period included:
Installation of a tail gas treating unit at the Humber Refinery to reduce emissions from the sulfur recovery units.
Installation of facilities to improve clean product yields at the Sweeny, Lake Charles and Ponca City refineries.
Installation of facilities to improve processing of advantaged crudes at the Billings and Ponca City refineries, as well as the jointly owned Wood River Refinery.
Installation of facilities to comply with U.S. Environmental Protection Agency (EPA) Tier 3 gasoline regulations at the Alliance, Lake Charles and Sweeny refineries, as well as the jointly owned Wood River Refinery.
Installation of a crude tank to increase accessibility of waterborne crude at the Los Angeles Refinery.
Major construction activities in progress include:
Installation of facilities to comply with EPA Tier 3 gasoline regulations at the Bayway and Ferndale refineries.
Installation of facilities to improve processing of advantaged crudes at the Lake Charles Refinery.
Installation of facilities to improve clean product yield at the Bayway Refinery, as well as the jointly owned Wood River Refinery.
Generally, our equity affiliates in the Refining segment are intended to have self-funding capital programs. During this three-year period, on a 100 percent basis, WRB’s capital expenditures and investments were $930 million. We expect WRB’s 2018 capital program to be self-funding.
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 | | | 2024
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, 2017,2023, was primarily for the acquisition of a marketing business and investmentsa 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 projects targeted at developing our new international sites. In addition, capital is used for reliabilitya retail marketing joint venture in the U.S. Central region; and maintenance projects at our Lubricants facilities.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, 2017,2023, was primarily for projects related to information technology and facilities.
20182024 Budget
Our 20182024 capital budget is $2.3$2.2 billion, including Phillips 66 Partners’$923 million for sustaining capital and $1.3 billion for growth capital. Our sustaining capital budget reflects $300 million of $0.6 billion. Thisefficiencies 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 DCP Midstream, CPChem and WRB totaling $0.9 billion, all of which is expected to be self-funded.$1 billion.
The Midstream capital budget of $1.2 billion is$985 million comprises a growth capital budget of $593 million focused on projectsenhancing our integrated withNGL wellhead-to-market value chain, as well as $250 million related to the repayment of our existing assets and infrastructure, including continued expansion25% share of the Beaumont Terminal, additional Gulf Coast fractionation capacity and investmentDakota Access’ debt due in pipelines and other terminals.2024. The Midstream capital budget also includes Phillips 66 Partners’ growth$392 million for sustaining projects, including expansionsDCP LP’s sustaining capital of $200 million. In Refining, the Sand Hills and Bayou Bridge pipelines, and construction of an isomerization unit at our Lake Charles Refinery. Refining’stotal capital budget of $0.8$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 directed toward reliability, safety andfund information technology projects.
environmental projects, as well as small, high-return, quick payout projects, primarily to improve clean product yields. In M&S, we plan to invest approximately $0.1 billion, primarily directed towards increasing retail sites in Europe. In Corporate and Other, we plan to fund approximately $0.1 billion in projects primarily related to information technology and facilities.
Contingencies
A number of lawsuits involving a variety of claims that arose in the ordinary course of business have been filed against us or are subject to indemnifications provided by us. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for financial recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-relatedincome tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.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 against us.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-relatedincome tax-related contingencies, we monitor tax legislation and court decisions, the status of tax audits and the statute of limitations within which a taxing authority can assert a liability. See Note 21—Income Taxes, in the Notes
Environmental Like other companies in our industry, weWe are subject to numerous international, federal, state and local environmental laws and regulations. Among the most significant of these international and federal environmental laws and regulations are the:
•U.S. Federal Clean Air Act, which governs air emissions.
•U.S. Federal Clean Water Act, which governs discharges into water bodies.bodies of water.
•European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH)(EU REACH), which governs the manufacture, placing on the market orproduction, marketing and use of chemicals.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 emissions.(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. Many
Other countries and many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of developing infrastructure and marketing and transporting products across state and international borders. For example, in California the South Coast Air Quality Management District (SCAQMD) approved amendments to the Regional Clean Air Incentives Market (RECLAIM) that became effective in 2016, which requirerequired a phased reduction of nitrogen oxide emissions through 2022, and potentially affectaffecting refineries in the Los Angeles metropolitan area. In 2017, SCAQMD required additional nitrogen dioxideoxide emissions reductions through 2025 and, began evaluating if and howon November 5, 2021, promulgated new regulations to replace the RECLAIM program with a traditional command and controlscontrol 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 emissionemissions 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 emissionemissions 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). ItThe law requires fuel producers and importers to provide additional renewable fuels for transportation motor fuels and stipulates a mix of various typestypes. Renewable Identification Numbers (RINs) form the mechanism used by the EPA to be included through 2022.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 increasingly stringent requirementsEPA’s renewable volume obligations (RVO) to date while establishing implementation,date. These obligations have been met using a variety of operating and capital strategies, along withstrategies. We are also implementing advanced technology development,and different technologies to address projected future requirements. It is uncertain how various future requirements contained in EISA,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 regulations promulgated thereunder, may be implementedEPA’s forecast for increasing compressed natural gas (CNG) and what their full impact may be on our operations. Forliquified natural gas (LNG) volumes derived from biogas. In addition, the 2018EPA increased total advanced biofuel volumes from the 5.63 billion gallons established for the 2022 compliance year the EPA has set volumes of advanced and total renewable fuel at higher levels than mandatedto 7.33 billion gallons in most previous years (although the 2018 compliance year volumes are roughly equivalent to those required for the 2017 compliance year); it is uncertain if these increased obligations will be achievable by fuel producers and shippers without drawing on the Renewable Identification Number (RIN) bank. For compliance years after 2018, we do not know whether the EPA will utilize its authority to reduce statutory volumes. Additionally, we2025. We may experience a decrease in demand for refined petroleum products due toand increased program costs if not fully recovered in the regulatory program as currently promulgated.market. This program continues to be the subject of possible Congressional review and re-promulgation in revised form, and the EPA’s final regulations pertainingestablishing RVO requirements have been and continue to the 2014 through 2017 compliance years arebe 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 fuel volume requirementsfuels into the motor fuels we produce. For the years ended December 31, 2023, 2022 and obligations. Additionally,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 forprice of RINs, has been the subject of fraudulent third-party activity,refinery production, blending activities, and it is reasonably possible that some RINs that we have purchased may be determined to be invalid. Should that occur, we could incur costs to replace those fraudulent RINs. Although the cost for replacing any fraudulently marketed RINs is not reasonably estimable at this time, we would not expect to incur the full financial impact of fraudulent RINs replacement costs in any single interim or annual period, and would not expect such costs to have a material impact on our results of operations or financial condition.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 both soil and groundwater.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 is borne solely by us. We anticipate increased expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.
We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As ofAt December 31, 2016,2022, we reported that we had been notified of potential liability under CERCLA and comparable state laws at 3122 sites within the United States. During 2017, there were three new sites for which we received notificationthe last quarter of potential liability, and three sites were deemed resolved and closed,2023, our legal organization approved the removal of one site following Department of Justice dismissal of Phillips 66, thus, leaving 3121 unresolved sites with potential liability at December 31, 2017.2023.
For mostthe majority of Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites for which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain 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 $690$824 million in 20172023 and are expected to be approximately $670$885 million and $640$863 million in 20182024 and 2019,2025, respectively. Capitalized environmental costs were $159$49 million in 20172023 and are expected to be approximately $185$76 million and $135$216 million, in 20182024 and 2019,2025, respectively. This amount doesThese amounts do not include capital expenditures made for another purposeother 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 materialthose costs and liabilities will not be incurred.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 greenhouse gas (GHG)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 review items,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 greenhouse gasGHG 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 Global Warming Solutions Act,Senate Bill No. 32, which requires the California Air Resources Board to develop regulations and market mechanisms that will target reduction of California’s GHG emissions by 25 percent by 2020 (as well as SB32, which requires further reduction of California's GHG emissions to 40 percent40% below the 1990 emission level by 2030, and the recently-enacted AB398,Assembly Bill 398, which extends the California GHG emission cap-and-tradecap and trade program through 2030).2030. Other GHG emissions programs in states in the western U.S. states 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 and2007. Phase II was undertaken from 2008 through to 2012. The current phase (Phase III) runs2012, and Phase III ran from 2013 through to 2020, with2020. Phase IV runs from January 1, 2021 through 2030 and sectors covered under the main changes being reduced allocationETS 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 free allowancesthe EU ETS and, increased auctioning of new allowances.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 company is actively engaged in minimizing any financial impact from the EUUK 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, the President of the United StatesTrump announced his intention to withdraw the United States from the Paris Agreement and that withdrawal became effective on November 4, 2020. On January 20, 2021, President Biden signed the “Acceptance on Behalf of the United States of America,” which allows the United States to rejoin the Paris Agreement. The United States officially rejoined the Paris Agreement in February 2021, which could lead to additional GHG emission reduction requirements for sources in the United States.
In the United States, some additional form of regulation is likely to be forthcoming in the future at the state or federal levels with respect to GHG emissions. Such regulation could take any of several forms that may result in the creation of additional costsfinancial 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. We are working
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, (suchsuch as a cap and trade system or a tax on emissions).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, (suchsuch as increased severe weather events, changes in sea levels and changes in temperature).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 generally accepted accounting principlesGAAP 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. CertainSome of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussion of critical accounting estimates along with the discussion of contingencies in this report, address all importantaddresses 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.
ImpairmentsBusiness 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 is expected.flows. If the sum of the undiscounted pre-taxexpected 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 groups of assets (for example, at a refinery complex level).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 of earnings for similar assets; or historical market transactions ofincluding similar assets, adjusted using principal market participant assumptions when necessary.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, ofincluding future volumes, commodity prices, operating costs, margins, discount rates and capital project decisions, considering all available information at the date of review.
Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment when there are indicators of a loss in value, such as a lack of sustained earnings capacity or a current fair value less than the investment’s carrying amount. When it is determined that an indicated impairment is other than temporary, a charge is recognized for the difference between the investment’s carrying value and its estimated fair value.
When determining whether a decline in value is other than temporary, management considers factors such as the length of timeduration 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 aobserved market analysisearnings multiples of comparable assets,companies, if appropriate. DifferingDifferent 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. |
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 | | | |
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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.
•Theimpact 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.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PHILLIPS 66
INDEX TO FINANCIAL STATEMENTS
Report of Management
Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this Annual Report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with 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 Under various contracts, permits and regulations,When we have a legal obligationsobligation to remove tangible equipment and restoreincur costs to retire an asset, we record a liability in the landperiod 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 end of operations at certain operational sites. Our largest asset removal obligations involve asbestos abatement at refineries. Estimatingtime the timing andobligation 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 paymentsthe related PP&E. Over time, the liability is increased for future asset removalchanges 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 difficult. Mostto keep our refining and other processing assets in good operating condition through routine repair and maintenance of these removal obligations are many years, or decades,component parts in the future,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 contracts and regulations often have vague descriptionsdates or ranges of what removal practices and criteria mustdates upon which we would retire these assets cannot be metreasonably estimated at this time. We will recognize liabilities for these obligations in the period when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuationsufficient information becomes available to estimate a date or range of the obligation, including discount and inflation rates, are also subject to change.potential retirement dates.
Environmental CostsFinancial 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 asset retirement obligations discussed above, we havecash settlement prior to contract expiration, certain obligationsexchange-traded futures may be settled by physical delivery of the underlying commodity.
•Enable us to complete environmental-related projects. 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 projects are primarily relatedobjectives optimize the value of our supply chain and may reduce our exposure to cleanupfluctuations 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 domestic refineries, underground storage sites and non-operated sites. Future environmental remediation costs are difficultRisk (VaR) limits. Compliance with these limits is monitored daily by our global risk group.
We use a VaR model to estimate because they are subjectthe 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 change dueour 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 factors as our senior notes, exposes us to changes in the uncertain magnitude of cleanup costs, timing and extent of such remedial actions that may be required, and the determinationfair value of our liability in proportion to that of other responsible parties.
Intangible Assets and Goodwill
At December 31, 2017, we had $756 million of intangible assets that we have determined to have indefinite useful lives, and therefore are not amortized. This judgmental assessment of an indefinite useful life must be continuously evaluated in the future. If,debt due to changes in factsmarket 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 circumstances, management determines these intangible assets have finite useful lives, amortization will commencerelated weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on effective rates at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to annual impairment tests that require management’s judgmenteach reporting date. The carrying amount of the estimatedour floating-rate debt approximates its fair value. The fair value of these intangible assets.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 | | | |
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Foreign Currency Risk We are exposed to foreign currency exchange rate fluctuations related to our international operations. Generally, we had $3.3 billiondo 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 goodwill recordedderivative instruments, see Note 17—Derivatives and Financial Instruments, in conjunction with past business combinations. Goodwillthe 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 amortized. Instead, goodwill is subjectforward-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 at least annual reviewsplace 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 impairment atour 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.
•Theimpact 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 reporting unit level. The reporting unitsresult 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 evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed. A reporting unit is an operating segment or a component that is one level below an operating segment.
Because quoted market prices for our reporting units are not available, management applies judgment in determining the estimated fair values of the reporting units for purposes of performing the goodwill impairment test. Management uses all available information to make this fair value determination, including observed market earnings multiples of comparable companies, our common stock price and associated total company market capitalization. Sales or dispositions of significant assets within a reporting unit are allocated a portion of that reporting unit’s goodwill, based on relative fair values, which impacts the amount of gain or loss on the sale or disposition.
We completed our annual impairment test as of October 1, 2017, and concluded that theassess fair value of eachintangible 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 reporting units continuedcustomers and the counterparties to exceed their respective recorded net book values by a significant percentage. A decline inour transactions, including the estimated fair valueimpact of onebankruptcies. •Cybersecurity incidents or moreother disruptions that compromise our information and expose us to liability. •The operation, financing and distribution decisions of our reporting unitsjoint ventures that we do not control. •The factors generally described in the future could result“Item 1A. Risk Factors” in an impairment. For example, a prolonged or significant decline in our stock price or a significant decline in actual or forecasted earnings could provide evidencethis report.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PHILLIPS 66
INDEX TO FINANCIAL STATEMENTS
Report of Management
Management prepared, and a need to record a material impairment of goodwill for one or more of our reporting units. After we have completed our annual test, we continue to monitor for impairment indicators, which can lead to further goodwill impairment testing.
Tax Assets and Liabilities
Our operations are subject to various taxes, including federal, state and foreign income taxes, property taxes, and transactional taxes such as excise, sales/use and payroll taxes. We record tax liabilities based on our assessment of existing tax laws and regulations. The recording of tax liabilities requires significant judgment and estimates. We recognize the financial statement effects of an income tax position when it is more likely than not that the position will be sustained upon examination by a taxing authority. A contingent liability related to a transactional tax claim is recorded if the loss is both probable and estimable. Actual incurred tax liabilities can vary from our estimates for a variety of reasons, including different interpretations of tax laws and regulations and different assessments of the amount of tax due.
In determining our income tax expense (benefit), we assess the likelihood our deferred tax assets will be recovered through future taxable income. Valuation allowances reduce deferred tax assets to an amount that will, more likely than not, be realized. Judgment is required in estimating the amount of valuation allowance, if any, that should be recorded against our deferred tax assets. Based on our historical taxable income, our expectationsresponsible for, the future,consolidated financial statements and available tax-planning strategies, we expect the net deferred tax assets will more likely than not be realized as offsets to reversing deferred tax liabilities and as reductions to future taxable income. If our actualother information appearing in this Annual Report. The consolidated financial statements present fairly the company’s financial position, results of operations differ from suchand 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 or our estimatesand 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 future taxable income change, the valuation allowance may needBoard of Directors. Management has made available to be revised.
New tax lawsErnst & Young LLP all of the company’s financial records and regulations,related data, as well as changesthe 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 existing tax lawsprovide reasonable assurance to the company’s management and regulations, are continuously being proposed or promulgated. The implementationdirectors regarding the preparation and fair presentation of future legislativepublished 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 regulatory tax initiatives could result in increased income tax liabilities that cannot be predicted at this time. The material provisionspresentation.
Management assessed the effectiveness of the Tax Act i) reduced the U.S. federal corporate income tax rate from 35 percent to 21 percent beginning January 1, 2018, ii) imposed a one-time deemed repatriation tax on foreign-sourced earnings that were previously tax deferred, and iii) created a new tax regime on post-2017 foreign-sourced earnings. We have not yet completed our accounting for the income tax effects of the Tax Actcompany’s internal control over financial reporting as of December 31, 2017, but have made reasonable estimates2023. In making this assessment, it used the criteria set forth by the Committee of those effects on our existing deferred income tax balances and the one-time deemed repatriation tax. As more guidelines and interpretationsSponsoring Organizations of the Tax Act become availableTreadway 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 next year, the estimates previously made may change, which could increase or decrease our revalued deferred income tax balancescompany’s internal control over financial reporting as of December 31, 2023, and the one-time deemed repatriation tax, with an offset to earnings.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
Projected Benefit ObligationsReport 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.
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/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 projected benefit obligationsSouth 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 defined benefit pensionfair value specialists, when performing audit procedures to evaluate the reasonableness of management’s estimates and postretirement plans impactsassumptions related to selection of the obligationsdiscount 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 balance sheetrecoverability analysis included evaluating Management’s significant inputs, including forecasted gathering and processing volumes, future commodity prices, the terminal value multiple, and the amountselection of benefit expensethe discount rate applied to estimated future cash flows included in Management’s cash flow model, included the income statement. The actuarial determinationfollowing, among others: •We tested the effectiveness of projected benefit obligationsinternal controls over financial reporting related to management’s preparation and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, ratesreview of return on plan assets, future interest rates, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmentalsignificant underlying assumptions used in the actuarial calculations significantly affect periodic financial statementsundiscounted 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 funding patterns over time. Benefit expense is particularly sensitiverig 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 return on plan assets assumptions. A one percentage-point decreaseterminal 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 assumption would increase annual benefit expense by an estimated $65 million, whileconsidering the comparability of operations to those of the Partnership –Developing a one percentage-point decrease in the return on plan assets assumption would increase annual benefit expense by an estimated $35 million. In determiningrange of independent estimates of the discount rate we use yieldsby 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 high-quality fixed income investmentsInternal 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 payments matchedthe 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 estimated distributionsPartnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of benefits fromthe Securities and Exchange Commission and the PCAOB.
We conducted our plans.
In 2017audit in accordance with the standards of the PCAOB and 2016,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 expected weighted-average long-term rate of return was approximately 6 percentaudit provides a reasonable basis for our worldwide pension plan assets. The actual weighted-average rateopinion.
Definition and Limitations of return was 15 percentInternal 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 10 percentthe preparation of financial statements for external purposes in 2017accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and 2016, respectively. Forprocedures that (1) pertain to the past ten years,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 weighted-average actual rate of return was 7 percent for worldwide pension plan assets.merger with Phillips 66 Partners LP (Phillips 66 Partners).
NEW ACCOUNTING STANDARDS
In February 2017, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2017-05, “Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20).” This ASU clarifies the scope and accounting for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. This ASU will eliminate the use of carryover basis for most nonmonetary exchanges, including contributions of assets toThe equity method joint ventures. These amendments could resultis used to account for investments in the entity recognizing a gain or loss on the sale or transfer of nonfinancial assets. Public entities should apply the guidanceaffiliates in ASU No. 2017-05 to annual periods beginning after December 15, 2017, including interim periods within those periods. There was no impact on our financial statements from adopting this ASU on January 1, 2018.
In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which clarifies the definition of a business with the objective of adding guidance to assist in evaluating whether transactions should be accounted for as acquisitions of assets or businesses. The amendment provides a screen for determining when a transaction involves an acquisition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset, or a group of similar identifiable assets, then the transaction is not considered an acquisition of a business. If the screen is not met, then the amendment requires that to be considered a business, the operation must include at a minimum an input and a substantive process that together significantly contribute towe have the ability to create an output. The guidance may reduceexert significant influence over the numberaffiliates’ operating and financial policies, including VIEs, of transactions accounted for as business acquisitions. Public business entities should applywhich we are not the guidance in ASU No. 2017-01 to annual periods beginning after December 15, 2017, including interim periods within those periods, with early adoption permitted. The amendments should be applied prospectivelyprimary beneficiary. Other securities and no disclosuresinvestments are required at the effective date. There was no impact on our financial statements from adopting this ASU on January 1, 2018.
In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The new standard amends the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which may result in earlier recognition of losses. Public business entities should apply the guidance in ASU No. 2016-13 for annual periods beginning after December 15, 2019, including interim periods within those annual periods. Early adoption will be permitted for annual periods beginning after December 15, 2018. We are currently evaluating the provisions of ASU No. 2016-13 and assessing the impact on our financial statements.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” The new standard establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will continue to be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. Similarly, lessors will be required to classify leases as sales-type, finance or operating, with classification affecting the pattern of income recognition. Classification for both lessees and lessors will be based on an assessment of whether risks and rewards as well as substantive control have been transferred through a lease contract. Public business entities should apply the guidance in ASU No. 2016-02 for annual periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements. We are currently evaluating the provisions of ASU No. 2016-02 and assessing its impact on our financial statements. As part of our assessment to-date, we have formed an implementation team, commenced identification of our lease population and selected a lease software package. We expect the adoption of ASU 2016-02 will materially gross up our consolidated balance sheet with the recognition of the ROU assets and operating lease liabilities. The impact to our consolidated statements of income and cash flows is not expected to be material. The new standard will also require additional disclosures for financing and operating leases.
In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities,” to meet its objective of providing more decision-useful information about financial instruments. The majority of this ASU’s provisions amend only the presentation or disclosures of financial instruments; however, one provision will also affect net income. Equity investments carried under the cost method or lower of cost or fair value method of accounting, in accordance with current GAAP, will have to begenerally carried at fair value, upon adoption of ASU No. 2016-01, with changes in fair value recorded in net income. For equity investments that do not have readily determinable fair values, a company may elect to carry such investments ator cost less impairments, if any, adjusted up or down for price changes in similar financial instruments issued by the investee, when and if observed. Public business entities should apply the guidance in ASU No. 2016-01See Note 8—Investments, Loans and Long-Term Receivables, for annual periods beginning after December 15, 2017, and interim periods within those annual periods, with early adoption prohibited. We are currently evaluating the provisions of ASU No. 2016-01. Our initial review indicates that ASU No. 2016-01 will have a limited impactfurther discussion on our significant unconsolidated VIEs.
Use of Estimates The preparation of financial statements.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.
In May 2014,Foreign Currency
Adjustments resulting from the FASB issued ASU No. 2014-09, “Revenueprocess 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 Contractsremeasuring 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 Customers (Topic 606)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).” This ASU 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 updatesasset, and is amortized over the useful life of the related asset.
Impairment of Properties, Plants and Equipment PP&E used in operations are intendedassessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to improve comparabilitybe generated by an asset group. If indicators of revenue recognition practices across entities, industries, jurisdictionspotential 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 markets and expand disclosure requirements. In August 2015,project decisions, considering all available evidence at the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The amendment in this ASU defers the effective date of ASU No. 2014-09 for all entities for one year. Public business entities should applyreview.
Property Dispositions When complete units of depreciable property are sold, the guidanceasset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in ASU No. 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Our assessment work primarily included the formation of an implementation work team, training“Net gain on the new ASU’s revenue recognition model, contract review and documentation and the monitoring of industry interpretative issues. We adopted the standard on January 1, 2018, using the modified retrospective application. Our evaluation of the new ASU is near completion, which includes understanding the impact of adoption on earnings from equity method investments. Based upon our analysis to-date, the primary impact of adoption of the new standard is the netting of sales-based taxes collected from our customers against revenue. Sales-based taxes include excise taxes on sales of petroleum products as noteddispositions” line item on our consolidated statement of income. WeWhen 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 identified anyamortized, 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 material impact on our financial statements other than disclosures.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
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKWhen 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.
Financial Instrument Market Risk
We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our cash flows or earningsare exposed to changes in commodity prices, foreign currency exchange rates or interest rates. We may use financial- and commodity-based derivative contracts to manage themarket risks produced by changes in the prices of crude oil, and related products,refined petroleum product, NGL, natural gas, NGL,renewable feedstock and electric power;power, as well as fluctuations in interest rates and foreign currency exchange rates; or to capture market opportunities.
Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board of Directors, that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient market liquidity for comparable valuations. The Authority Limitations document also establishes Value at Risk (VaR) limits,rates. We and compliance with these limits is monitored daily. Our Chief Financial Officer monitors risks resulting from foreign currency exchange rates and interest rates. Our Executive Vice President, Marketing and Commercial monitors commodity price risk. The Commercial organization manages our commercial marketing, optimizes our commodity flows and positions, and monitors related riskscertain of our businesses.subsidiaries may hold and use derivative contracts to manage these risks.
Commodity Price Risk We sell into or receive supply from the worldwide crude oil, refined products, natural gas, NGL, and electric power markets, exposing our revenues, purchases, cost of operating activities, and cash flows to fluctuations in the prices for these commodities. Generally, our policy is to remain exposed to the market prices of commodities. Consistent with this policy, our Commercial organization useswe use derivative contracts to effectively convert our exposure from fixed-price sales or purchase contracts, often requested byspecified in contracts with refined petroleum product customers, back to fluctuatingfloating market prices. Conversely, our Commercial organizationWe also usesuse futures, forwards, swaps and options in various markets to accomplish the following objectives to optimize the value ofobjectives:
•Balance physical systems or meet our supply chain,refinery requirements and this may reduce our exposure to fluctuations in market prices:
demand. In addition to cash settlement prior to contract expiration, certain exchange-traded futures contracts may be settled by physical delivery of the underlying commodity. This provides another source of supply to balance physical systems or to meet our refinery requirements and marketing demand. Manage the risk to our cash flows from price exposures on specific crude oil, refined product, natural gas, NGL, and electric power transactions.
•Enable us to use the market knowledge gained from theseour 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 financial instruments and derivative commodity instruments held or issued, including commodity purchase and sales contracts recorded on the balance sheet at December 31, 2017, as derivative instruments.issued. Using the Monte Carlo simulation, a 95 percent95% confidence level and a one-day holding period, the VaR for thosederivative commodity instruments issued or held for trading purposes at December 31, 20172023 and 2016,2022, was immaterial to our cash flows and net income. The VaR for instruments held for purposes other than trading at December 31, 2017 and 2016, was also immaterial to our cash flows and net income.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 theeach 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 2017 | | | | | | | | | | | | 2018 | | $ | — |
| | — | % | | $ | 25 |
| | 1.94 | % | | 2019 | | | — |
| | — |
| | | 300 |
| | 2.01 |
| | 2020 | | | 300 |
| | 2.65 |
| | | 775 |
| | 2.31 |
| | 2021 | | | — |
| | — |
| | | 50 |
| | 1.94 |
| | 2022 | | | 2,000 |
| | 4.30 |
| | | — |
| | — |
| | Remaining years | | | 6,576 |
| | 4.78 |
| | | — |
| | — |
| | Total | | $ | 8,876 |
| | | | $ | 1,150 |
| | | | Fair value | | $ | 9,746 |
| | | | $ | 1,150 |
| | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | | | |
\ | | | | | | | | | | | | | | | | | | Millions of Dollars, Except as Indicated | | Expected Maturity Date | | Fixed Rate Maturity | | | Average Interest Rate |
| | Floating Rate Maturity | | | Average Interest Rate |
| | Year-End 2016 | | | | | | | | | | | | 2017 | | $ | 516 |
| | 3.08 | % | | $ | 15 |
| | 1.80 | % | | 2018 | | | 518 |
| | 2.39 |
| | | 12 |
| | 0.80 |
| | 2019 | | | 18 |
| | 7.00 |
| | | — |
| | — |
| | 2020 | | | 816 |
| | 2.76 |
| | | 12 |
| | 0.80 |
| | 2021 | | | — |
| | — |
| | | 221 |
| | 1.86 |
| | Remaining years | | | 7,926 |
| | 4.72 |
| | | — |
| | — |
| | Total | | $ | 9,794 |
| | | | $ | 260 |
| | | | Fair value | | $ | 10,260 |
| | | | $ | 260 |
| | |
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 15—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.
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 thethese 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 operate in general.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 as theyand 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 forecastforecasted in theany forward-looking statements. Any differencesstatement. Factors that could resultcause actual results to differ materially from a variety of factors, including the following:those in our forward-looking statements include:
•Fluctuations in market conditions, including NGL, crude oil, refined petroleum productsproduct and natural gas prices and refining, marketing and petrochemical margins.margins and demand. Failure•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 new productsalternative markets and servicesarrangements 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 market acceptance.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 chemicalschemical 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 DCP Midstream’s assets and itsour midstream assets. •Our ability to connect supplies to its gathering and processing systems, residue gas and NGL infrastructure. Inability to timely obtain or maintain permits, including those necessary for capital projects;projects.
•Our ability to comply with government regulations;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.
•Theimpact 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 timely complete construction of, announced and future capital projects.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 cyber attacks.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 investmentinvestments required, or reduced demand for products, as a result of existing or future environmental rules and regulations.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. General domestic and international economic and political developments including: armed hostilities; expropriation of assets; changes in governmental policies relating to NGL, crude oil, natural gas or refined product pricing, regulation or taxation; and other political, economic or diplomatic developments.
•Changes in tax, environmental and other laws and regulations (including alternative energy mandates) applicable to our business. •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.ventures that we do not control. Domestic and foreign supplies of crude oil and other feedstocks.
Domestic and foreign supplies of petrochemicals and refined products, such as gasoline, diesel, aviation fuel and home heating oil.
Governmental policies relating to exports of crude oil and natural gas.
Overcapacity or undercapacity in the midstream, chemicals and refining industries.
Fluctuations in consumer demand for refined products.
•The factors generally described in Item“Item 1A.—Risk FactorsFactors” in this report.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PHILLIPS 66
INDEX TO FINANCIAL STATEMENTS
Report of Management
Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report.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, 2017.2023. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Control—Integrated Framework (2013). Based on this assessment, management concluded the company’s internal control over financial reporting was effective as of December 31, 2017.2023.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2017,2023, and their report is included herein.
| | | | | | | | | | | | | | | /s/ Greg C. GarlandMark E. Lashier | | /s/ Kevin J. Mitchell | | | | Greg C. GarlandMark E. Lashier | | Kevin J. Mitchell | ChairmanPresident and Chief Executive Officer | | Executive Vice President Finance and | | Chief Executive Officer | Chief Financial Officer | | | | | | | | | |
Date: February 23, 201821, 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, 20172023 and 2016,2022, 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, 2017,2023, and the related notes (collectively referred to as the financial statements)“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 consolidated financial position of the Company as ofat December 31, 20172023 and 2016,2022, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2023, 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’sCompany's internal control over financial reporting as of December 31, 2017,2023, 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 23, 201821, 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 includeincluded 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
Houston, Texas
February 23, 2018
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, 2017,2023, based on criteria established in Internal Control-IntegratedControl—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, 2017,2023, 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, 20172023 and 2016,2022, 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, 2017,2023, and the related notes and our report dated February 23, 201821, 2024, expressed an unqualified opinion thereon.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 23, 2018
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. | | | | | |
| | | | | | | | | | | | | Millions of Dollars | | Years Ended December 31 | 2017 |
|
| 2016 |
|
| 2015 |
| | Revenues and Other Income | | | | | | | Sales and other operating revenues* | $ | 102,354 |
| | 84,279 |
| | 98,975 |
| | Equity in earnings of affiliates | 1,732 |
| | 1,414 |
| | 1,573 |
| | Net gain on dispositions | 15 |
| | 10 |
| | 283 |
| | Other income | 521 |
| | 74 |
| | 118 |
| | Total Revenues and Other Income | 104,622 |
| | 85,777 |
| | 100,949 |
| | | | | | | | | Costs and Expenses | | | | | | | Purchased crude oil and products | 79,409 |
| | 62,468 |
| | 73,399 |
| | Operating expenses | 4,699 |
| | 4,275 |
| | 4,294 |
| | Selling, general and administrative expenses | 1,695 |
| | 1,638 |
| | 1,670 |
| | Depreciation and amortization | 1,318 |
| | 1,168 |
| | 1,078 |
| | Impairments | 24 |
| | 5 |
| | 7 |
| | Taxes other than income taxes* | 13,462 |
| | 13,688 |
| | 14,077 |
| | Accretion on discounted liabilities | 22 |
| | 21 |
| | 21 |
| | Interest and debt expense | 438 |
| | 338 |
| | 310 |
| | Foreign currency transaction (gains) losses | — |
| | (15 | ) | | 49 |
| | Total Costs and Expenses | 101,067 |
| | 83,586 |
| | 94,905 |
| | Income before income taxes | 3,555 |
| | 2,191 |
| | 6,044 |
| | Income tax expense (benefit) | (1,693 | ) | | 547 |
| | 1,764 |
| | Net Income | 5,248 |
| | 1,644 |
| | 4,280 |
| | Less: net income attributable to noncontrolling interests | 142 |
| | 89 |
| | 53 |
| | Net Income Attributable to Phillips 66 | $ | 5,106 |
| | 1,555 |
| | 4,227 |
| | | | | | | | Net Income Attributable to Phillips 66 Per Share of Common Stock (dollars) | | | | | | | Basic | $ | 9.90 |
| | 2.94 |
| | 7.78 |
| | Diluted | 9.85 |
| | 2.92 |
| | 7.73 |
| | | | | | | | Dividends Paid Per Share of Common Stock (dollars) | $ | 2.73 |
| | 2.45 |
| | 2.18 |
| | | | | | | | Weighted-Average Common Shares Outstanding (thousands) | | | | | | | Basic | 515,090 |
| | 527,531 |
| | 542,355 |
| | Diluted | 518,508 |
| | 530,066 |
| | 546,977 |
| | * Includes excise taxes on sales of petroleum products: | $ | 13,054 |
| | 13,381 |
| | 13,780 |
| | 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 Statement of Comprehensive Income | Phillips 66 | | | | | | | Millions of Dollars | | Years Ended December 31 | 2017 |
| | 2016 |
| | 2015 |
| | | | | | | | | Net Income | $ | 5,248 |
| | 1,644 |
| | 4,280 |
| | Other comprehensive income (loss) | | | | | | | Defined benefit plans | | | | | | | Actuarial loss arising during the period | (1 | ) | | (178 | ) | | (138 | ) | | Amortization to net income of net actuarial loss and settlements | 176 |
| | 94 |
| | 174 |
| | Curtailment gain | — |
| | 31 |
| | — |
| | Plans sponsored by equity affiliates | 10 |
| | (11 | ) | | 11 |
| | Income taxes on defined benefit plans | (70 | ) | | 13 |
| | (13 | ) | | Defined benefit plans, net of tax | 115 |
| | (51 | ) | | 34 |
| | Foreign currency translation adjustments | 268 |
| | (301 | ) | | (163 | ) | | Income taxes on foreign currency translation adjustments | (9 | ) | | 5 |
| | 7 |
| | Foreign currency translation adjustments, net of tax | 259 |
| | (296 | ) | | (156 | ) | | Cash flow hedges | 6 |
| | 8 |
| | — |
| | Income taxes on hedging activities | (2 | ) | | (3 | ) | | — |
| | Hedging activities, net of tax | 4 |
| | 5 |
| | — |
| | Other Comprehensive Income (Loss), Net of Tax | 378 |
| | (342 | ) | | (122 | ) | | Comprehensive Income | 5,626 |
| | 1,302 |
| | 4,158 |
| | Less: comprehensive income attributable to noncontrolling interests | 142 |
| | 89 |
| | 53 |
| | Comprehensive Income Attributable to Phillips 66 | $ | 5,484 |
| | 1,213 |
| | 4,105 |
| | 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 Balance Sheet | Phillips 66 | | | | | | | Millions of Dollars | | At December 31 | 2017 |
| | 2016 |
| | Assets | | | | | Cash and cash equivalents | $ | 3,119 |
| | 2,711 |
| Accounts and notes receivable (net of allowances of $29 million in 2017 and $34 million in 2016) | 6,424 |
| | 5,485 |
| | Accounts and notes receivable—related parties | 1,082 |
| | 912 |
| | Inventories | 3,395 |
| | 3,150 |
| | Prepaid expenses and other current assets | 370 |
| | 422 |
| | Total Current Assets | 14,390 |
| | 12,680 |
| | Investments and long-term receivables | 13,941 |
| | 13,534 |
| | Net properties, plants and equipment | 21,460 |
| | 20,855 |
| | Goodwill | 3,270 |
| | 3,270 |
| | Intangibles | 876 |
| | 888 |
| | Other assets | 434 |
| | 426 |
| | Total Assets | $ | 54,371 |
| | 51,653 |
| | | | | | | Liabilities | | | | | Accounts payable | $ | 7,242 |
| | 6,395 |
| | Accounts payable—related parties | 785 |
| | 666 |
| | Short-term debt | 41 |
| | 550 |
| | Accrued income and other taxes | 1,002 |
| | 805 |
| | Employee benefit obligations | 582 |
| | 527 |
| | Other accruals | 455 |
| | 520 |
| | Total Current Liabilities | 10,107 |
| | 9,463 |
| | Long-term debt | 10,069 |
| | 9,588 |
| | Asset retirement obligations and accrued environmental costs | 641 |
| | 655 |
| | Deferred income taxes | 5,008 |
| | 6,743 |
| | Employee benefit obligations | 884 |
| | 1,216 |
| | Other liabilities and deferred credits | 234 |
| | 263 |
| | Total Liabilities | 26,943 |
| | 27,928 |
| | | | | | | Equity | | | | Common stock (2,500,000,000 shares authorized at $0.01 par value) Issued (2017—643,835,464 shares; 2016—641,593,854 shares) | | | | | Par value | 6 |
| | 6 |
| | Capital in excess of par | 19,768 |
| | 19,559 |
| | Treasury stock (at cost: 2017—141,565,145 shares; 2016—122,827,264 shares) | (10,378 | ) | | (8,788 | ) | | Retained earnings | 16,306 |
| | 12,608 |
| | Accumulated other comprehensive loss | (617 | ) | | (995 | ) | | Total Stockholders’ Equity | 25,085 |
| | 22,390 |
| | Noncontrolling interests | 2,343 |
| | 1,335 |
| | Total Equity | 27,428 |
| | 23,725 |
| | Total Liabilities and Equity | $ | 54,371 |
| | 51,653 |
| | 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 Cash Flows | Phillips 66 | | | | | | | Millions of Dollars | | Years Ended December 31 | 2017 |
| | 2016 |
| | 2015 |
| | Cash Flows From Operating Activities | | | | | | | Net income | $ | 5,248 |
| | 1,644 |
| | 4,280 |
| | Adjustments to reconcile net income to net cash provided by operating activities | | | | | | | Depreciation and amortization | 1,318 |
| | 1,168 |
| | 1,078 |
| | Impairments | 24 |
| | 5 |
| | 7 |
| | Accretion on discounted liabilities | 22 |
| | 21 |
| | 21 |
| | Deferred income taxes | (1,886 | ) | | 612 |
| | 529 |
| | Undistributed equity earnings | (516 | ) | | (815 | ) | | 185 |
| | Net gain on dispositions | (15 | ) | | (10 | ) | | (283 | ) | | Gain on consolidation of business | (423 | ) | | — |
| | — |
| | Other | (186 | ) | | (163 | ) | | 117 |
| | Working capital adjustments | | | | | | | Decrease (increase) in accounts and notes receivable | (1,182 | ) | | (1,258 | ) | | 2,129 |
| | Decrease (increase) in inventories | (176 | ) | | 216 |
| | (144 | ) | | Decrease (increase) in prepaid expenses and other current assets | 104 |
| | (147 | ) | | 324 |
| | Increase (decrease) in accounts payable | 1,153 |
| | 1,579 |
| | (2,300 | ) | | Increase (decrease) in taxes and other accruals | 163 |
| | 111 |
| | (230 | ) | | Net Cash Provided by Operating Activities | 3,648 |
| | 2,963 |
| | 5,713 |
| | | | | | | | | Cash Flows From Investing Activities | | | | | | | Capital expenditures and investments | (1,832 | ) | | (2,844 | ) | | (5,764 | ) | | Proceeds from asset dispositions* | 86 |
| | 156 |
| | 70 |
| | Advances/loans—related parties | (10 | ) | | (432 | ) | | (50 | ) | | Collection of advances/loans—related parties | 326 |
| | 108 |
| | 50 |
| | Restricted cash received from consolidation of business | 318 |
| | — |
| | — |
| | Other | (34 | ) | | (146 | ) | | (44 | ) | | Net Cash Used in Investing Activities | (1,146 | ) | | (3,158 | ) | | (5,738 | ) | | | | | | | | | Cash Flows From Financing Activities | | | | | | | Issuance of debt | 3,508 |
| | 2,090 |
| | 1,169 |
| | Repayment of debt | (3,678 | ) | | (833 | ) | | (926 | ) | | Issuance of common stock | 35 |
| | 34 |
| | 31 |
| | Repurchase of common stock | (1,590 | ) | | (1,042 | ) | | (1,512 | ) | | Dividends paid on common stock | (1,395 | ) | | (1,282 | ) | | (1,172 | ) | | Distributions to noncontrolling interests | (120 | ) | | (75 | ) | | (46 | ) | | Net proceeds from issuance of Phillips 66 Partners LP common and preferred units | 1,205 |
| | 972 |
| | 384 |
| | Other | (76 | ) | | (42 | ) | | (45 | ) | | Net Cash Used in Financing Activities | (2,111 | ) | | (178 | ) | | (2,117 | ) | | | | | | | | | Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash | 17 |
| | 10 |
| | 9 |
| | | | | | | | | Net Change in Cash, Cash Equivalents and Restricted Cash | 408 |
| | (363 | ) | | (2,133 | ) | | Cash, cash equivalents and restricted cash at beginning of year | 2,711 |
| | 3,074 |
| | 5,207 |
| | Cash, Cash Equivalents and Restricted Cash at End of Year | $ | 3,119 |
| | 2,711 |
| | 3,074 |
| | * Includes return of investments in equity affiliates. | | 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 | |
| | | | | | | | | | | | | | | | | | 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, 2014 | $ | 6 |
| 19,040 |
| (6,234 | ) | 9,309 |
| (531 | ) | 447 |
| 22,037 |
| | Net income | — |
| — |
| — |
| 4,227 |
| — |
| 53 |
| 4,280 |
| | Other comprehensive loss | — |
| — |
| — |
| — |
| (122 | ) | — |
| (122 | ) | | Cash dividends paid on common stock | — |
| — |
| — |
| (1,172 | ) | — |
| — |
| (1,172 | ) | | Repurchase of common stock | — |
| — |
| (1,512 | ) | — |
| — |
| — |
| (1,512 | ) | | Benefit plan activity | — |
| 105 |
| — |
| (16 | ) | — |
| — |
| 89 |
| | Issuance of Phillips 66 Partners LP common units | — |
| — |
| — |
| — |
| — |
| 384 |
| 384 |
| | Distributions to noncontrolling interests | — |
| — |
| — |
| — |
| — |
| (46 | ) | (46 | ) | | December 31, 2015 | 6 |
| 19,145 |
| (7,746 | ) | 12,348 |
| (653 | ) | 838 |
| 23,938 |
| | Net income | — |
| — |
| — |
| 1,555 |
| — |
| 89 |
| 1,644 |
| | Other comprehensive loss | — |
| — |
| — |
| — |
| (342 | ) | — |
| (342 | ) | | Cash dividends paid on common stock | — |
| — |
| — |
| (1,282 | ) | — |
| — |
| (1,282 | ) | | Repurchase of common stock | — |
| — |
| (1,042 | ) | — |
| — |
| — |
| (1,042 | ) | | Benefit plan activity | — |
| 106 |
| — |
| (13 | ) | — |
| — |
| 93 |
| | Issuance of Phillips 66 Partners LP common units | — |
| 308 |
| — |
| — |
| — |
| 483 |
| 791 |
| | Distributions to noncontrolling interests | — |
| — |
| — |
| — |
| — |
| (75 | ) | (75 | ) | | December 31, 2016 | 6 |
| 19,559 |
| (8,788 | ) | 12,608 |
| (995 | ) | 1,335 |
| 23,725 |
| | Net income | — |
| — |
| — |
| 5,106 |
| — |
| 142 |
| 5,248 |
| | Other comprehensive income | — |
| — |
| — |
| — |
| 378 |
| — |
| 378 |
| | Cash dividends paid on common stock | — |
| — |
| — |
| (1,395 | ) | — |
| — |
| (1,395 | ) | | Repurchase of common stock | — |
| — |
| (1,590 | ) | — |
| — |
| — |
| (1,590 | ) | | Benefit plan activity | — |
| 72 |
| — |
| (13 | ) | — |
| — |
| 59 |
| | Issuance of Phillips 66 Partners LP common and preferred units | — |
| 137 |
| — |
| — |
| — |
| 986 |
| 1,123 |
| | Distributions to noncontrolling interests | — |
| — |
| — |
| — |
| — |
| (120 | ) | (120 | ) | | December 31, 2017 | $ | 6 |
| 19,768 |
| (10,378 | ) | 16,306 |
| (617 | ) | 2,343 |
| 27,428 |
|
| | | | | | | | | | | | | | | | | | 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. | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Shares in Thousands | | | | | Common Stock Issued |
| Treasury Stock |
| | December 31, 2014 | | | 637,032 |
| 90,650 |
| | Repurchase of common stock | | | — |
| 19,276 |
| | Shares issued—share-based compensation | | | 2,304 |
| — |
| | December 31, 2015 | | | 639,336 |
| 109,926 |
| | Repurchase of common stock | | | — |
| 12,901 |
| | Shares issued—share-based compensation | | | 2,258 |
| — |
| | December 31, 2016 | | | 641,594 |
| 122,827 |
| | Repurchase of common stock | | | — |
| 18,738 |
| | Shares issued—share-based compensation | | | 2,241 |
| — |
| | December 31, 2017 | | | 643,835 |
| 141,565 |
| | See Notes to Consolidated Financial Statements. |
| | | | | | | | | Notes to Consolidated Financial Statements | Phillips 66 |
Note 1—Summary of Significant Accounting Policies
| | ▪ | Consolidation Principles and Investments Consolidation Principles and Investments—Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies. When we do not have the ability to exert significant influence, the investment is classified either as available-for-sale if fair value is readily determinable, or as the cost method if fair value is not readily determinable. Undivided interests in pipelines, natural gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are generally carried at cost.
|
| | ▪ | Recasted Financial Information—Certain prior period financial information has been recasted to reflect the current year’s presentation.
|
| | ▪ | Foreign Currency Translation—Adjustments resulting from the process of translating foreign functional currency financial statements 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 denominated in a foreign currency into the functional currency of our subsidiary holding the asset or liability. We include these transaction gains and losses in current earnings. Most of our foreign operations use their local currency as the functional currency. |
| | ▪ | Use of Estimates—The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.
|
| | ▪ | Revenue Recognition—Revenues associated with sales of crude oil, natural gas liquids (NGL), petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.
|
Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty on the balance sheet if the legal right of offset exists and certain other criteria are entered into in contemplation of one another, are combinedmet. When applicable, we also net collateral payables and reported in the “Purchased crude oilreceivables against derivative assets and products” line on our consolidated statement of income (i.e., these transactions are recorded net).derivative liabilities, respectively.
| | ▪ | 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.
|
| | ▪ | Shipping and Handling Costs—We record shipping and handling costs in the “Purchased crude oil and products” line on our consolidated statement of income. Freight costs billed to customers are recorded in “Sales and other operating revenues.”
|
| | ▪ | 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 are recorded on the balance sheet at fair value. We have elected to net derivative assets and liabilities with the same counterparty on the balance sheet if the right of offset exists and certain other criteria are met. We also net collateral payables or receivables against derivative assets and derivative liabilities, respectively.
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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 a cash flow hedgehedges are recognized in other comprehensive income (loss) and appear on the balance sheet in accumulated other comprehensive income (loss) until the hedged transaction istransactions are recognized in earnings; however,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 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.
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| | ▪ | Loans and Long-Term Receivables—We enter into agreements with other parties to pursue business opportunities, which may require us to provide loans or advances to certain affiliated and non-affiliated companies. Loans are recorded when cash is transferred or seller financing is provided to the affiliated or non-affiliated company pursuant to a loan agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will decrease as interest and principal payments are received. Interest is earned at the loan agreement’s stated interest rate. Loans and long-term receivables are assessed for impairment when events indicate the loan balance may not be fully recovered.
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| | ▪ | Intangible Assets Other Than Goodwill—Intangible assets with finite useful lives are amortized using the straight-line method over their useful lives. Intangible assets with indefinite useful lives are not amortized but are tested at least annually for impairment. Each reporting period, we evaluate the remaining useful lives of intangible assets not being amortized to determine whether events and circumstances continue to support indefinite useful lives. 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.
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| | ▪ | Goodwill—Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination. It is not amortized, but is tested for impairment annually and when events or changes in circumstance indicate that the fair value of a reporting unit with goodwill is below its carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, an impairment is recognized for the amount by which the book value exceeds the reporting unit’s fair value. A goodwill loss cannot exceed the total amount of goodwill allocated to that reporting unit. For purposes of testing goodwill for impairment, we have three reporting units with goodwill balances: Transportation, Refining, and Marketing and Specialties.
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Impairment of Properties, Plants and Equipment
| | ▪ | Depreciation and Amortization—Depreciation and amortization of properties, plants and equipment are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units).
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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.
| | ▪ | Impairment of Properties, Plants and Equipment—Properties, plants and equipment (PP&E) used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If indicators of potential impairment exist, an undiscounted cash flow test is performed. If the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, including applicable liabilities, the carrying value of the PP&E included in the asset group is written down to estimated fair value through additional amortization or depreciation provisions and reported in the “Impairments” line on our consolidated statement of income in the period in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets (for example, at a refinery complex level). Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined using one or more of the following methods: the present values of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants; a market multiple of earnings for similar assets; or historical market transactions of similar assets, adjusted using principal market participant assumptions when necessary. Long-lived assets held for sale are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described.
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The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future volumes, prices, costs, margins and capital project decisions, considering all available evidence at the date of review.
| | ▪ | Property Dispositions Impairment of Investments in Nonconsolidated Entities—Investments in nonconsolidated entities are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. When indicators exist, the fair value is estimated and compared to the investment carrying value. If any impairment is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. The fair value of the impaired investment is based on quoted market prices, if available, or upon the present value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants and a market analysis of comparable assets, if appropriate.
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| | ▪ | 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.
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| | ▪ | Property Dispositions—When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the “Net gain on dispositions” line on our consolidated statement of income. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.
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| | ▪ | Asset Retirement Obligations 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—The fair value of legal obligations to retire and remove long-lived assets are recorded in the period in which the obligation arises. When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related PP&E. Over time, the liability is increased for the change in its present value, and the capitalized cost in PP&E is depreciated over the useful life of the related asset. If our estimate of the liability changes after initial recognition, we record an adjustment to the liability and PP&E. |
Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures relating to an existing condition caused by past operations, and those having no future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a business combination) whenWhen environmental assessments or cleanups are probable and the costs can be reasonably estimated.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 assetsa 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 their receipt iswe have information to support the reversal. When the performance on the guarantee becomes probable and estimable.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.
| | ▪ | Guarantees—The fair value of a guarantee is determined and recorded as a liability at the time the guarantee is given. The initial liability is subsequently reduced as we are released from exposure under the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we have information indicating the liability has essentially been relieved or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over time. We amortize the guarantee liability to the related income statement line item based on the nature of the guarantee. When it becomes probable we will have to perform on a guarantee, we accrue a separate liability for the excess amount above the guarantee’s book value, if it is reasonably estimable, based on the facts and circumstances at that time. We reverse the fair value liability only when there is no further exposure under the guarantee.
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| | ▪ | Share-Based Compensation—We recognize share-based compensation expense over the shorter of: (1) the service period (i.e., the stated period of time required to earn the award); or (2) the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months as this is the minimum period of time required for an award not to be subject to forfeiture. Our equity-classified programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for awards held by employees at the time they become eligible for retirement (at age 55 with 5 years of service). We have elected to recognize expense on a straight-line basis over the service period for the entire award, irrespective of whether the award was granted with ratable or cliff vesting, and elected to recognize forfeiture reversals of awards when they occur.
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| | ▪ | Income Taxes—Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Interest related to unrecognized income tax benefits is reflected in interest expense, and penalties in operating expenses.
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| | ▪ | Taxes Collected from Customers and Remitted to Governmental Authorities—Excise taxes are reported gross within sales and other operating revenues and taxes other than income taxes, while other sales and value-added taxes are recorded net in taxes other than income taxes.
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| | ▪ | Treasury Stock—We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in stockholders’ equity in the consolidated balance sheet.
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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, 2017,2023, we early adopted Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2017-04, “Intangibles—Goodwill and Other (Topic 350)ASU 2022-04, “Liabilities—Supplier Finance Programs (Subtopic 405-50): Simplifying the Test for Goodwill Impairment,” which eliminated the second step from the goodwill impairment test. Under the revised test, an entity should perform its goodwill impairment tests by comparing the fair valueDisclosure of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit.Supplier Finance Program Obligations.” This ASU was applied prospectivelyrequires the buyer in a supplier finance program to goodwill impairment tests performed on or after January 1, 2017.
Effective January 1, 2017, we early adopted ASU No. 2016-18, “Statementdisclose qualitative and quantitative information about the program. At the time of Cash Flows (Topic 230): Restricted Cash.” The update clarified the classification and presentation of changes in restricted cash. The ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash and restricted cash equivalents. Adoption ofadoption, this ASU on a retrospective basis did not have a material impact on our consolidated financial statements. See Note 23—Cash Flow Information for more information.
Effective January 1, 2017,2022, we early adopted ASU No. 2016-15, “Statement2021-08, “Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers.” This pronouncement requires application of Cash Flows (Topic 230): Classification of Certain Cash ReceiptsASC 606 “Revenue from Contracts with Customers” (“Topic 606”) to recognize and Cash Payments.”measure contract assets and contract liabilities from contracts with customers acquired in a business combination. The update clarified how certain cash receipts and cash payments should be presented and classified in the statement of cash flows. In addition, the ASU clarified that when cash receipts and cash
payments have aspects of more than one class of cash flows and cannot be separated, classification will depend on the predominant source or use. Adoptionadoption of this ASU on a retrospective basispronouncement did not have a material impact on our consolidated financial statements.
Effective JanuaryOctober 1, 2017,2021, we adopted ASU No. 2016-09, “Compensation—Stock Compensation2020-04, “Reference Rate Reform (Topic 718)848): Improvements to Employee Share-Based Payment Accounting,” which simplified several aspectsFacilitation 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 for share-based payment award transactions, including accounting for income taxesapply to derivatives that are affected by the discounting transition. These pronouncements were effective upon issuance and classification of excess tax benefits on the statement of cash flows, forfeitures and minimum statutory tax withholding requirements. Adoption of this ASU on a prospective basis did not materially impact our financial position, results of operations, or cash flows. We account for forfeitures of awards when they occur and excess tax benefits, which were previously reported in cash flows from financing activities, are now reported in cash flows from operating activities.
In June 2014,applicable to contract modifications through December 31, 2022. On December 21, 2022, the FASB issued ASU No. 2014-10, “Development Stage Entities2022-06, “Reference Rate Reform (Topic 915)848): EliminationDeferral of Certain Financial Reporting Requirements, Including an Amendmentthe Sunset Date of Topic 848.” The ASU defers the sunset date of Topic 848 from December 31, 2022, to Variable Interest Entities (VIE) GuidanceDecember 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 810, Consolidation.”848. This update removedpronouncement 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 definition of a development stage entity from the Master Glossary of the Accounting Standard Codification (ASC) and the related financial reporting requirements specific to development stage entities. This update was intended to reduce cost and complexity of financial reporting for entities that have not commenced planned principal operations. For financial reporting requirements other than the VIE guidance in ASC Topic 810, ASU No. 2014-10 was effective for annual and quarterly reporting periods of public entities beginning after December 15, 2014. For the financial reporting requirements related to VIEs in ASC Topic 810, ASU No. 2014-10 was effective for annual and quarterly reporting periods for public entities beginning after December 15, 2015. We adopted the provisions of this ASU relatedsurviving entity.
Prior to the financial reporting requirements other than the VIE guidance effective January 1, 2015. We adopted the remaining provisions effective January 1, 2016.
Note 3—Variable Interest Entities
Consolidated VIEs
In 2013,DCP Midstream Merger, we formed Phillips 66 Partnersand 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 (Phillips 66 Partners)(DCP LP), a master limited partnership, to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum products and NGL pipelines and terminals, as well as other midstream assets. We consolidate Phillips 66 Partners as we determined that Phillips 66 Partnerseach 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.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 general partnera result of Phillips 66 Partners,the governance rights granted to us over DCP Midstream Class A Segment and the governance rights we have the ability to control itshold 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 well as the ability to direct the activities of Phillips 66 Partners that most significantly impact its economic performance. See Note 27—Phillips 66 Partners LP, for additional information.noncontrolling interests on our financial statements.
The most significant assets of Phillips 66 Partners that are available to settle only its obligations, along with its most significant liabilities for which its creditors do not have recourse to Phillips 66’s general credit at December 31 were:
| | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | | | | | | Cash and cash equivalents | $ | 185 |
| | 2 |
| | Equity investments* | 1,932 |
| | 1,142 |
| | Net properties, plants and equipment | 2,918 |
| | 2,675 |
| | Long-term debt | 2,920 |
| | 2,396 |
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* Included in “Investments and long-term receivables” on the Phillips 66 consolidated balance sheet.
Non-Consolidated VIEs
We hold variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information onaccount for our significant non-consolidated VIEs follows.
Merey Sweeny, L.P. (MSLP) is a limited partnership that owns a delayed coker and related facilities at the Sweeny Refinery. Under the agreements that governed the relationships between the former co-venturers in MSLP, certain defaults by Petróleos de Venezuela S.A. (PDVSA) with respect to supply of crude oil to the Sweeny Refinery triggered the right to acquire PDVSA’s 50 percent ownershipremaining indirect economic interest in MSLP. The call right was exercised in August 2009. The exercise of the call right was challenged, and the dispute was arbitrated in our favor and subsequently litigated. Through February 7, 2017, we determined MSLP was a VIE and usedGray Oak Pipeline, now held through DCP Midstream Class B Segment, using the equity method of accounting because the exerciseaccounting. As a result of the callDCP 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 remainedto 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 legal challenge. MSLPchange 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 VIE because,15.05% incremental indirect economic ownership interest in securing lender consentsDCP 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 our separation from ConocoPhillips in 2012 (the Separation), we provided a 100 percent debt guaranteethe DCP Midstream Merger. Adjustments related to the lendereconomic 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 MSLP’s 8.85% senior notes. PDVSA didthe 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 participatedisclose 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 debt guarantee. Inremaining 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 VIE assessment, this disproportionate debt guarantee, plus other liquidity support provided jointly by uscontracts with customers, and PDVSA independentlyis expected to be recognized through 2031 with a weighted average remaining life of equity ownership, resulted in MSLP not beingtwo years as of December 31, 2023.
Note 6—Credit Losses
We are exposed to all potential losses.credit losses primarily through our sales of refined petroleum products, crude oil, NGL and natural gas. We determinedassess each counterparty’s ability to pay for the products we were notsell by conducting a credit review. The credit review considers our expected billing exposure and timing for payment and the primary beneficiary while the call exercise was subject to legal challenge, because under the partnership agreement, the co-venturers jointly directed the activities of MSLP that most significantly impacted economic performance. As discussed more fully in Note 5—Business Combinations, the exercisecounterparty’s established credit rating or our assessment of the call right ceasedcounterparty’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 be subject to legal challenge in February 2017. At that point, we no longer considered MSLP a VIE and the entity became a consolidated subsidiary.mitigate credit risk.
We own a 25 percent interest in both Dakota Access, LLC (Dakota Access)monitor our ongoing credit exposure through active review of counterparty balances against contract terms and Energy Transfer Crude Oil Company, LLC (ETCO), which collectively own the Bakken Pipeline. These entities did not have sufficient equitydue 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 riskDecember 31, 2023, more than 95% of our accounts receivable were outstanding less than 60 days.
We are also exposed to fully fund the constructioncredit losses from off-balance sheet exposures, such as guarantees of all assets requiredjoint venture debt and standby letters of credit. See Note 15—Guarantees, and Note 16—Contingencies and Commitments, for principal operations, and thus represented VIEs until operations began. We determined we were not the primary beneficiary because we and our co-venturer at the time jointly directed the activities of Dakota Access and ETCO that most significantly impact economic performance. In June 2017,more information on these entities started commercial operations and were no longer considered VIEs. We use the equity method of accounting for these investments.off-balance sheet exposures.
Note 4—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 | |
| | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | | | | | | Crude oil and petroleum products | $ | 3,106 |
| | 2,883 |
| | Materials and supplies | 289 |
| | 267 |
| | | $ | 3,395 |
| | 3,150 |
|
Inventories valued on the LIFO basis totaled $2,980$3,050 million and $2,772$2,635 million at December 31, 20172023 and 2016,2022, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $4.3$5.3 billion and $3.3$6.3 billion at December 31, 20172023 and 2016,2022, respectively.
Excluding the dispositionDuring each of the Whitegate Refinery, which occurred in September 2016,three years ended December 31, 2023, certain plannedvolume reductions in inventory caused liquidations of LIFO inventory values during each ofvalues. For the three years ended December 31, 2017. These2023 and 2022, LIFO inventory liquidations increased net income by approximately $13 million in 2017 and decreased net income by approximately $68$94 million and $37$75 million, in 2016 and 2015, respectively.
In conjunction with the Whitegate Refinery disposition, the refinery’s LIFO inventory values were liquidated causing a decrease in net income of $62 million during 2016. This LIFO liquidation impact was included in the net gain recognized on the disposition.
Note 5—Business Combinations
MSLP owns a delayed coker and related facilities at the Sweeny Refinery. Prior to August 28, 2009, MSLP was owned 50/50 by ConocoPhillips and PDVSA. Under the agreements that governed the relationships between the partners, certain defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery triggered the right, exercised in August 2009, to acquire its 50 percent ownership interest in MSLP for a purchase price determined by a contractual formula. As the distributions PDVSA received from MSLP exceeded the amounts it contributed to MSLP, the contractual formula required no cash consideration for the acquisition. The exercise was challenged, and the dispute was arbitrated in our favor and subsequently litigated. While the dispute was being arbitrated and litigated, we continued to use the equity method of accounting for our 50 percent interest in MSLP. When the exercise of the call right ceased to be subject to legal challenge on February 7, 2017, we deemed that we had acquired PDVSA’s 50 percent share of MSLP and began accounting for MSLP as a consolidated subsidiary.
Based on a third-party appraisal of the fair value of MSLP’s net assets, utilizing discounted cash flows and replacement costs, the acquisition of PDVSA’s 50 percent interest resulted in our recording a pre-tax gain of $423 million in the first quarter of 2017. This gain was included in the “Other income” line on our consolidated statement of income. The fair value of our original equity interest in MSLP immediately prior to the deemed acquisition was $145 million. As a result of the transaction, we recorded $318 million of restricted cash, $250 million of PP&E and $238 million of debt, as well as a net $93 million for the elimination of our equity investment in MSLP and net intercompany payables. Our acquisition accounting was finalized during the first quarter of 2017.
The results of MSLP were included in our Refining segment until October 2017, when we contributed our 100 percent interest in MSLP to Phillips 66 Partners, which is included in our Midstream segment. See Note 27—Phillips 66 Partners LP for further discussion regarding the contribution.
In November 2016, Phillips 66 Partners acquired NGL logistics assets located in southeast Louisiana, consisting of approximately 500 miles of pipelines and storage caverns connecting multiple fractionation facilities, refineries and a petrochemical facility. The acquisition provided an opportunity for fee-based growth in the Louisiana market within our Midstream segment. The acquisition was included in the “Capital expenditures and investments” line on our consolidated statement of cash flows. At the acquisition date, we recorded $183 million of PP&E and $3 million of goodwill. Our acquisition accounting was finalized during the first quarter of 2017, with no change to the provisional amounts recorded in 2016.
Note 6—Assets Held for Sale or Sold
In September 2016, we completed the sale of the Whitegate Refinery and related marketing assets, which were included primarily in our Refining segment. The net carrying value of the assets at the time of their disposition was $135 million, which consisted of $127 million of inventory, other working capital, and PP&E; and $8 million of allocated goodwill. An immaterial gain was recognized in 2016 on the disposition.
In February 2015, we completed the sale of the Bantry Bay terminal, which was included in our Refining segment. At the time of the disposition, the terminal had a net carrying value of $68 million, which primarily related to net PP&E. An immaterial gain was recognized in 2015 on this disposition.
In July 2013, we completed the sale of the Immingham Combined Heat and Power Plant (ICHP), which was included in our Marketing and Specialties segment. A gain on this disposal was deferred at the time of the sale due to an indemnity provided to the buyer. We recognized the deferred gain in earnings as our exposure under the indemnity declined, beginning in the third quarter of 2014 and ending in the second quarter of 2015 when the indemnity expired. We recognized $242 million of the deferred gain during For the year ended December 31, 2015.2021, LIFO inventory liquidations decreased net income by $101 million.
Note 7—8—Investments, Loans and Long-Term Receivables Components of investments loans 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 | |
| | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | | | | | | Equity investments | $ | 13,733 |
| | 13,102 |
| | Loans and long-term receivables | 94 |
| | 334 |
| | Other investments | 114 |
| | 98 |
| | | $ | 13,941 |
| | 13,534 |
|
Equity Investments AffiliatedSignificant affiliated companies in which we had a significantaccounted for under the equity investmentmethod, including nonconsolidated VIEs, at December 31, 2017,2023 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 businesspercent-owned joint venture with Cenovus Energy Inc. (Cenovus)—that owns the Wood River and Borger refineries. 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 (DCP Midstream)—50 percent owned joint venture with Spectra Energy Corp, a wholly owned subsidiary of Enbridge Inc.—owns and operates gas plants, gathering systems, storage facilities and fractionation plants, including through its investment in DCP Midstream, LP (DCP Partners).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. Chevron Phillips Chemical
•Dakota Access, LLC (Dakota Access) and Energy Transfer Crude Oil Company, LLC (CPChem)(ETCO)—50 percent ownedTwo 25 percent-owned joint venture with Chevron U.S.A. Inc., an indirect wholly owned subsidiary of Chevron Corporation—manufactures and markets petrochemicals and plastics. Rockies Express Pipeline LLC (REX)—25 percent owned joint venture with Tallgrass Energy Partners L.P.—owns and operates a natural gas pipeline system from Colorado to Ohio.
DCP Sand Hills Pipeline, LLC (Sand Hills)—Phillips 66 Partners’ 33 percent owned joint venture with DCP Partners—owns and operates NGL pipeline systems from the Permian and Eagle Ford basins to Mont Belvieu, Texas.
DCP Southern Hills Pipeline, LLC (Southern Hills)—Phillips 66 Partners’ 33 percent owned joint venture with DCP Partners—owns and operates NGL pipeline systems from the Midcontinent region to Mont Belvieu, Texas.
Dakota Access and ETCO—Phillips 66 Partners’ two 25 percent owned joint ventures with Energy Transfer Partners L.P. (ETP) and MarEn Bakken Company LLC.ventures. Dakota Access owns a pipeline system that deliverstransports 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 Illinois, to Nederland, Texas. Collectively, theseThese two pipeline systems collectively form the Bakken Pipeline system, which is operated by ETP.a co-venturer.
Summarized 100 percent financial informationIn 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 alla 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 methodcontributions 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 affiliated companies, combined, was:Dakota Access and ETCO was $640 million and $675 million, respectively.
| | | | | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | 2015 |
| | | | | | | | | Revenues | $ | 35,523 |
| | 30,605 |
| | 33,126 |
| | Income before income taxes | 3,956 |
| | 3,206 |
| | 3,180 |
| | Net income | 3,764 |
| | 2,960 |
| | 3,158 |
| | Current assets | 7,325 |
| | 7,097 |
| | 6,024 |
| | Noncurrent assets | 49,950 |
| | 50,163 |
| | 46,047 |
| | Current liabilities | 5,248 |
| | 5,173 |
| | 4,130 |
| | Noncurrent liabilities | 13,743 |
| | 13,709 |
| | 11,493 |
| | Noncontrolling interests | 2,549 |
| | 2,260 |
| | 2,404 |
|
At December 31, 2017, retained earnings included approximately $2,320 million related•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 the undistributed earnings of affiliated companies. Dividends received from affiliates were $1,270 million, $616 million, and $1,769 million in 2017, 2016 and 2015, respectively.
WRB
WRB’s operating assets consist of the Wood River and Borger refineries, located in Roxana, Illinois, and Borger, Texas, respectively, for which we are the operator and managing partner. AsSkellytown, Texas. The pipeline is operated by a resultco-venturer. This investment was acquired as part of our contributionconsolidation of these two assets to WRB,DCP Midstream Class A Segment starting on August 18, 2022, and was recorded at fair value. We have a basis difference was createdfor our investment in Front Range because the faircarrying value of our investment is higher than our share of Front Range net assets. The basis difference is the contributed assets recorded by WRB exceeded their historical bookresult of recognizing the investment at fair value. The basis difference is primarilybeing amortized and recognized as a benefit evenlydecrease to equity earnings over a period of 2620 years,, which was the estimated remaining useful life of the refineries’joint venture’s PP&E at the closingacquisition date. At December 31, 2017,2023, 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 WRBFront Range was $2,269$477 million and the basis difference was $2,787 million. Equity earnings in 2017, 2016 and 2015 were increased by $186$499 million, $185 million and $218 million, respectively, due to amortization of the basis difference.
In the first quarter of 2017, we received payment of the $75 million outstanding principal balance of a partner loan we made to WRB in 2016. This cash inflow was included in the “Collection of advances/loans—related parties” line on our consolidated statement of cash flows.
DCP Midstream
respectively. See Note 3—DCP Midstream, ownsLLC and operates gas plants, gathering systems, storage facilities and fractionation plants, primarily through its investment in DCP Partners. DCP Midstream, markets a portion of its NGL to usLP Mergers, Note 4—Business Combinations and CPChem under supply agreements,Note 18—Fair Value Measurements, for additional information on the primary production commitment of which began a ratable wind-down period in December 2014 and expires in January 2019. This purchase commitment is on an “if-produced, will-purchase” basis. NGL is purchased under this agreement at various published market index prices, less transportation and fractionation fees. At December 31, 2017, the book value of our investment in DCP Midstream was $2,227 million,Merger and the basis difference was $54 million.
In 2015, we contributed $1.5 billion in cash to DCP Midstreamour accounting for this transaction as a capital contribution. Our co-venturer contributed its interests in Sand Hills and Southern Hills as a capital contribution equal in value to ours. Our capital contribution was included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.business combination.
CPChem
CPChem manufactures and markets petrochemicals and plastics. We have multiple supply and purchase agreements in place with CPChem, ranging in initial terms from one to 99 years, with extension options. These agreements cover sales and purchases of refined products, solvents, and petrochemical and NGL feedstocks, as well as fuel oils and gases. All products are purchased and sold under specified pricing formulas based on various published pricing indices. At December 31, 2017, the book value of our equity method investment in CPChem was $6,222 million.
REX
REX•Rockies Express Pipeline LLC (REX)—25 percent-owned joint venture that owns a natural gas pipeline system that runsextends from Meeker,Wyoming and Colorado to Clarington, Ohio. At December 31, 2017,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 bookcarrying value of our equity method investment in REX was $445 million, and the basis difference was $376 million. Theis 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 investment.basis difference. At December 31, 2023 and 2022, the book value of our investment in REX was $451 million and $483 million, respectively.
In 2015,•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 contributed $112were 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 REXpurchase our co-venturer’s interest based on a fixed multiple. Accordingly, CF United ceased to coverbe 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 25 percent share of a $450 million debt repayment. Our capital contribution was includedco-venturer did not participate in the “Capital expendituresguarantees. 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 investments” line onguaranteed debt obligations of $65 million. At December 31, 2022, the book value of our consolidated statementinvestment in OnCue was $138 million.
Sand Hills
The•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 is a fee-based pipelinesystem that transports NGLextends from the Permian Basin and Eagle Ford Shale to facilities alongon 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, 2017,2023 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’ equity investmentdecided to exit the Liberty Pipeline project, which resulted in Sand Hills was $515 million.
Southern Hills
a $198 million before-tax impairment. The Southern Hillsimpairment 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 isassets with a fee-based pipelinevalue that transports NGL fromapproximated 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 Midcontinent to facilities along the Texas Gulf Coastimpairment and the Mont Belvieu market hub. At December 31, 2017,techniques used to determine the bookfair value of Phillips 66 Partners’ investment in Southern Hills was $209Liberty.
Midstream Investment Disposition On August 1, 2023, we sold our 25% ownership interest in the South Texas Gateway Terminal for approximately $275 million and the basis difference was $94recognized a before-tax gain of $101 million.
Dakota Access and ETCO
The Dakota Access and ETCO joint ventures were created to construct pipeline systems that collectively form the Bakken Pipeline. The Bakken Pipeline went into commercial service in June 2017, and delivers crude oil produced in the Bakken/Three Forks production area of North Dakota to market centers in the Midwest and the Gulf Coast. In October 2017, these investments were contributed to Phillips 66 Partners as discussed further in Note 27—Phillips 66 Partners LP. At December 31, 2017, the aggregate book value of Phillips 66 Partners’ investments in Dakota Access and ETCO was $621 million, and the basis difference was $53 million.
In May 2016, we and our co-venturer at the time, executed agreements under which we and our co-venturer would loan Dakota Access and ETCO up to a maximum of $2,256 million and $227 million, respectively, with the amounts loaned by us and our co-venturer being proportionate to our ownership interests (Sponsor Loans). In August 2016, Dakota Access and ETCO secured a $2.5 billion facility (Facility) with a syndicate of financial institutions on a limited recourse basis with certain guarantees, and the outstanding Sponsor Loans were repaid. Allowable draws under the Facility were initially reduced and finally suspended in September 2016 pending resolution of permitting delays. As a result, Dakota Access and ETCO resumed making draws under the Sponsor Loans. The maximum amounts that could be loaned under the Sponsor Loans were reduced in September 2016, to $1,411 million for Dakota Access and $76 million for ETCO. At December 31, 2016, Dakota Access and ETCO had $976 million and $22 million, respectively, outstanding under the Sponsor Loans. Our 25 percent share of those loans was $244 million and $6 million, respectively. In February 2017, the Sponsor Loans were repaid in their entirety when draws resumed under the Facility. These cash inflows werebefore-tax gain is included in the “Collection of advances/loans—related parties”“Net gain on dispositions” line item on our consolidated statement of cash flows.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 8—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-year25-year life, pipeline assets over a 45-year45-year life and terminal assets over a 33-year35-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. | | | | | | | | | | | | | | | | | | | | | | Millions of Dollars | | | 2017 | | 2016 | | | Gross PP&E |
| | Accum. D&A |
| | Net PP&E |
| | Gross PP&E |
| | Accum. D&A |
| | Net PP&E |
| | | | | | | | | | | | | | | Midstream | $ | 8,849 |
| | 1,853 |
| | 6,996 |
| | 8,179 |
| | 1,579 |
| | 6,600 |
| | Chemicals | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Refining | 22,144 |
| | 8,987 |
| | 13,157 |
| | 21,152 |
| | 8,197 |
| | 12,955 |
| | Marketing and Specialties | 1,658 |
| | 909 |
| | 749 |
| | 1,451 |
| | 776 |
| | 675 |
| | Corporate and Other | 1,091 |
| | 533 |
| | 558 |
| | 1,207 |
| | 582 |
| | 625 |
| | | $ | 33,742 |
| | 12,282 |
| | 21,460 |
|
| 31,989 |
|
| 11,134 |
| | 20,855 |
|
Note 9—10—Goodwill and Intangibles
Goodwill
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 | |
| | | | | | | | | | | | | | | | Millions of Dollars | | | Midstream |
| | Refining |
| | Marketing and Specialties |
| | Total |
| | | | | | | | | | | Balance at January 1, 2016 | $ | 623 |
| | 1,813 |
| | 839 |
| | 3,275 |
| | Goodwill assigned to acquisitions | 3 |
| | — |
| | — |
| | 3 |
| | Goodwill allocated to dispositions | — |
| | (8 | ) | | — |
| | (8 | ) | | Balance at December 31, 2016 | 626 |
| | 1,805 |
| | 839 |
| | 3,270 |
| | Adjustments | — |
| | — |
| | — |
| | — |
| | Balance at December 31, 2017 | $ | 626 |
| | 1,805 |
| | 839 |
| | 3,270 |
|
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 | |
| | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | | | | | | Trade names and trademarks | $ | 503 |
| | 503 |
| | Refinery air and operating permits | 252 |
| | 260 |
| | Other | 1 |
| | 1 |
| | | $ | 756 |
| | 764 |
|
At December 31, 2017, theThe net book value of our amortized intangible assets was $120$220 million which included accumulated amortization of $173 million. Atand $128 million at December 31, 2016,2023 and 2022, respectively. For the net book value of our amortized intangible assets was $124 million, which included accumulatedyears ended December 31, 2023, 2022 and 2021, amortization of $152 million. Amortization expense was $21$33 million, $18$27 million and $13$26 million, in 2017, 2016 and 2015, respectively, and is expected to be less than $20$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 10—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 | | Millions of Dollars | | | 2017 |
| | 2016 |
| | 2023 | | 2022 | | | | | | | Asset retirement obligations | $ | 268 |
| | 244 |
| | Asset retirement obligations | | | Asset retirement obligations | | | Accrued environmental costs | 458 |
| | 496 |
| | Total asset retirement obligations and accrued environmental costs | 726 |
| | 740 |
| | Asset retirement obligations and accrued environmental costs due within one year* | (85 | ) | | (85 | ) | | Long-term asset retirement obligations and accrued environmental costs | $ | 641 |
| | 655 |
|
* 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 theseour 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. Our largest individual obligations involve asbestos abatement at refineries.
During 2017the years ended December 31, 2023 and 2016,2022, 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 | |
| | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | | | | | | Balance at January 1 | $ | 244 |
| | 251 |
| | Accretion of discount | 10 |
| | 9 |
| | Changes in estimates of existing obligations | 17 |
| | 10 |
| | Spending on existing obligations | (14 | ) | | (15 | ) | | Property dispositions | — |
| | (5 | ) | | Foreign currency translation | 11 |
| | (6 | ) | | Balance at December 31 | $ | 268 |
| | 244 |
|
Accrued Environmental Costs The $38 million decrease in total accrued environmental costs in 2017 was due to payments and settlements during the year, which exceeded new accruals, accrual adjustments and accretion.
Of our total accrued environmental costs at December 31, 2017, $2222023, $279 million was primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations; $187$117 million was associated with nonoperator sites; and $49$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 5 percent discount factor, resulting in anrate of approximately 5%. At December 31, 2023, the accrued balance for acquired environmental liabilities of $268 million at December 31, 2017.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 2018, $462025, $20 million in 2019, $302026, $17 million in 2020,2027, $16 million in 2021, $162028, and $200 million in 2022, and $216 millionthe aggregate for all future years after 2022.2028.
Note 11—13—Earnings Per Share
The numerator of basic earnings per share (EPS) is net income attributable to Phillips 66, reduced byadjusted 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 only by dividend equivalents paid on participating securities for which the dividends are more dilutive than the participation of the awards in the earnings of the periods presented. To the extent unvested stock, unit or option awards and vested unexercised stock options are dilutive, they are included with the weighted-average common shares outstanding in the denominator. Treasury stock is excluded from the denominator in both basic and diluted EPS.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | |
| | | | | | | | | | | | | | | | | | | 2017 | | 2016 | | 2015 | | | Basic |
| Diluted |
| | Basic |
| Diluted |
| | Basic |
| Diluted |
| Amounts Attributed to Phillips 66 Common Stockholders (millions): | | | | | | | | | | Net income attributable to Phillips 66 | $ | 5,106 |
| 5,106 |
| | 1,555 |
| 1,555 |
| | 4,227 |
| 4,227 |
| | Income allocated to participating securities | (6 | ) | — |
| | (6 | ) | (5 | ) | | (6 | ) | — |
| | Net income available to common stockholders | $ | 5,100 |
| 5,106 |
| | 1,549 |
| 1,550 |
| | 4,221 |
| 4,227 |
| | | | | | | | | | | Weighted-average common shares outstanding (thousands): | 511,268 |
| 515,090 |
| | 523,250 |
| 527,531 |
| | 537,602 |
| 542,355 |
| | Effect of share-based compensation | 3,822 |
| 3,418 |
| | 4,281 |
| 2,535 |
| | 4,753 |
| 4,622 |
| | Weighted-average common shares outstanding—EPS | 515,090 |
| 518,508 |
| | 527,531 |
| 530,066 |
| | 542,355 |
| 546,977 |
| | | | | | | | | | | Earnings Per Share of Common Stock (dollars) | $ | 9.90 |
| 9.85 |
| | 2.94 |
| 2.92 |
| | 7.78 |
| 7.73 |
|
Note 14—Debt
Note 12—Debt
Long-termShort-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 | | | 2017 |
| | 2016 |
| | | | | | | 2.950% Senior Notes due 2017 | $ | — |
| | 1,500 |
| | 4.300% Senior Notes due 2022 | 2,000 |
| | 2,000 |
| | 4.650% Senior Notes due 2034 | 1,000 |
| | 1,000 |
| | 5.875% Senior Notes due 2042 | 1,500 |
| | 1,500 |
| | 4.875% Senior Notes due 2044 | 1,500 |
| | 1,500 |
| | Phillips 66 Partners 2.646% Senior Notes due 2020 | 300 |
| | 300 |
| | Phillips 66 Partners 3.605% Senior Notes due 2025 | 500 |
| | 500 |
| | Phillips 66 Partners 3.550% Senior Notes due 2026 | 500 |
| | 500 |
| | Phillips 66 Partners 3.750% Senior Notes due 2028 | 500 |
| | — |
| | Phillips 66 Partners 4.680% Senior Notes due 2045 | 450 |
| | 300 |
| | Phillips 66 Partners 4.900% Senior Notes due 2046 | 625 |
| | 625 |
| | Floating-rate notes due 2019 at 2.009% at year-end 2017 | 300 |
| | — |
| Floating-rate notes due 2020 at 2.109% at year-end 2017
| 300 |
| | — |
| | Term loan due 2020 at 2.469% at year-end 2017 | 450 |
| | — |
| | Note payable to MSLP due 2020 at 7.00%* | — |
| | 68 |
| | Industrial Development Bonds due 2018 through 2021 at 0.80%-2.09% at year-end 2017 and 0.57%-0.81% at year-end 2016* | 100 |
| | 50 |
| | Phillips 66 Partners revolving credit facility due 2021 at 1.98% at year-end 2016 | — |
| | 210 |
| | Other | 1 |
| | 1 |
| | Debt at face value | 10,026 |
| | 10,054 |
| | Capitalized leases | 192 |
| | 188 |
| | Net unamortized discounts and debt issuance costs | (108 | ) | | (104 | ) | | Total debt | 10,110 |
| | 10,138 |
| | Short-term debt | (41 | ) | | (550 | ) | | Long-term debt | $ | 10,069 |
| | 9,588 |
| | * In February 2017, MSLP became a consolidated subsidiary, see Note 5—Business Combinations. |
| | | | | | | | | | | | | | | | | | | 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, 2017,2023, inclusive of net unamortized discounts and debt issuance costs, for each of the years from 20182024 through 20222028 are $41$1,482 million, $314$1,999 million, $1,084$2,253 million, $62$1,276 million and $2,003$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 In October 2017,On March 29, 2023, Phillips 66 Partners closed onCompany, a public offeringwholly owned subsidiary of $650Phillips 66, issued $1.25 billion aggregate principal amount of senior unsecured notes consisting of:
•$750 million aggregate principal amount of senior notes, consisting of $500 million of 3.750%4.950% Senior Notes due 2028 and $150 million of 4.680% Senior Notes due 2045. Interest on the 3.750% Senior Notes due 2028 is payable semiannually in arrears on March 1 and September 1 of each year, commencing on March 1, 2018. Interest on the 4.680% Senior Notes due 2045 is payable semiannually in arrears on February 15 and August 15 of each year.December 2027 (2027 Notes).
In April 2017, Phillips 66 completed a private offering of $600•$500 million aggregate principal amount of unsecured notes, consisting of $300 million of5.300% Senior Notes due 2019June 2033 (2033 Notes).
The 2027 Notes and $300 million of2033 Notes due 2020.(collectively, the Notes) are fully and unconditionally guaranteed by Phillips 66. Interest on these notesthe 2027 Notes is a floating rate equal to three-month London Interbank Offered Rate (LIBOR) plus 0.65% per annum for the 2019 Notespayable semi-annually on June 1 and three-month LIBOR plus 0.75% per annum for the 2020 Notes.December 1 of each year and commenced on December 1, 2023. Interest on both series of notesthe 2033 Notes is payable quarterly in arrearssemi-annually on January 15, April 15, July 15June 30 and October 15, commencing in July 2017. The 2019 Notes matureDecember 30 of each year and commenced on April 15, 2019, and the 2020 Notes mature on April 15, 2020. The notes areDecember 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 Company,(the Term Loan Agreement). The Term Loan Agreement provides for a 100-percent-owned subsidiary.
Also in April 2017, Phillips 66 entered into term loan facilities with an aggregatesingle borrowing amount of $900 million, consisting ofduring a $450 million 364-day facility and a $450 million three-year facility. Interest90-day period commencing on the term loans is a floating rate based on eitherclosing date, which borrowing was contingent upon the Eurodollar rate or the reference rate, plus a margin determined by our long-term credit ratings.
In February 2017, as partcompletion of the consolidation of MSLP, Phillips 66 assumed $135 million of 8.85% Senior Notes dueDCP LP Merger. The Term Loan Agreement contains customary covenants similar to those contained in 2019 and $100 million of tax-exempt bonds due between 2018 and 2021. See Note 5—Business Combinations for additional information regarding the consolidation of MSLP.
Debt Repayments
In October 2017, as part of a contribution of assets to Phillips 66 Partners, Phillips 66 Partners assumed the $450 million term loan outstanding under the 364-day facility originally issued in April 2017, and subsequently repaid the loan. See Note 27—Phillips 66 Partners LP for additional information.
In May 2017, we repaid $1,500 million of 2.950% Senior Notes upon maturity with the funding from the April 2017 debt issuances discussed above. In addition, we repaid $135 million of MSLP 8.85% Senior Notes due in 2019 originally recorded in February 2017 as part of the consolidation of MSLP. See Note 5—Business Combinations for additional information regarding MSLP.
During 2017, Phillips 66 Partners repaid all outstanding borrowings under its $750 millionour revolving credit facility.
Credit Facilities and Commercial Paper
Phillips 66 has a $5.0 billion revolving credit facility that extends until October 2021. This facility may be used for direct bank borrowings, as support for issuances of letters of credit, or as support for our commercial paper program. The facility is with a broad syndicate of financial institutions and contains covenants that we consider usual and customary for an agreement, of this type for comparable commercial borrowers, including a maximum consolidated net debt-to-capitalization ratio of 60 percent.65% as of the last day of each fiscal quarter. The agreementTerm Loan Agreement has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts;amounts after grace periods; and violation of covenants; cross-payment default and cross-acceleration (in each case, to indebtedness in excess of a threshold amount); and a change of control. Borrowingscovenants. We may at any time prepay outstanding borrowings under the facility will incurTerm Loan Agreement, in whole or in part, without premium or penalty. Outstanding borrowings under the Term Loan Agreement bear interest at either: (a) the LIBOR plus a margin based on the credit rating of our senior unsecured long-term debt as determinedadjusted 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 Standard & Poor’s Ratings ServicesDCP LP. Interest on all of DCP LP’s senior notes and Moody’s Investors Service.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 administrative agentcommitment fees. The pricing levels for the commitment fees and commitment fees.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, 2017,2023 and 2022, no amount had been drawn under this revolving credit agreement.the Facility.
Phillips 66 also has a $5.0$5 billion uncommitted commercial paper program for short-term working capital needs that is supported by our revolving credit facility.the Facility. Commercial paper maturities are generallycontractually limited to 90365 days. At December 31, 2017, we had2023 and 2022, no borrowings were outstanding under our commercial paperthe program.
Phillips 66 Partners has a 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 that extends until October 2021. The Phillips 66 Partners facility isunder its amended credit agreement (the Credit Agreement), with a broad syndicateborrowing capacity of financial institutions.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, 2017, Phillips 66 Partners2023, DCP LP had $25 million in borrowings outstanding under the Credit Agreement. At December 31, 2022, DCP LP had no borrowings outstanding under this facility.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.
Note 13—Guarantees
Total Committed Capacity Available
At December 31, 2017,2023, 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 guaranteeguarantees and expect future performance to be either immaterial or have only a remote chance of occurrence.
Guarantees of Joint-Venture Debt
In December 2016, as part of the restructuring within DCP Midstream, we issued a guarantee, effective January 1, 2017, to support the debt DCP Midstream issued in the first quarter of 2017. At December 31, 2017, the maximum potential amount of future payments to third parties under the guarantee is estimated to be $175 million. Payment would be required if DCP Midstream defaults on this debt obligation, which matures in 2019.
At December 31, 2017, we had other guarantees outstanding for our portion of certain joint-venture debt obligations, which have remaining terms of up to 8 years. The maximum potential amount of future payments to third parties under these guarantees is approximately $133 million. Payment would be required if a joint venture defaults on its debt obligations.
OtherLease Residual Value Guarantees
Under the operating lease agreement onfor our headquarters facility in Houston, Texas, we have a residual value guarantee with a maximum future exposure of $554 million. The operating lease has a term of five years and provides us 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 airplanetruck leases with maximum potential future exposures totaling $305$168 million. Based on third-party appraisalsThese 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 railcars’ fair value at the end of their lease terms, we estimated a total residual value deficiency of $109 million and recognized $28 million as expense in 2016. During 2017, we recognized an additional $45 million of expense related to the residual value deficiency. In October 2017, upon maturity of one of our railcar leases, $53 million of the total residual value deficiency of $109 million was settled. The remaining residual value deficiency of $36 million remaining atCECU.
At December 31, 2017, will2023, 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 recognizedrequired if a joint venture defaults on a straight-line basis through May 2019.its obligations.
Indemnifications Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to indemnification.indemnifications. Agreements associated with these sales include indemnifications for taxes, litigation, environmental liabilities, permits and licenses, and employee claims, as well asand real estate indemnity against tenant defaults. The provisions of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, which generally have indefinite terms and potentially unlimited exposure. TheAt December 31, 2023 and 2022, the carrying amount of recorded for indemnifications at December 31, 2017, was $193 million.$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 that the liability was essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines.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. Included in the recorded carrying amount were $104 million ofAt December 31, 2023 and 2022, environmental accruals for known contamination at December 31, 2017.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 10—12—Asset Retirement Obligations and Accrued Environmental Costs and Note 14—16—Contingencies and Commitments.
Indemnification and Release Agreement In 2012, in connection with the Separation,our separation from ConocoPhillips, we entered into thean Indemnification and Release Agreement with ConocoPhillips.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.separation. Generally, the agreement provides for cross-indemnitiescross indemnities principally designed to place financial responsibility for the obligations and liabilities of our business with us and financial responsibility for the obligations and liabilities of ConocoPhillips’ business with ConocoPhillips. The agreement also establishes procedures for handling claims subject to indemnification and related matters.
Note 14—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-relatedincome tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.uncertain. See Note 21—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 all information available at the time. We measure estimates and base contingent liabilities on currently available facts, existing technology and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring contingent environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.
Although liability for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies alleged to have liability at a particular site. Due to such joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites atfor which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit, although some of the indemnifications are subject to dollar and time limits.
We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those pertaining to sites acquired in a business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings. See Note 10—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, 2017,2023, we had performance obligations secured by letters of credit and bank guarantees of $773$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. TheAt December 31, 2023, the estimated aggregate amounts of estimatedfuture payments under these various agreements arewere $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, annually for each of the years from 2018 through 2022 and $2,644 million in the aggregate for years 2023 and thereafter. Total payments under the agreements were $323 million in 2017, $325 million in 2016 and $328 million in 2015.respectively.
Note 15—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 products,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 16—18—Fair Value Measurements.
Commodity Derivative Contracts—We sell into or receive supply from the worldwide crude oil, refined products,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 immaterial amount of trading not directly related to our physical business, all of which may reduce our exposure to fluctuations in market prices. We also use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades.
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 setoffoffset 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 | | |
| | | | | | | | | | | | | | | | | | | | | | Millions of Dollars | | | December 31, 2017 | | December 31, 2016 | | | 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 | $ | 43 |
| (19 | ) | — |
| 24 |
| | 267 |
| (154 | ) | — |
| 113 |
| | Other assets | 7 |
| (3 | ) | — |
| 4 |
| | 5 |
| (1 | ) | — |
| 4 |
| | Liabilities | | | |
|
| | | | | | | Other accruals | 699 |
| (746 | ) | 21 |
| (26 | ) | | 474 |
| (612 | ) | 73 |
| (65 | ) | | Other liabilities and deferred credits | — |
| (1 | ) | — |
| (1 | ) | | — |
| (1 | ) | — |
| (1 | ) | | Total | $ | 749 |
| (769 | ) | 21 |
| 1 |
|
| 746 |
| (768 | ) | 73 |
| 51 |
|
At December 31, 2017 and 2016,2023, there was no material cash$7 million of net collateral received orthat 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) | |
| | | | | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | 2015 |
| | | | | | | | | Sales and other operating revenues | $ | (247 | ) | | (451 | ) | | 162 |
| | Other income | 27 |
| | 29 |
| | 58 |
| | Purchased crude oil and products | (18 | ) | | (62 | ) | | 121 |
| | Net gain (loss) from commodity derivative activity | $ | (238 | ) | | (484 | ) | | 341 |
|
The following table summarizes our material net exposures resulting from outstanding commodity derivative contracts. These financial and physical derivative contracts are primarily used to manage price exposure on our underlying operations. The underlying exposures may be from non-derivativenonderivative positions such as inventory volumes. Financial derivative contracts may also offset physical derivative contracts, such as forward purchase and sales contracts. The percentage of our derivative contract volumes expiring within the next 12 months was at least 98 percentmore than 90% at December 31, 20172023 and 2016.2022.
| | | | | | | | | | | | | 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) | |
| | | | | | | | | Open Position Long / (Short) | | | 2017 |
| | 2016 |
| | Commodity | | | | Crude oil, refined products and NGL (millions of barrels) | (11 | ) | | (18 | ) |
Interest Rate Derivative Contracts—In 2016, we entered into interest rate swaps to hedge the variability of anticipated lease payments on our new headquarters. These monthly lease payments will vary based on monthly changes in the one-month LIBOR and changes, if any, in our credit rating over the five-year term of the lease. The pay-fixed, receive-floating interest rate swaps have an aggregate notional value of $650 million and end on April 25, 2021. They qualify for and are designated as cash-flow hedges.
The aggregate net fair value of these swaps, which is included in the “Prepaid expenses and other current assets,” “Other assets” and “Other accruals” lines of our consolidated balance sheet, totaled $14 million and $8 million at December 31, 2017 and 2016, respectively.
We report the effective portion of the mark-to-market gain or loss on our interest rate swaps designated as cash-flow hedges as a component of other comprehensive income (loss), and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness are recognized in general and administrative expenses. We did not have any material hedge ineffectiveness gain or loss for the years ended December 31, 2017 and 2016. Net realized losses from settlements of the swaps were immaterial for the years ended December 31, 2017 and 2016.
We currently estimate that pre-tax gains of $2 million will be reclassified from accumulated other comprehensive income (loss) into general and administrative expenses during the next twelve months as the hedged transactions settle; however, the actual amounts that will be reclassified will vary based on changes in interest rates throughout 2018.
Credit Risk from Derivative and Financial Instruments Financial instruments potentially exposed to concentrations of credit risk consist primarily of over-the-counter (OTC)trade receivables and derivative contractscontracts.
Our trade receivables result primarily from the sale of products from, or related to, our refinery operations and trade receivables.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 OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements, typically on a daily basis, until settled. However, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.
Our trade receivables result primarily from the sale of products from, or related to, our refinery operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less. We continually monitor this exposure and the creditworthiness of the counterparties and recognize bad debt expense based on historical write-off experience or specific counterparty collectability. Generally, we do not require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments or master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due to us.
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating.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 not materialimmaterial at December 31, 20172023 and 2016.2022.
Note 16—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 an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability)liability (i.e., an exit price), and disclose the quality of these fair values based on the valuation inputs used in these measurements under the following hierarchy:
•Level 1: Fair value measured with unadjusted quoted prices from an active market for identical assets or liabilities. •Level 2: Fair value measured either with: (1) adjusted quoted prices from an active market for similar assets or liabilities; or (2) other valuation inputs that are directly or indirectly observable. •Level 3: Fair value measured with unobservable inputs that are significant to the measurement.
We classify the fair value of an asset or liability based on the significance of its observable or unobservable inputs to the measurement. However, the fair value of an asset or liability initially reported as Level 3 will be subsequently reported as Level 2 if the unobservable inputs become inconsequential to its measurement or corroborating market data becomes available. Conversely, an asset or liability initially reported as Level 2 will be subsequently reported as Level 3 if corroborating market data becomes unavailable. For the year ended December 31, 2017, derivative assets with an aggregate value of $131 million and derivative liabilities with an aggregate value of $134 million were transferred to Level 1 from Level 2, as measured from the beginning of the reporting period. The measurements were reclassified within the fair value hierarchy due to the availability of unadjusted quoted prices from an active market.
We used the following methods and assumptions to estimate the fair value of financial instruments:
•Cash and cash equivalents—The carrying amount reported on our consolidated balance sheet approximates fair value. •Accounts and notes receivable—The carrying amount reported on our consolidated balance sheet approximates fair value. •Derivative instruments—WeThe 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 classify themis 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 non-exchangenonexchange quotes, we classify those contracts as Level 2. 2 or Level 3 based on the degree to which inputs are observable.OTC financial swaps and physicalPhysical 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, OTC swaps and 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. FinancialPhysical and OTC and physical commodity options are valued using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines whether the options are classified as Level 2 or 3. We use a mid-marketmidmarket pricing convention (the mid-pointmidpoint between bid and ask prices). When appropriate, valuations are adjusted to reflect credit considerations, generally based on available market evidence.
WeWhen applicable, we determine the fair value of our interest rate swaps based on observedobservable market valuations for interest rate swaps that have notionals,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 material financial assets and liabilities either accounted for or disclosed at fair value on a recurring basis. These values are determined by treating each contract as the fundamental unit of account; therefore, derivative assets and liabilities with the same counterparty are shown on a gross basis in the hierarchy sections of these tables, before the effects of counterparty and collateral netting. These tables also show that our Level 3 activity was not material.
We have master netting agreements for all of our exchange-cleared derivative instruments, the majority of our OTC derivative instruments, and certain physical commodity forward contracts (primarily pipeline crude oil deliveries). The following tables showalso reflect the impacteffect of these contracts innetting derivative assets and liabilities with the column “Effectsame counterparty for which we have the legal right of Counterparty Netting.”offset and collateral netting.
The carrying values and fair values by hierarchy of our material financial instrumentsassets and commodity forward contracts,liabilities, either carried or disclosed at fair value, including any effects of netting derivative assets with liabilitiescounterparty and netting collateral due to right of setoff or master netting, agreements, 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | Millions of Dollars | | | December 31, 2017 | | | 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 | $ | 333 |
| | 395 |
| | — |
| | 728 |
| (721 | ) | — |
| — |
| 7 |
| | Physical forward contracts | — |
| | 20 |
| | 1 |
| | 21 |
| — |
| — |
| — |
| 21 |
| | Interest rate derivatives | — |
|
| 14 |
|
| — |
|
| 14 |
| — |
| — |
| — |
| 14 |
| | Rabbi trust assets | 112 |
| | — |
| | — |
| | 112 |
| N/A |
| N/A |
| — |
| 112 |
| | | $ | 445 |
| | 429 |
| | 1 |
| | 875 |
| (721 | ) | — |
| — |
| 154 |
| | | | | | | | | | | | | | | Commodity Derivative Liabilities | | | | | | | | | | | | | Exchange-cleared instruments | $ | 369 |
| | 373 |
| | — |
| | 742 |
| (721 | ) | (21 | ) | — |
| — |
| | Physical forward contracts | — |
| | 23 |
| | 4 |
| | 27 |
| — |
| — |
| — |
| 27 |
| | Floating-rate debt | — |
| | 1,150 |
| | — |
| | 1,150 |
| N/A |
| N/A |
| — |
| 1,150 |
| | Fixed-rate debt, excluding capital leases | — |
| | 9,746 |
| | — |
| | 9,746 |
| N/A |
| N/A |
| (978 | ) | 8,768 |
| | | $ | 369 |
| | 11,292 |
| | 4 |
| | 11,665 |
| (721 | ) | (21 | ) | (978 | ) | 9,945 |
|
| | | | | | | | | | | | | | | | | | | | | | | | Millions of Dollars | | | December 31, 2016 | | | 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 | $ | 273 |
| | 371 |
| | — |
| | 644 |
| (628 | ) | — |
| — |
| 16 |
| | OTC instruments | — |
| | 6 |
| | — |
| | 6 |
| (1 | ) | — |
| — |
| 5 |
| | Physical forward contracts | — |
| | 94 |
| | 2 |
| | 96 |
| — |
| — |
| — |
| 96 |
| | Interest rate derivatives | — |
| | 8 |
| | — |
| | 8 |
| — |
| — |
| — |
| 8 |
| | Rabbi trust assets | 97 |
| | — |
| | — |
| | 97 |
| N/A |
| N/A |
| — |
| 97 |
| | | $ | 370 |
| | 479 |
| | 2 |
| | 851 |
| (629 | ) | — |
| — |
| 222 |
| | | | | | | | | | | | | | | Commodity Derivative Liabilities | | | | | | | | | | | | | Exchange-cleared instruments | $ | 249 |
| | 452 |
| | — |
| | 701 |
| (628 | ) | (73 | ) | — |
| — |
| | OTC instruments | — |
| | 1 |
| | — |
| | 1 |
| (1 | ) | — |
| — |
| — |
| | Physical forward contracts | — |
| | 61 |
| | 5 |
| | 66 |
| — |
| — |
| — |
| 66 |
| | Floating-rate debt | — |
| | 260 |
| | — |
| | 260 |
| N/A |
| N/A |
| — |
| 260 |
| | Fixed-rate debt, excluding capital leases | — |
| | 10,260 |
| | — |
| | 10,260 |
| N/A |
| N/A |
| (570 | ) | 9,690 |
| | | $ | 249 |
| | 11,034 |
| | 5 |
| | 11,288 |
| (629 | ) | (73 | ) | (570 | ) | 10,016 |
|
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” linesline items on our consolidated balance sheet. ForSee Note 17—Derivatives and Financial Instruments, for information regarding where the location ofassets and liabilities related to our commodity derivative assets and liabilitiesderivatives are recorded on our consolidated balance sheet, see the first table in Note 15—Derivatives and Financial Instruments.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 5—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 remeasurementDCP Midstream Merger.
Equity Method Investments The fair value of our investmentthe 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 MSLP to fair value. During the years ended December 31, 2017, and 2016, there were no other materialLevel 3 nonrecurring fair value remeasurementsmeasurements.
PP&E The fair value of PP&E was $13,030 million. The fair value of these assets subsequentwas 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 initial recognition.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 17—19—Equity
Preferred Stock We have Phillips 66 has 500 million shares of preferred stock authorized, with a par value of $0.01$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 Julythe inception of our share repurchase program in 2012, our Board of Directors has at various times, authorized an aggregate of $25 billion of repurchases of our outstanding common stock, which aggregate to a total authorization of up to $12.0 billion. The shares will be repurchased from time to time in the open market at the company’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Since the inception of our share repurchases in 2012, through December 31, 2017, we have repurchased a total of 124,142,530213.8 million shares at an aggregate cost of $9.0$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.
InOur Board of Directors separately authorized two transactions in 2014 we completedand 2018, which resulted in the exchangerepurchase of our flow improver business for52.4 million shares of Phillips 66 common stock owned bywith an aggregate value of $4.6 billion.
In March 2022, in connection with the other party to the transaction. We received 17,422,615Phillips 66 Partners merger, we issued 41.8 million shares of our common stock from our treasury stock with a fair value atan aggregate cost of $3.4 billion. See Note 30—Phillips 66 Partners LP, for information on the time of the exchange of $1.35 billion.merger with Phillips 66 Partners.
Common Stock Dividends On February 7, 2018,2024, our Board of Directors declared a quarterly cash dividend of $0.70$1.05 per common share, payable March 1, 2018,2024, to holders of record at the close of business on February 20, 2018.2024.
Noncontrolling Interests OurAt December 31, 2023, our noncontrolling interests primarily represent issuancesrepresented 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 units tounit redemptions.
At December 31, 2022, our noncontrolling interests primarily represented Enbridge’s indirect economic interest in DCP LP, the public byholders 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.Partners, which resulted in the acquisition of all limited partnership interests in Phillips 66 Partners not already owned by us. See Note 27—29—DCP Midstream Class A Segment, for further information on the preferred unit redemption. SeeNote 30—Phillips 66 Partners LP, for further information on the merger with Phillips 66 Partners.
Note 18—20—Leases
We lease ocean transportmarine vessels, tugboats, barges, pipelines, storage tanks, railcars, service station sites, computers, 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 by the leasingin our lease agreements with regardregards to dividends,dividend payments, asset dispositions or borrowing ability. Our capitalCertain 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 the lease of anservice station consignment agreements with a marketing joint venture and a crude oil terminal in the United Kingdom. The lease obligationliability for the terminal finance lease is subject to foreign currency translation adjustments each reporting period. The total
Components of net PP&E recorded for capital leases was $210 million and $208 million at December 31, 2017 and 2016, respectively.
Future minimum lease payments at December 31, 2017, for operating and capital lease obligations were:
| | | | | | | | | | Millions of Dollars | | | Capital Lease Obligations |
| | Operating Lease Obligations* |
| | | | | | | 2018 | $ | 22 |
| | 533 |
| | 2019 | 22 |
| | 420 |
| | 2020 | 18 |
| | 306 |
| | 2021 | 18 |
| | 141 |
| | 2022 | 15 |
| | 100 |
| | Remaining years | 148 |
| | 326 |
| | Total | 243 |
| | 1,826 |
| | Less: income from subleases | — |
| | 71 |
| | Net minimum lease payments | $ | 243 |
| | 1,755 |
| | Less: amount representing interest | 51 |
| | | | Capital lease obligations | $ | 192 |
| | | | * Includes the remaining residual value deficiency on our railcar leases. See Note 13—Guarantees, for additional information. |
Operating lease rental expensecost 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.
| | | | | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | 2015 |
| | | | | | | | | Minimum rentals* | $ | 680 |
| | 669 |
| | 641 |
| | Contingent rentals | 6 |
| | 6 |
| | 6 |
| | Less: sublease rental income | 73 |
| | 95 |
| | 136 |
| | | $ | 613 |
| | 580 |
| | 511 |
| | * Includes expenses related to the residual value deficiency on our railcar leases. See Note 13—Guarantees, for additional information. |
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 19—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) | |
| | | | | | | | | | | | | | | | | | | | | | Millions of Dollars | | | Pension Benefits | | Other Benefits | | | 2017 | | 2016 | | 2017 |
| | 2016 |
| | | U.S. |
| | Int’l. |
| | U.S. |
| | Int’l. |
| | | | | | Change in Benefit Obligation | | | | | | | | | | | | | Benefit obligation at January 1 | $ | 2,881 |
| | 1,055 |
| | 2,791 |
| | 912 |
| | 225 |
| | 219 |
| | Service cost | 132 |
| | 32 |
| | 127 |
| | 32 |
| | 6 |
| | 7 |
| | Interest cost | 108 |
| | 27 |
| | 116 |
| | 28 |
| | 8 |
| | 8 |
| | Plan participant contributions | — |
| | 2 |
| | — |
| | 3 |
| | 3 |
| | 2 |
| | Actuarial loss (gain) | 267 |
| | (5 | ) | | 62 |
| | 237 |
| | 6 |
| | (6 | ) | | Benefits paid | (345 | ) | | (20 | ) | | (215 | ) | | (19 | ) | | (16 | ) | | (13 | ) | | Curtailment gain | — |
| | — |
| | — |
| | (31 | ) | | — |
| | — |
| | Acquisition of a business | — |
| | — |
| | — |
| | — |
| | — |
| | 8 |
| | Foreign currency exchange rate change | — |
| | 118 |
| | — |
| | (107 | ) | | — |
| | — |
| | Benefit obligation at December 31 | $ | 3,043 |
| | 1,209 |
| | 2,881 |
| | 1,055 |
| | 232 |
| | 225 |
| | | | | | | | | | | | | | | Change in Fair Value of Plan Assets | | | | | | | | | | | | | Fair value of plan assets at January 1 | $ | 2,274 |
| | 796 |
| | 2,023 |
| | 742 |
| | — |
| | — |
| | Actual return on plan assets | 399 |
| | 71 |
| | 136 |
| | 148 |
| | — |
| | — |
| | Company contributions | 423 |
| | 35 |
| | 330 |
| | 40 |
| | 13 |
| | 11 |
| | Plan participant contributions | — |
| | 2 |
| | — |
| | 3 |
| | 3 |
| | 2 |
| | Benefits paid | (345 | ) | | (20 | ) | | (215 | ) | | (19 | ) | | (16 | ) | | (13 | ) | | Foreign currency exchange rate change | — |
| | 88 |
| | — |
| | (118 | ) | | — |
| | — |
| | Fair value of plan assets at December 31 | $ | 2,751 |
| | 972 |
| | 2,274 |
| | 796 |
| | — |
| | — |
| | | | | | | | | | | | | | | Funded Status at December 31 | $ | (292 | ) | | (237 | ) | | (607 | ) | | (259 | ) | | (232 | ) | | (225 | ) |
Amounts recognized in the consolidated balance sheet for our pension and other postretirement benefit plans at December 31 2017 and 2016, 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) | |
| | | | | | | | | | | | | | | | | | | | | | Millions of Dollars | | | Pension Benefits | | Other Benefits | | | 2017 | | 2016 | | 2017 |
| | 2016 |
| | | U.S. |
| | Int’l. |
| | U.S. |
| | Int’l. |
| | | | | | Amounts Recognized in the Consolidated Balance Sheet at December 31 | | | | | | | | | | | | | Current liabilities | $ | (25 | ) | | — |
| | (10 | ) | | — |
| | (16 | ) | | (10 | ) | | Noncurrent liabilities | (267 | ) | | (237 | ) | | (597 | ) | | (259 | ) | | (216 | ) | | (215 | ) | | Total recognized | $ | (292 | ) | | (237 | ) | | (607 | ) | | (259 | ) | | (232 | ) | | (225 | ) |
Included in accumulated other comprehensive income (loss)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 | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | | | | | | Millions of Dollars | | | Pension Benefits | | Other Benefits | | | 2017 | | 2016 | | 2017 |
| | 2016 |
| | | U.S. |
| | Int’l. |
| | U.S. |
| | Int’l. |
| | | | | | | | | | | | | | | | | | | Unrecognized net actuarial loss (gain) | $ | 545 |
| | 190 |
| | 684 |
| | 227 |
| | 1 |
| | (5 | ) | | Unrecognized prior service cost (credit) | — |
| | (4 | ) | | 3 |
| | (5 | ) | | (7 | ) | | (9 | ) |
Other changes in plan assets and benefit obligations recognized in other comprehensive income (loss):
| | | | | | | | | | | | | | | | | | | | | | Millions of Dollars | | | Pension Benefits | | Other Benefits | | | 2017 | | 2016 | | 2017 |
| | 2016 |
| | | U.S. |
| | Int’l. |
| | U.S. |
| | Int’l. |
| | | | | | Sources of Change in Other Comprehensive Income (Loss) | | | | | | | | | | | | | Net gain (loss) arising during the period | $ | (14 | ) | | 14 |
| | (54 | ) | | (129 | ) | | (6 | ) | | 7 |
| | Curtailment gain | — |
| | — |
| | — |
| | 31 |
| | — |
| | — |
| | Amortization of loss and settlements included in income | 153 |
| | 23 |
| | 80 |
| | 14 |
| | — |
| | — |
| | Net change in unrecognized net actuarial loss (gain) during the period | $ | 139 |
| | 37 |
| | 26 |
| | (84 | ) | | (6 | ) | | 7 |
| | | | | | | | | | | | | | | Prior service cost arising during the period | $ | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Amortization of prior service cost (credit) included in income | 3 |
| | (1 | ) | | 3 |
| | (1 | ) | | (2 | ) | | (1 | ) | | Net change in unrecognized prior service cost (credit) during the period | $ | 3 |
| | (1 | ) | | 3 |
| | (1 | ) | | (2 | ) | | (1 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 $2,743$2,101 million and $1,006$661 million, respectively, at December 31, 2017,2023, and $2,601$2,055 million and $880$593 million, respectively, at December 31, 2016.2022.
Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31 were: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 | |
| | | | | | | | | | | | | | | | Millions of Dollars | | | Pension Benefits | | | 2017 | | 2016 | | | U.S. |
| | Int’l. |
| | U.S. |
| | Int’l. |
| | | | | | | | | | | Projected benefit obligations | $ | 172 |
| | 389 |
| | 2,881 |
| | 355 |
| | Accumulated benefit obligations | 143 |
| | 368 |
| | 2,601 |
| | 334 |
| | Fair value of plan assets | — |
| | 196 |
| | 2,274 |
| | 166 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Millions of Dollars | | | Pension Benefits | | Other Benefits | | | 2017 | | 2016 | | 2015 | | 2017 |
| | 2016 |
| | 2015 |
| | | U.S. |
| | Int’l. |
| | U.S. |
| | Int’l. |
| | U.S. |
| | Int’l. |
| | | | | | | | Components of Net Periodic Benefit Cost | | | | | | | | | | | | | | | | | | | Service cost | $ | 132 |
| | 32 |
| | 127 |
| | 32 |
| | 124 |
| | 38 |
| | 6 |
| | 7 |
| | 7 |
| | Interest cost | 108 |
| | 27 |
| | 116 |
| | 28 |
| | 109 |
| | 28 |
| | 8 |
| | 8 |
| | 7 |
| | Expected return on plan assets | (146 | ) | | (40 | ) | | (128 | ) | | (38 | ) | | (138 | ) | | (37 | ) | | — |
| | — |
| | — |
| | Amortization of prior service cost (credit) | 3 |
| | (1 | ) | | 3 |
| | (1 | ) | | 3 |
| | (1 | ) | | (2 | ) | | (1 | ) | | (2 | ) | | Recognized net actuarial loss (gain) | 70 |
| | 23 |
| | 72 |
| | 14 |
| | 75 |
| | 15 |
| | — |
| | — |
| | (1 | ) | | Settlements | 83 |
| | — |
| | 8 |
| | — |
| | 80 |
| | — |
| | — |
| | — |
| | — |
| | Total net periodic benefit cost | $ | 250 |
| | 41 |
| | 198 |
| | 35 |
| | 253 |
| | 43 |
| | 12 |
| | 14 |
| | 11 |
|
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 percent10% of the unamortized balance each year. The amount subject to amortization is determined on a plan-by-plan basis. Amounts included in accumulated other comprehensive income (loss) at December 31, 2017, that are expected to be amortized into net periodic benefit cost during 2018 are provided below:
| | | | | | | | | | | | | Millions of Dollars | | | Pension Benefits | | Other Benefits |
| | | U.S. |
| | Int’l. |
| | | | | | | | | | | Unrecognized net actuarial loss | $ | 59 |
| | 19 |
| | — |
| | Unrecognized prior service credit | — |
| | (1 | ) | | (1 | ) |
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 | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | Pension Benefits | | Other Benefits | | | 2017 | | 2016 | | 2017 | | 2016 | | | U.S. |
| | Int’l. | | U.S. | | Int’l. | | | | | | Assumptions Used to Determine Benefit Obligations: | | | | | | | | | | | | | Discount rate | 3.60 | % | | 2.36 | | 3.95 | | 2.42 | | 3.35 | | 3.65 | | Rate of compensation increase | 4.00 |
| | 3.74 | | 4.00 | | 3.78 | | — | | — | | | | | | | | | | | | | | | Assumptions Used to Determine Net Periodic Benefit Cost: | | | | | | | | | | | | | Discount rate | 3.95 | % | | 2.46 | | 4.35 | | 3.35 | | 3.65 | | 4.00 | | Expected return on plan assets | 6.75 |
| | 4.74 | | 6.75 | | 5.31 | | — | | — | | Rate of compensation increase | 4.00 |
| | 3.78 | | 4.00 | | 3.65 | | — | | — |
For both U.S. and international pension plans, the overall expected long-term rate of return is developed from the expected future return of each asset class, weighted by the expected allocation of pension assets to that asset class. We rely on a variety of independent market forecasts in developing the expected rate of return for each class of assets.
For the year ended December 31, 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 through the company.insurance. In general, employees hired after December 31, 2012, will not receive credits to an account, but will have unsubsidized access to health insurance through the plan. The cost of health insurance will be adjusted annually by the company’s actuary to reflect actual experience and expected health care cost trends. The measurement of the accumulated benefit obligation assumes a health care cost trend rate of 6.25 percent7% in 20182024 that declines to 5.00 percent5% by 2023. A one percentage-point change in the assumed health care cost trend rate would be immaterial2031.
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 57 percent47% equity securities, 41 percent37% debt securities, 8% real estate investments and 2 percent8% in all other types of investments.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 mutual fundscorporate debt securities are valued based on quotedestimated using recently executed transactions and market prices, which representprice 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 net asset valuesecurity against other securities with actual market prices.
•Fair values of shares held. Cashcash and cash equivalents are valued at cost, which approximates fair value.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 real estate investments are valued using real estate valuation techniques and other methods that include reference to third-party sources and sales comparables where available.
•Fair values of investments in common/collective trusts (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 determineda practical expedient. The NAV is based on the underlying net assets owned by the issuerfund and the relative interest of each fund. Certain investments that are measured at fair value using the NAV value per share (or its equivalent) practical expedient have not been classifiedparticipating investor in the fair value hierarchy.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. | | | U.S. | | International | | | Millions of Dollars | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | | U.S. | | International | | | Level 1 |
| | Level 2 |
| | Level 3 |
| | Total |
| | Level 1 |
| | Level 2 |
| | Level 3 |
| | Total |
| | 2017 | | | | | | | | | | | | | | | | | 2023 | | | Equity securities | | | Equity securities | | | Equity securities | $ | 589 |
| | — |
| | — |
| | 589 |
| | — |
| | — |
| | — |
| | — |
| | Government debt securities | 632 |
| | — |
| | — |
| | 632 |
| | — |
| | — |
| | — |
| | — |
| | Mutual funds | 129 |
| | — |
| | — |
| | 129 |
| | — |
| | — |
| | — |
| | — |
| | Corporate debt securities | | | | Cash and cash equivalents | | | Cash and cash equivalents | | | Cash and cash equivalents | 90 |
| | — |
| | — |
| | 90 |
| | 6 |
| | — |
| | — |
| | 6 |
| | Insurance contracts | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 14 |
| | 14 |
| | Real estate | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 8 |
| | 8 |
| | | Total assets in the fair value hierarchy | | | Total assets in the fair value hierarchy | | | Total assets in the fair value hierarchy | 1,440 |
| | — |
| | — |
| | 1,440 |
| | 6 |
| | — |
| | 22 |
| | 28 |
| | Common/collective trusts measured at NAV |
| |
| |
| | 1,311 |
| |
| |
| |
| | 944 |
| | Real estate and infrastructure investments measured at NAV | | | Total | $ | 1,440 |
| | — |
| | — |
| | 2,751 |
| | 6 |
| | — |
| | 22 |
| | 972 |
|
| | | | | | | | | | | | | | | | | | | | | Millions of Dollars | | U.S. | | | U.S. | | International | | | Millions of Dollars | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | | U.S. | | International | | | Level 1 |
| | Level 2 |
| | Level 3 |
| | Total |
| | Level 1 |
| | Level 2 |
| | Level 3 |
| | Total |
| | 2016 | | | | | | | | | | | | | | | | | 2022 | | | Equity securities | $ | 533 |
| | — |
| | — |
| | 533 |
| | — |
| | — |
| | — |
| | — |
| | Mutual funds | 47 |
| | — |
| | — |
| | 47 |
| | — |
| | — |
| | — |
| | — |
| | Equity securities | | | Equity securities | | | Government debt securities | | | Corporate debt securities | | | Cash and cash equivalents | 21 |
| | — |
| | — |
| | 21 |
| | 5 |
| | — |
| | — |
| | 5 |
| | Insurance contracts | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 13 |
| | 13 |
| | Real estate | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 6 |
| | 6 |
| | | Total assets in the fair value hierarchy | | | Total assets in the fair value hierarchy | | | Total assets in the fair value hierarchy | 601 |
| | — |
| | — |
| | 601 |
| | 5 |
| | — |
| | 19 |
| | 24 |
| | Common/collective trusts measured at NAV | | | | | | | 1,673 |
| | | | | | | | 772 |
| | Real estate and infrastructure investments measured at NAV | | | Total | $ | 601 |
| | — |
| | — |
| | 2,274 |
| | 5 |
| | — |
| | 19 |
| | 796 |
|
As reflected in the table above, Level 3 activity was not material.
Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to international plans are subject to local laws and tax regulations. Actual contribution amounts are dependent upon plan asset returns, changes in pension obligations, regulatory environments, and other economic factors. In 2018,2024, we expect to contribute approximately $60$75 million to our U.S. pension plans and other postretirement benefit plans and $35$5 million to our international pension plans.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by usto 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 | |
| | | | | | | | | | | | | Millions of Dollars | | | Pension Benefits | | Other Benefits |
| | | U.S. |
| | Int’l. |
| | | | | | | | | | | 2018 | $ | 329 |
| | 22 |
| | 27 |
| | 2019 | 302 |
| | 22 |
| | 28 |
| | 2020 | 294 |
| | 24 |
| | 27 |
| | 2021 | 290 |
| | 26 |
| | 26 |
| | 2022 | 292 |
| | 27 |
| | 24 |
| | 2023-2026 | 1,298 |
| | 162 |
| | 101 |
|
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 percent75% of their eligible pay, subject to certain statutory limits, in the thrift feature of the Savings Plan to a choice of investment funds. For the years ended December 31, 2023 and 2022, Phillips 66 providesprovided a company match of participant thrift contributions up to 5 percent of eligible pay. In addition, participants who contribute at least 1 percent to the Savings Plan are eligible for “Success Share,” a semi-annual discretionary company contribution to the Savings Plan that can range from 0 to 6 percent8% 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 targetcompany match of 2 percent. The totalparticipant 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 participants inour contributions to the Savings Plan was $101 million, $99 million and $134 million in 2017, 2016 and 2015, respectively.Plan.
Note 20—22—Share-Based Compensation Plans
In accordance with the Employee Matters Agreement related to the Separation, compensationShare-based payment awards, based on ConocoPhillips stock and granted before April 30, 2012 (the Separation Date) were converted to compensation awards based on both ConocoPhillips and Phillips 66 stock if, on the Separation Date, the awards were: (1) options outstanding and exercisable; or (2) restricted stock or restricted stock units (RSUs) awarded for completed performance periods under the ConocoPhillips Performance Share Program. Phillips 66 restricted stock, RSUs and options issued in this conversion became subject to the “Omnibus Stock and Performance Incentive Plan of Phillips 66” (the 2012 Plan) on the Separation Date, whether held by grantees working for Phillips 66 or grantees that remained employees of ConocoPhillips. Some of these awards based on Phillips 66 stock and held by employees of ConocoPhillips are outstanding and appear in the activity tables for the Stock Option and the Performance Share Programs presented later in this footnote.
In May 2013, shareholders approved the 2013 Omnibus Stock and Performance Incentive Plan of Phillips 66 (the P66 Omnibus Plan). Subsequent to this approval, all new share-based awards are granted under the P66 Omnibus Plan, which authorizes the Human Resources and Compensation Committee (HRCC) of our Board of Directors to grantincluding stock options, stock appreciation rights, stock awards (including restricted stock and RSU awards), cash awards, and performance awards, are granted to our employees, non-employeenonemployee directors and other plan participants. The numberparticipants by the Human Resources and Compensation Committee (HRCC) of new shares that may be issuedour 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 may not exceed 45 million.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) | |
| | | | | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | 2015 |
| | | | | | | | | Share-based compensation expense | $ | 142 |
| | 156 |
| | 144 |
| | Income tax benefit | (74 | ) | | (59 | ) | | (54 | ) |
Stock Options
Stock options granted under the provisions of the P66 Omnibus Plan and earlier plans permit purchases of our common stock at exercise prices equivalent to the average of the high and low market price of our stock on the date the options were granted. The options have terms of 10 years and vest ratably, with one-third of the options becoming exercisable on each anniversary date for the three years following the date of grant. Options awarded to employees eligible for retirement are not subject to forfeiture six months after the grant date.
The following table summarizes our stock option activity from January 1, 2017, to December 31, 2017:
| | | | | | | | | | | | | | | | | | | | | | | | Millions of Dollars |
| | | Options |
| | Weighted- Average Exercise Price |
| | Weighted-Average Grant-Date Fair Value |
| | Aggregate
Intrinsic Value |
| | | | | | | | | | | Outstanding at January 1, 2017 | 5,103,130 |
| | $ | 49.48 |
| |
|
| |
| | Granted | 864,100 |
| | 78.48 |
| | $ | 16.95 |
| |
| | Forfeited | (32,500 | ) | | 78.48 |
| |
| |
|
| | Exercised | (1,095,875 | ) | | 32.38 |
| |
| | $ | 62 |
| | Outstanding at December 31, 2017 | 4,838,855 |
| | $ | 58.34 |
| |
| |
| | | | | | | | | | | Vested at December 31, 2017 | 4,191,679 |
| | $ | 55.25 |
| |
| | $ | 195 |
| | | | | | | | | | | Exercisable at December 31, 2017 | 3,258,015 |
| | $ | 48.79 |
| |
| | $ | 172 |
|
The weighted-average remaining contractual terms of vested options and exercisable options at December 31, 2017, were 5.48 years and 4.62 years, respectively. During 2017, we received $35 million in cash and realized an income tax benefit of $9 million from the exercise of options. At December 31, 2017, the remaining unrecognized compensation expense from unvested options was $6 million, which will be recognized over a weighted-average period of 20 months, the longest period being 27 months. The calculations of realized income tax benefits and weighted-average periods include awards based on both Phillips 66 and ConocoPhillips stock held by Phillips 66 employees.
During 2016 and 2015, we granted options with a weighted-average grant-date fair value of $16.94 and $18.84, respectively. During 2016 and 2015, employees exercised options with an aggregate intrinsic value of $58 million and $60 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:
| | | | | | | | | | 2017 |
| | 2016 | | 2015 | | | | | | | | | Risk-free interest rate | 2.28 | % | | 1.71 | | 1.60 | | Dividend yield | 2.90 | % | | 3.00 | | 3.00 | | Volatility factor | 26.91 | % | | 28.68 | | 34.17 | | Expected life (years) | 7.22 |
| | 7.08 | | 6.66 |
After the Separation and through 2015, we calculated the volatility of options granted using a formula that adjusts the pre-Separation historical volatility of ConocoPhillips by the ratio of Phillips 66 implied market volatility on the grant date divided by the pre-Separation implied market volatility of ConocoPhillips. In 2016, we began calculating the volatility using historical Phillips 66 end-of-week closing stock prices from the Separation date.
We use the average period of time elapsed between grant dates and exercise dates of past grants to estimate the expected life of new option grants.
Restricted Stock Units Generally, RSUs are granted annually under the provisions of the P66 Omnibus Planapplicable 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 of a dividend equivalent 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 eligibleretirement-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.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, 2017,2023, to December 31, 2017:2023:
| | | | | | | | | | | | | | | | | | | | | | | 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 | | | |
| | | | | | | | | | | | | | | | | | Millions of Dollars |
| | | Stock Units |
| | Weighted-Average Grant-Date Fair Value |
| | Total Fair Value |
| | | | | | | | | Outstanding at January 1, 2017 | 2,643,139 |
| | $ | 71.28 |
| |
| | Granted | 975,164 |
| | 78.49 |
| |
| | Forfeited | (58,171 | ) | | 77.18 |
| |
| | Issued | (1,063,707 | ) | | 63.67 |
| | $ | 85 |
| | Outstanding at December 31, 2017 | 2,496,425 |
| | $ | 77.20 |
| |
| | | | | | | | | Not Vested at December 31, 2017 | 1,615,668 |
| | $ | 77.32 |
| |
|
At December 31, 2017,2023, the remaining unrecognized compensation cost from the unvested RSU awards was $50$92 million, which will be recognized over a weighted-average period of 2018 months, the longest period being 3735 months.
During 20162022 and 2015,2021, we granted RSUs with a weighted-average grant-date fair value of $78.56$88.16 and $74.09,$75.91, respectively. During 20162022 and 2015,2021, we issued shares with an aggregate fair value of $109$102 million and $107$61 million, respectively, to settle RSUs.
Performance Share Units Under the P66 Omnibus Plan, weapplicable Phillips 66 incentive plan, senior management is annually grant to senior managementawarded restricted performance share units (PSUs) with three-year performance periods that vest: (1) with respect toperiods. These awards for performance periods beginning before 2009,vest when the employee becomes eligible for retirement; or (2) with respect to awards forHRCC approves the three-year performance periods beginning in 2009, the shorter of: (a) the participant’s retirement eligibility date; or (b) five years afterresults, which represents the grant datedate. Retirement-eligible employees may retain a prorated share of the award; or (3) with respectaward if they retire prior to awards for performance periods beginning in 2013 or later, at the end of the performance period on the grant date.
For PSU PSUs are classified as liability awards with performance periods beginning before 2013, we recognizeand compensation expense beginning onis recognized over the date authorized and ending on the vest date. Since PSU awards withthree-year performance periods beginning in 2013 or later vest on the grant date, we recognize compensation expense beginning on the date of authorization and ending on the grant date for all employees.periods.
We settle each PSU with performance periods beginning before 2013 by issuing one share of our common stock and recipients receive a quarterly cash payment of a dividend equivalent beginning on the grant date and ending on the settlement date.
PSUs with performance periods beginning in 2013 or latergranted under the applicable Phillips 66 incentive plan are settled by paying cash payments equal to the fair value of the awards, which is based on the average of the high and low 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, 2017,2023, to December 31, 2017:2023: | | | | | | | | | | | | | | | | | | | | | | | 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 | — | | | $ | — | | | |
| | | | | | | | | | | | | | | | | | Millions of Dollars |
| | | Performance Share Units |
| | Weighted-Average Grant-Date Fair Value |
| | Total Fair Value |
| | | | | | | | | Outstanding at January 1, 2017 | 3,239,497 |
| | $ | 50.12 |
| |
| | Granted | 642,212 |
| | 86.88 |
| |
| | Issued | (681,219 | ) | | 42.85 |
| | $ | 54 |
| | Cash settled | (642,212 | ) | | 86.88 |
| | 56 |
| | Outstanding at December 31, 2017 | 2,558,278 |
| | $ | 52.06 |
| |
| | | | | | | | | Not Vested at December 31, 2017 | 286,031 |
| | $ | 66.65 |
| |
|
At December 31, 2017, the2023, there was no remaining unrecognized compensation cost from unvested PSU awards held by employeesawards.
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 $4$6 million, which will be recognized over a weighted-average period of 2321 months, with the longest period being 9 years. The calculations of unamortized expense and weighted-average periods include awards based on both Phillips 66 and ConocoPhillips stock held by Phillips 66 employees.30 months.
During 20162022 and 2015,2021, we granted PSUsoptions with a weighted-average grant-date fair value of $78.62$17.02 and $74.14,$12.06, respectively. During 20162022 and 2015, we issued shares2021, employees exercised options with an aggregate fairintrinsic value of $26$42 million and $37$24 million, respectively,respectively.
The following table provides the significant assumptions used to settle PSUs. 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 cash settled PSUs with an aggregate fair valuecalculate the volatility factor using historical Phillips 66 end-of-week closing stock prices. We periodically calculate the average period of $60time 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 in 2016. No PSUs were cash settled in 2015.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 21—23—Income Taxes
On December 22, 2017, the U.S. government enacted comprehensive income tax legislation, referred to as the Tax Cuts and Jobs Act (the Tax Act). The material provisions of the Tax Act i) reduced the U.S. federal corporate income tax rate from 35 percent to 21 percent beginning January 1, 2018, ii) required companies to reflect on their 2017 corporate income tax return a liability for a one-time deemed repatriation tax on foreign-sourced earnings that were previously tax deferred, and iii) created a new tax regime for post-2017 foreign-sourced earnings.
To account for the reduction in the U.S. federal corporate income tax rate, we remeasured our deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, generally 21 percent, which resulted in a provisional deferred tax benefit of $2,870 million. To account for the one-time deemed repatriation income tax, we calculated our provisional liability in accordance with the Tax Act and considered previously accrued current and deferred tax liabilities on undistributed earnings of our foreign subsidiaries and foreign joint ventures. The effects of the one-time deemed repatriation tax resulted in a provisional income tax expense of $149 million.
The provisions in the Tax Act are broad and complex. We have not yet completed our accounting for the income tax effects of the Tax Act as of December 31, 2017, but have made reasonable estimates of those effects on our existing deferred income tax balances and the one-time deemed repatriation tax. The final financial statement impact of the Tax Act may differ from the above estimates, possibly materially, due to, among other things, changes in interpretations of the Tax Act, any legislative action to address questions that arise because of the Tax Act, and changes in accounting standards for income taxes or related interpretations in response to the Tax Act, or any updates or changes to estimates the company has utilized to calculate the provisional impacts. The Securities and Exchange Commission (SEC) has issued rules that would allow for a measurement period of up to one year after the enactment date of the Tax Act to finalize the recording of the related income tax impacts.
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 | |
| | | | | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | 2015 |
| | Income Tax Expense (Benefit) | | | | | | | Federal | | | | | | | Current | $ | 9 |
| | (105 | ) | | 1,128 |
| | Deferred | (1,960 | ) | | 645 |
| | 444 |
| | Foreign | | | | | | | Current | 126 |
| | 66 |
| | (74 | ) | | Deferred | 3 |
| | (84 | ) | | 42 |
| | State and local | | | | | | | Current | 61 |
| | (24 | ) | | 227 |
| | Deferred | 68 |
| | 49 |
| | (3 | ) | | | $ | (1,693 | ) | | 547 |
| | 1,764 |
|
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 | |
| | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | Deferred Tax Liabilities | | | | | Properties, plants and equipment, and intangibles | $ | 2,942 |
| | 4,525 |
| | Investment in joint ventures | 1,923 |
| | 2,442 |
| | Investment in subsidiaries | 594 |
| | 803 |
| | Inventory | — |
| | 154 |
| | Other | 18 |
| | 19 |
| | Total deferred tax liabilities | 5,477 |
| | 7,943 |
| | Deferred Tax Assets | | | | | Benefit plan accruals | 314 |
| | 669 |
| | Inventory | 10 |
| | — |
| | Asset retirement obligations and accrued environmental costs | 121 |
| | 211 |
| | Other financial accruals and deferrals | 44 |
| | 188 |
| | Loss and credit carryforwards | 96 |
| | 261 |
| | Other | 3 |
| | 1 |
| | Total deferred tax assets | 588 |
| | 1,330 |
| | Less: valuation allowance | 28 |
| | 38 |
| | Net deferred tax assets | 560 |
| | 1,292 |
| | Net deferred tax liabilities | $ | 4,917 |
| | 6,651 |
|
TheAt December 31, 2023, the loss and credit carryforwardscarryforward deferred tax assets arewere primarily related to a German interest deductionforeign tax credit carryforward in the United States of $113 million; a state tax net operating loss carryforward of $77 million, a U.S. alternative minimum tax credit of $10 million$30 million; and a capital loss and net operating loss carryforwardcarryforwards in the United Kingdom of $7$8 million. All losses may be carried forward indefinitelyState 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 the alternative minimum credit carryforwards, all of $10 million, if not utilized sooner, will become refundable with the filing of the 2021 U.S. federal income tax return.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 2017,the year ended December 31, 2023, our total valuation allowances decreasedallowance balance increased by a total of $10$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.
At December 31, 2017, all undistributed earningsEarnings of our foreign subsidiaries and foreign joint ventures have been includedafter 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 provisional computation offoreign subsidiaries are indefinitely reinvested. At December 31, 2023 and 2022, the one-time deemed repatriation tax associated with the enactment of the Tax Act. After considering the effects of the Tax Act described above, we have not provided aunrecorded deferred tax liability related to any remaining difference inthe undistributed earnings of this foreign subsidiary was not material.
A deferred income tax liability has not been recognized on the excess of the book andbasis over the tax basis of an investment in oura controlled foreign subsidiaries or foreign joint ventures because such differences aresubsidiary that is essentially permanent in duration. Based on our preliminary analysis, which is not yet complete,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 and associated unrecordedresulting from the investment book basis exceeding the tax basis was $1,430 million. Determination of the unrecognized deferred income tax liability arerelated to this temporary difference is not material.practicable given the variables involved in performing such a calculation.
As a result ofWe file tax returns in the SeparationU.S. federal jurisdiction and pursuant toin many foreign and state jurisdictions. Unrecognized tax benefits reflect the Tax Sharing Agreement with ConocoPhillips, the unrecognizeddifference between positions taken on income tax benefits related to our operations for which ConocoPhillips wasreturns and the taxpayer remainamounts recognized in the responsibility of ConocoPhillips, and we have indemnified ConocoPhillips for such amounts. Followingfinancial 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 | |
| | | | | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | 2015 |
| | | | | | | | | Balance at January 1 | $ | 70 |
| | 82 |
| | 142 |
| | Additions for tax positions of prior years | 1 |
| | 5 |
| | 6 |
| | Reductions for tax positions of prior years | (5 | ) | | (17 | ) | | (17 | ) | | Settlements | (32 | ) | | — |
| | (49 | ) | | Balance at December 31 | $ | 34 |
| | 70 |
| | 82 |
|
Included in the balance of unrecognized income tax benefits for 2017, 2016at December 31, 2023, 2022 and 20152021, were $5$100 million, $13$37 million and $34$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 liability, approximately $2liabilities, we expect $28 million mayto be recognized or paid within the next twelve months due to completion of audits.months.
At December 31, 2017, 20162023, 2022 and 2015,2021, accrued liabilities for interest and penalties, net of accrued income taxes, totaled $8 million, $12$7 million and $19$6 million, respectively. As a resultThese accruals decreased our results for each of reversing certain of these accruals, earnings increasedthe years ended December 31, 2023, 2022 and 2021 by $1 million, $7$3 million and $3 million, in 2017, 2016 and 2015, respectively.
We file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions.
Audits in significant jurisdictions are generally complete as follows: United Kingdom (2014)(2021), Germany (2011)(2017) and United States (2010)(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 | |
| | | | | | | | | | | | | | | | | | | | | | Millions of Dollars | | Percentage of Income Before Income Taxes | | | 2017 |
| | 2016 |
| | 2015 |
| | 2017 |
| | 2016 |
| | 2015 |
| | Income before income taxes | | | | | | | | | | | | | United States | $ | 2,799 |
| | 1,713 |
| | 4,983 |
| | 78.7 | % | | 78.2 |
| | 82.4 |
| | Foreign | 756 |
| | 478 |
| | 1,061 |
| | 21.3 |
| | 21.8 |
| | 17.6 |
| | | $ | 3,555 |
| | 2,191 |
| | 6,044 |
| | 100.0 | % | | 100.0 |
| | 100.0 |
| | | | | | | | | | | | | | | Federal statutory income tax | $ | 1,244 |
| | 767 |
| | 2,115 |
| | 35.0 | % |
| 35.0 |
| | 35.0 |
| | State income tax, net of federal benefit | 79 |
| | 12 |
| | 150 |
| | 2.2 |
|
| 0.6 |
| | 2.5 |
| | Tax Cuts and Jobs Act | (2,721 | ) | | — |
| | — |
| | (76.5 | ) | | — |
| | — |
| | Foreign rate differential | (210 | ) | | (152 | ) | | (239 | ) | | (5.9 | ) |
| (6.9 | ) | | (3.9 | ) | | Noncontrolling interests | (46 | ) | | (26 | ) | | (13 | ) | | (1.3 | ) | | (1.2 | ) | | (0.2 | ) | | Federal manufacturing deduction | (18 | ) | | — |
| | (77 | ) | | (0.5 | ) |
| — |
| | (1.3 | ) | | Change in valuation allowance | (4 | ) | | (81 | ) | | (17 | ) | | (0.1 | ) |
| (3.7 | ) | | (0.2 | ) | | Goodwill allocated to assets sold | — |
| | — |
| | 41 |
| | — |
|
| — |
| | 0.7 |
| | German tax legislation | — |
| | — |
| | (103 | ) | | — |
|
| — |
| | (1.7 | ) | | Sale of foreign subsidiaries | — |
| | — |
| | (125 | ) | | — |
|
| — |
| | (2.1 | ) | | Other | (17 | ) | | 27 |
| | 32 |
| | (0.5 | ) |
| 1.2 |
| | 0.4 |
| | | $ | (1,693 | ) | | 547 |
| | 1,764 |
| | (47.6 | )% |
| 25.0 |
| | 29.2 |
|
Included inFor the line item “Saleyear ended December 31, 2021, state income tax, net of foreign subsidiaries” is a $72 millionfederal income tax benefit, realized in 2015 attributableincludes a $58 million benefit, primarily to reflect the nontaxable gain fromimpact of updated apportionment factors.
For the saleyears ended December 31, 2023 and 2022, income tax benefits of ICHP.
Income tax expense of $81$113 million and $150$323 million, in 2017 and 2016, respectively, and an income tax benefit of $34 million in 2015 are reflected in the “Capital in Excess of Par” column on ourthe 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 22—24—Accumulated Other Comprehensive Income (Loss)Loss
Changes in the balances of each component of accumulated other comprehensive income (loss)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) | |
| | | | | | | | | | | | | | | | Millions of Dollars | | | Defined Benefit Plans |
| | Foreign Currency Translation |
| | Hedging |
| | Accumulated Other Comprehensive Loss |
| | | | | | | | | | | December 31, 2014 | $ | (696 | ) | | 167 |
| | (2 | ) | | (531 | ) | | Other comprehensive loss before reclassification | (78 | ) | | (156 | ) | | — |
| | (234 | ) | | Amounts reclassified from accumulated other comprehensive loss* |
|
| |
|
| |
|
| |
|
| | Amortization of defined benefit plan items** |
|
| |
|
| |
|
| |
|
| | Actuarial losses and settlements | 112 |
| | — |
| | — |
| | 112 |
| | Net current period other comprehensive income (loss) | 34 |
| | (156 | ) | | — |
| | (122 | ) | | December 31, 2015 | (662 | ) | | 11 |
| | (2 | ) | | (653 | ) | | Other comprehensive income (loss) before reclassifications | (112 | ) | | (296 | ) | | 5 |
| | (403 | ) | | Amounts reclassified from accumulated other comprehensive loss* |
|
| |
|
| |
|
| |
|
| | Amortization of defined benefit plan items** |
|
| |
|
| |
|
| |
|
| | Actuarial losses and settlements | 61 |
| | — |
| | — |
| | 61 |
| | Net current period other comprehensive income (loss) | (51 | ) | | (296 | ) | | 5 |
| | (342 | ) | | December 31, 2016 | (713 | ) | | (285 | ) | | 3 |
| | (995 | ) | | Other comprehensive income before reclassifications | 3 |
| | 259 |
| | 4 |
| | 266 |
| | Amounts reclassified from accumulated other comprehensive loss* |
|
| |
|
| |
|
| |
|
| | Amortization of defined benefit plan items** |
|
| |
|
| |
|
| |
|
| | Actuarial losses and settlements | 112 |
| | — |
| | — |
| | 112 |
| | Net current period other comprehensive income | 115 |
| | 259 |
| | 4 |
| | 378 |
| | December 31, 2017 | $ | (598 | ) | | (26 | ) | | 7 |
| | (617 | ) |
* There were no significant reclassifications related to foreign currency translation or hedging.
** Included in the computation of net periodic benefit cost. See Note 19—21—Pension and Postretirement Plans, for additional information.
Note 23—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 | |
| | | | | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | 2015 |
| | Cash Payments (Receipts) | | | | | | | Interest | $ | 421 |
| | 311 |
| | 275 |
| | Income taxes* | (257 | ) | | (375 | ) | | 1,560 |
|
* 2017 and 2016 reflected a net cash refund position; cash payments for income taxes were $102 million and $385 million in 2017 and 2016, respectively.
Restricted Cash
At December 31, 2017 and 2016, the company did not have any restricted cash. The restrictions on the cash acquired in February 2017, as a result of the consolidation of MSLP, were fully removed in May 2017 when MSLP’s outstanding debt that contained lender restrictions on the use of cash was paid in full. See Note 5—Business Combinations and Note 12—Debt for additional information regarding MSLP.
Note 24—Other Financial Information
| | | | | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | 2015 |
| | Interest and Debt Expense | | | | | | | Incurred | | | | | | | Debt | $ | 432 |
| | 402 |
| | 389 |
| | Other | 21 |
| | 17 |
| | 27 |
| | | 453 |
| | 419 |
| | 416 |
| | Capitalized | (15 | ) | | (81 | ) | | (106 | ) | | Expensed | $ | 438 |
| | 338 |
| | 310 |
| | | | | | | | | Other Income | | | | | | | Interest income | $ | 31 |
| | 18 |
| | 27 |
| | Gain on consolidation of business* | 423 |
| | — |
| | — |
| | Other, net** | 67 |
| | 56 |
| | 91 |
| | | $ | 521 |
| | 74 |
| | 118 |
| | * See Note 5—Business Combinations regarding the gain recognized in 2017. | | ** Includes derivatives-related activities. | | | | | | | | Research and Development Expenditures—expensed | $ | 60 |
| | 60 |
| | 65 |
| | | | | | | | | Advertising Expenses | $ | 76 |
| | 80 |
| | 73 |
| | | | | | | | Foreign Currency Transaction (Gains) Losses—after-tax | | | | | | | Midstream | $ | — |
| | — |
| | — |
| | Chemicals | — |
| | — |
| | — |
| | Refining | (1 | ) | | (10 | ) | | 34 |
| | Marketing and Specialties | 1 |
| | 1 |
| | 4 |
| | Corporate and Other | — |
| | (2 | ) | | — |
| | | $ | — |
| | (11 | ) | | 38 |
|
Note 25—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 | | | | | | | |
| | | | | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | 2015 |
| | | | | | | | | Operating revenues and other income (a) | $ | 2,596 |
| | 2,174 |
| | 2,452 |
| | Purchases (b) | 10,468 |
| | 8,109 |
| | 8,142 |
| Operating expenses and selling, general and administrative expenses (c) | 79 |
| | 125 |
| | 129 |
|
(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 discussed more fully in Note 5—Business Combinations, in February 2017,a result of the DCP Midstream Merger, we began accounting for MSLP as a consolidated subsidiary. Accordingly,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 only includes processing fees paidabove.
| | (a) | We sold NGL and other petrochemical feedstocks, along with solvents, to CPChem, and we sold gas oil and hydrogen feedstocks to Excel Paralubes (Excel). We sold refined products to our OnCue Holdings, LLC joint venture. We sold certain feedstocks and intermediate products to WRB and also acted as agent for WRB in supplying crude oil and other feedstocks for a fee. In addition, we charged several of our affiliates, including CPChem, for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities. |
| | (b) | We purchased crude oil and refined products from WRB and also acted as agent for WRB in distributing solvents. We purchased natural gas and NGL from DCP Midstream and CPChem, as well as other feedstocks from various affiliates, for use in our refinery and fractionation processes. We paid NGL fractionation fees to CPChem. We also paid fees to various pipeline equity companies for transporting crude oil, refined products and NGL. We purchased base oils and fuel products from Excel for use in our refining and specialty businesses. |
| | (c) | We paid utility and processing fees to various affiliates. |
Note 26—28—Segment Disclosures and Related Information
Our operating segments are:
| | 1) | Midstream—Provides crude oil and refined products transportation, terminaling and processing services, as well as natural gas, NGL and liquefied petroleum gas (LPG) transportation, storage, processing and marketing services, mainly in the United States. The Midstream segment includes our master limited partnership, Phillips 66 Partners, as well as our 50 percent equity investment in DCP Midstream.
|
| | 2) | Chemicals—Consists of our 50 percent equity investment in CPChem, which manufactures and markets petrochemicals and plastics on a worldwide basis.
|
| | 3) | Refining—Refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels) at 13 refineries in the United States and Europe.
|
| | 4) | Marketing and Specialties—Purchases for resale and markets refined petroleum products, mainly in the United States and Europe. In addition, this segment includes the manufacturing and marketing of specialty products, as well as power generation operations.
|
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.
119
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 investmentsinvestment in research of new technologies and various other corporate activities. Corporate assets include all cash, cash equivalents and cash equivalents. In addition,income tax-related assets. Corporate and Other also includes the provisional income tax benefit from the enactment of the Tax Act on December 22, 2017.restructuring costs related to our business transformation. See Note 21—Income Taxes31—Restructuring, for further discussion.additional information regarding restructuring costs.
During the fourth quarter of 2017, the segment performance measure used by our chief executive officer to assess performance and allocate resources was changed from “net income attributable to Phillips 66” to “net income.” This change reflects the recognition that management does not differentiate between those earnings attributable to Phillips 66 and those attributable to noncontrolling interests when making operating and resource allocation decisions impacting segment performance. Prior period segment information has been recast to conform to the current presentation. Intersegment sales are at prices that we believe approximate market.
Analysis of Results by Operating Segment | | | | | | | | | | Millions of Dollars | | | Millions of Dollars | | 2023 | | 2022 | | 2021 | | | 2017 |
| | 2016 |
| | 2015 |
| | Sales and Other Operating Revenues | | | | | | | Sales and Other Operating Revenues* | | | Midstream | | | | | | | Midstream | | | Midstream | | | Total sales | | | Total sales | | | Total sales | $ | 6,620 |
| | 4,226 |
| | 3,676 |
| | Intersegment eliminations | (1,842 | ) | | (1,299 | ) | | (1,034 | ) | | Total Midstream | 4,778 |
| | 2,927 |
| | 2,642 |
| | Chemicals | 5 |
| | 5 |
| | 5 |
| | Refining | | | | | | | Total sales | 65,494 |
| | 52,068 |
| | 63,470 |
| | Total sales | | | Total sales | | | Intersegment eliminations | (40,284 | ) | | (34,120 | ) | | (40,317 | ) | | Total Refining | 25,210 |
| | 17,948 |
| | 23,153 |
| | Marketing and Specialties | | | | | | | Total sales | | | Total sales | | | Total sales | 73,565 |
| | 64,476 |
| | 74,591 |
| | Intersegment eliminations | (1,233 | ) | | (1,109 | ) | | (1,446 | ) | | Total Marketing and Specialties | 72,332 |
| | 63,367 |
| | 73,145 |
| | Corporate and Other | 29 |
| | 32 |
| | 30 |
| | Consolidated sales and other operating revenues | $ | 102,354 |
| | 84,279 |
| | 98,975 |
| | * See Note 5—Sales and Other Operating Revenues, for further details on our disaggregated sales and other operating revenues. | | * See Note 5—Sales and Other Operating Revenues, for further details on our disaggregated sales and other operating revenues. | | | | | | | | | Depreciation, Amortization and Impairments | | | | | | | Equity in Earnings (Losses) of Affiliates | | | Equity in Earnings (Losses) of Affiliates | | | Equity in Earnings (Losses) of Affiliates | | | Midstream | | | Midstream | | | Midstream | | | Chemicals | | | Refining | | | Marketing and Specialties | | | Corporate and Other | | | Consolidated equity in earnings of affiliates | | | | Depreciation, Amortization and Impairments* | | | Depreciation, Amortization and Impairments* | | | Depreciation, Amortization and Impairments* | | | Midstream | | | Midstream | | | Midstream | $ | 299 |
| | 218 |
| | 128 |
| | Chemicals | — |
| | — |
| | — |
| | Refining | 838 |
| | 770 |
| | 741 |
| | Marketing and Specialties | 116 |
| | 107 |
| | 100 |
| | Corporate and Other | 89 |
| | 78 |
| | 116 |
| | Consolidated depreciation, amortization and impairments | $ | 1,342 |
| | 1,173 |
| | 1,085 |
| | * See Note 11—Impairments, for further details on impairments by segment. | | * 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 | | | 2017 |
| | 2016 |
| | 2015 |
| | Equity in Earnings of Affiliates | | | | | | | Midstream | $ | 454 |
| | 184 |
| | (268 | ) | | Chemicals | 713 |
| | 834 |
| | 1,316 |
| | Refining | 322 |
| | 164 |
| | 325 |
| | Marketing and Specialties | 243 |
| | 232 |
| | 207 |
| | Corporate and Other | — |
| | — |
| | (7 | ) | | Consolidated equity in earnings of affiliates | $ | 1,732 |
| | 1,414 |
| | 1,573 |
| | | | | | | | | Income Tax Expense (Benefit) | | | | | | | Midstream | $ | 174 |
| | 123 |
| | 73 |
| | Chemicals | 191 |
| | 256 |
| | 353 |
| | Refining | 672 |
| | 61 |
| | 1,104 |
| | Marketing and Specialties | 334 |
| | 370 |
| | 466 |
| | Corporate and Other | (3,064 | ) | | (263 | ) | | (232 | ) | | Consolidated income tax expense (benefit) | $ | (1,693 | ) | | 547 |
| | 1,764 |
| | | | | | | | | Net Income (Loss) | | | | | | | Midstream | $ | 464 |
| | 280 |
| | 74 |
| | Chemicals | 525 |
| | 583 |
| | 962 |
| | Refining | 1,404 |
| | 374 |
| | 2,555 |
| | Marketing and Specialties | 686 |
| | 891 |
| | 1,187 |
| | Corporate and Other | 2,169 |
| | (484 | ) | | (498 | ) | | Consolidated net income | $ | 5,248 |
| | 1,644 |
| | 4,280 |
|
| | | | | | | | | | | | | | | | | | | | 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 | |
| | | | | | | | | | | | | Millions of Dollars | | | 2017 |
| | 2016 |
| | 2015 |
| | Investments In and Advances To Affiliates | | | | | | | Midstream | $ | 4,734 |
| | 4,769 |
| | 4,198 |
| | Chemicals | 6,222 |
| | 5,773 |
| | 5,177 |
| | Refining | 2,398 |
| | 2,420 |
| | 2,262 |
| | Marketing and Specialties | 390 |
| | 391 |
| | 342 |
| | Corporate and Other | — |
| | 1 |
| | 1 |
| | Consolidated investments in and advances to affiliates | $ | 13,744 |
| | 13,354 |
| | 11,980 |
| | | | | | | | | Total Assets | | | | | | | Midstream | $ | 13,231 |
| | 12,832 |
| | 11,043 |
| | Chemicals | 6,226 |
| | 5,802 |
| | 5,237 |
| | Refining | 23,820 |
| | 22,825 |
| | 21,993 |
| | Marketing and Specialties | 7,103 |
| | 6,227 |
| | 5,631 |
| | Corporate and Other | 3,991 |
| | 3,967 |
| | 4,676 |
| | Consolidated total assets | $ | 54,371 |
| | 51,653 |
| | 48,580 |
| | | | | | | | | Capital Expenditures and Investments | | | | | | | Midstream | $ | 771 |
| | 1,453 |
| | 4,457 |
| | Chemicals | — |
| | — |
| | — |
| | Refining | 853 |
| | 1,149 |
| | 1,069 |
| | Marketing and Specialties | 108 |
| | 98 |
| | 122 |
| | Corporate and Other | 100 |
| | 144 |
| | 116 |
| | Consolidated capital expenditures and investments | $ | 1,832 |
| | 2,844 |
| | 5,764 |
| | | | | | | | | Interest Income and Expense | | | | | | | Interest income | | | | | | | Midstream | $ | 1 |
| | 2 |
| | — |
| | Marketing and Specialties | — |
| | — |
| | 2 |
| | Corporate and Other | 30 |
| | 16 |
| | 25 |
| | Consolidated interest income | $ | 31 |
| | 18 |
| | 27 |
| | | | | | | | | Interest and debt expense | | | | | | | Corporate and Other | $ | 438 |
| | 338 |
| | 310 |
|
| | | | | | | | | | | | Sales and Other Operating Revenues by Product Line | | | | | | | Refined products | $ | 85,405 |
| | 73,385 |
| | 86,249 |
| | Crude oil resales | 11,808 |
| | 7,594 |
| | 8,993 |
| | NGL | 4,670 |
| | 3,107 |
| | 2,998 |
| | Other | 471 |
| | 193 |
| | 735 |
| | Consolidated sales and other operating revenues by product line | $ | 102,354 |
| | 84,279 |
| | 98,975 |
|
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 | | | | | | | | | | | | | | | | | | | | | | Millions of Dollars | | | Sales and Other Operating Revenues* | | Long-Lived Assets** | | | 2017 |
| | 2016 |
| | 2015 |
| | 2017 |
| | 2016 |
| | 2015 |
| | | | | | | | | | | | | | | United States | $ | 75,684 |
| | 59,742 |
| | 69,578 |
| | 33,264 |
| | 32,442 |
| | 29,624 |
| | United Kingdom | 10,626 |
| | 9,895 |
| | 12,120 |
| | 1,254 |
| | 1,177 |
| | 1,459 |
| | Germany | 6,692 |
| | 6,128 |
| | 6,584 |
| | 591 |
| | 503 |
| | 502 |
| | Other foreign countries | 9,352 |
| | 8,514 |
| | 10,693 |
| | 95 |
| | 87 |
| | 116 |
| | Worldwide consolidated | $ | 102,354 |
| | 84,279 |
| | 98,975 |
| | 35,204 |
| | 34,209 |
| | 31,701 |
|
* SalesDCP Midstream Class A Segment is a VIE and other operating revenueswe are attributable to countries based on the locationprimary beneficiary. DCP Midstream Class A Segment is comprised of the operations generatingbusinesses, 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 revenues.DCP Midstream Merger and related accounting.
** Defined as net properties, plants and equipment plus investments in and advances to affiliated companies.
Note 27—Phillips 66 PartnersDCP LP
Phillips 66 Partners is a publicly traded master limited partnership formed to own, operate, developwhose operations currently include producing and acquire primarily fee-based crude oil, refined petroleum productfractionating NGL, gathering, compressing, treating and NGL pipelinesprocessing natural gas; recovering condensate; and terminals, as well as other midstream assets. Headquartered in Houston, Texas, Phillips 66 Partners’ assets currently consist of crude oil, refined petroleum productstransporting, trading, marketing and NGL transportation, terminalingstoring natural gas and storage systems, as well as crude oil and NGL processing facilities.NGL.
We consolidate Phillips 66 Partners as a variable interest entity for financial reporting purposes. See Note 3—Variable Interest Entities for additional information on why we consolidate the partnership. As a result of this consolidation,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 perpetual convertibleindirect 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 unitholders’ ownershipunit 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 reflectedno longer publicly traded.
The merger was accounted for as noncontrolling interestsan equity transaction and resulted in decreases to “Treasury stock” of $2,314$3,380 million, “Noncontrolling interests” of $2,163 million, “Capital in excess of par” of $901 million, “Deferred income taxes” of $323 million, and $1,306“Cash and cash equivalents” of $2 million, and an increase to “Other accruals” of $5 million on our consolidated balance sheet as ofsheet.
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, 2017,2023, and 2016, respectively. Generally, drop down transactions2022, we recorded restructuring costs totaling $177 million and $160 million, respectively, primarily related to Phillips 66 Partners will eliminate in consolidation, exceptconsulting fees and severance costs. Restructuring costs for third-party debt and third-party equity offerings made by Phillips 66 Partners to finance such transactions.
At December 31, 2017, we owned a 55 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while the public owned a 43 percent limited partner interest and 13.8 million perpetual convertible preferred units.
2017 Activities
In October 2017, we contributed to Phillips 66 Partners our 25 percent interests in both Dakota Access and ETCO and our 100 percent interest in MSLP. Total consideration for the transaction was $1.65 billion, which consisted of $372 million in cash at closing, the assumption of $588 million of promissory notes payable to us, the assumption of a $450 million term loan payable to a third party, and the issuance to us of common and general partner units with a fair value of $240 million. Shortly after closing, Phillips 66 Partners repaid the $588 million of promissory notes payable to us, resulting in total cash received by us for the transaction of $960 million.
Phillips 66 Partners financed the consideration paid with the proceeds from the following third-party equity and debt offerings:
Net proceeds of $737 million from a private placement of 13,819,791 perpetual convertible preferred units, at a price of $54.27 per unit. Holders of the preferred units are entitled to receive cumulative quarterly distributions equal to $0.678375 per unit. Beginning in October 2020, holders are entitled to receive quarterly distributions equal to the greater of $0.678375 per unit or the per-unit distribution paid to common unitholders.
Net proceeds of $295 million from a private placement of 6,304,204 common units, at a price of $47.59 per unit.
A portion of the $643 million of net proceeds from a public offering of $650 million of Senior Notes. See Note 12—Debt for additional information on the Senior Notes.
In June 2016, Phillips 66 Partners began issuing common units under a continuous offering program, which allows for the issuance of up to an aggregate of $250 million of Phillips 66 Partners’ common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of the offerings (such continuous offering program, or at-the-market program, is referred to as the ATM program). For year ended December 31, 2017,2022, 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 a settlement-date basis, Phillips 66 Partners issued 3,372,716 common units underour consolidated statement of income and are reported in our Corporate segment.
In addition, for the ATM program, which generated net proceeds of $173 million. From inception throughyears ended December 31, 2017, Phillips 66 Partners has issued an aggregate2023 and 2022, we recorded restructuring costs of 3,718,868 common units under the ATM program, which generated net proceeds of $192 million.
Phillips 66 Partners filed a new shelf registration statement for Phillips 66 Partners’ second continuous offering program that became effective$38 million and $18 million, respectively, associated with the SECintegration 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 January 23, 2018, which allows for the issuanceour consolidated statement of up to an aggregate of $250 million of Phillips 66 Partners’ common units,income and are reported in amounts, at prices and on terms to be determined by market conditions and other factors at the time of the offerings.our Midstream segment.
Note 28—32—New Accounting Standards
In February 2017,December 2023, the FASB issued ASU No. 2017-05, “Other Income—Gains2023-09, “Income Taxes (Topic 740) – Improvements to Income Tax Disclosures,” which enhances the transparency, effectiveness, and Losses fromcomparability of income tax disclosures by requiring consistent categories and greater disaggregation of information related to income tax rate reconciliations and the Derecognition of Nonfinancial Assets (Subtopic 610-20).”jurisdictions in which income taxes are paid. This ASU clarifies the scope and accounting for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. This ASU will eliminate the use of carryover basis for most nonmonetary exchanges, including contributions of assets to equity method joint ventures. These amendments could result in the entity recognizing a gain or loss on the sale or transfer of nonfinancial assets. Public entities should apply the guidance in ASU No. 2017-05 to annual periods beginning after December 15, 2017, including interim periods within those periods. There was no impact on our financial statements from adopting this ASU on January 1, 2018.
In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which clarifies the definition of a business with the objective of adding guidance to assist in evaluating whether transactions should be accounted for as acquisitions of assets or businesses. The amendment provides a screen for determining when a transaction involves an acquisition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset, or a group of similar identifiable assets, then the transaction is not considered an acquisition of a business. If the screen is not met, then the amendment requires that to be considered a business, the operation must include at a minimum an input and a substantive process that together significantly contribute to the ability to create an output. The guidance may reduce the number of transactions accounted for as business acquisitions. Public business entities should apply the guidance in ASU No. 2017-01 to annual periods beginning after December 15, 2017, including interim periods within those periods, with early adoption permitted. The amendments should be applied prospectively and no disclosures are required at the effective date. There was no impact on our financial statements from adopting this ASU on January 1, 2018.
In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The new standard amends the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which may result in earlier recognition of losses. Public business entities should apply the guidance in ASU No. 2016-13 for annual periods beginning after December 15, 2019,2024, 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 annual periods. Earlyfiscal years, with early adoption will be permitted for annual periods beginning after December 15, 2018. We are currently evaluatingpermitted. Effective January 1, 2024, we adopted ASU 2023-01. At the provisionstime of ASU No. 2016-13 and assessing theadoption, there was no impact on our consolidated financial statements.statements from this ASU.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” The new standard establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will continue to be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. Similarly, lessors will be required to classify leases as sales-type, finance or operating, with classification affecting the pattern of income recognition. Classification for both lessees and lessors will be based on an assessment of whether risks and rewards as well as substantive control have been transferred through a lease contract. Public business entities should apply the guidance in ASU No. 2016-02 for annual periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or entered into
after the earliest comparative period presented in the financial statements. We are currently evaluating the provisions of ASU No. 2016-02 and assessing its impact on our financial statements. As part of our assessment to-date, we have formed an implementation team, commenced identification of our lease population and selected a lease software package. We expect the adoption of ASU 2016-02 will materially gross up our consolidated balance sheet with the recognition of the ROU assets and operating lease liabilities. The impact to our consolidated statements of income and cash flows is not expected to be material. The new standard will also require additional disclosures for financing and operating leases.
In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities,” to meet its objective of providing more decision-useful information about financial instruments. The majority of this ASU’s provisions amend only the presentation or disclosures of financial instruments; however, one provision will also affect net income. Equity investments carried under the cost method or lower of cost or fair value method of accounting, in accordance with current GAAP, will have to be carried at fair value upon adoption of ASU No. 2016-01, with changes in fair value recorded in net income. For equity investments that do not have readily determinable fair values, a company may elect to carry such investments at cost less impairments, if any, adjusted up or down for price changes in similar financial instruments issued by the investee, when and if observed. Public business entities should apply the guidance in ASU No. 2016-01 for annual periods beginning after December 15, 2017, and interim periods within those annual periods, with early adoption prohibited. We are currently evaluating the provisions of ASU No. 2016-01. Our initial review indicates that ASU No. 2016-01 will have a limited impact on our financial statements.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This ASU and other related updates are intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets and expand disclosure requirements. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The amendment in this ASU defers the effective date of ASU No. 2014-09 for all entities for one year. Public business entities should apply the guidance in ASU No. 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Our assessment work primarily included the formation of an implementation work team, training on the new ASU’s revenue recognition model, contract review and documentation and the monitoring of industry interpretative issues. We adopted the standard on January 1, 2018, using the modified retrospective application. Our evaluation of the new ASU is near completion, which includes understanding the impact of adoption on earnings from equity method investments. Based upon our analysis to-date, the primary impact of adoption of the new standard is the netting of sales-based taxes collected from our customers against revenue. Sales-based taxes include excise taxes on sales of petroleum products as noted on our consolidated statement of income. We have not identified any other material impact on our financial statements other than disclosures.
Note 29—Condensed Consolidating Financial Information
Phillips 66 has $6.0 billion of senior notes outstanding, the payment obligations of which are fully and unconditionally guaranteed by Phillips 66 Company, a 100-percent-owned subsidiary. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:
Phillips 66 and Phillips 66 Company (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).
All other nonguarantor subsidiaries.
The consolidating adjustments necessary to present Phillips 66’s results on a consolidated basis.
This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.
| | | | | | | | | | | | | | | Millions of Dollars | | | Year Ended December 31, 2017 | | Statement of Income | Phillips 66 |
| Phillips 66 Company |
| All Other Subsidiaries |
| Consolidating Adjustments |
| Total Consolidated |
| | Revenues and Other Income | | | | | | | Sales and other operating revenues | $ | — |
| 74,640 |
| 27,714 |
| — |
| 102,354 |
| | Equity in earnings of affiliates | 5,336 |
| 3,256 |
| 559 |
| (7,419 | ) | 1,732 |
| | Net gain on dispositions | — |
| 1 |
| 14 |
| — |
| 15 |
| | Other income | 3 |
| 471 |
| 47 |
| — |
| 521 |
| | Intercompany revenues | — |
| 1,610 |
| 13,457 |
| (15,067 | ) | — |
| | Total Revenues and Other Income | 5,339 |
| 79,978 |
| 41,791 |
| (22,486 | ) | 104,622 |
| | | | | | | | | Costs and Expenses | | | | | | | Purchased crude oil and products | — |
| 63,812 |
| 30,379 |
| (14,782 | ) | 79,409 |
| | Operating expenses | — |
| 3,672 |
| 1,085 |
| (58 | ) | 4,699 |
| | Selling, general and administrative expenses | 7 |
| 1,300 |
| 399 |
| (11 | ) | 1,695 |
| | Depreciation and amortization | — |
| 892 |
| 426 |
| — |
| 1,318 |
| | Impairments | — |
| 20 |
| 4 |
| — |
| 24 |
| | Taxes other than income taxes | — |
| 5,784 |
| 7,678 |
| — |
| 13,462 |
| | Accretion on discounted liabilities | — |
| 17 |
| 5 |
| — |
| 22 |
| | Interest and debt expense | 348 |
| 70 |
| 236 |
| (216 | ) | 438 |
| | Total Costs and Expenses | 355 |
| 75,567 |
| 40,212 |
| (15,067 | ) | 101,067 |
| | Income before income taxes | 4,984 |
| 4,411 |
| 1,579 |
| (7,419 | ) | 3,555 |
| | Income tax benefit | (122 | ) | (925 | ) | (646 | ) | — |
| (1,693 | ) | | Net Income | 5,106 |
| 5,336 |
| 2,225 |
| (7,419 | ) | 5,248 |
| | Less: net income attributable to noncontrolling interests | — |
| — |
| 142 |
| — |
| 142 |
| | Net Income Attributable to Phillips 66 | $ | 5,106 |
| 5,336 |
| 2,083 |
| (7,419 | ) | 5,106 |
| | | | | | |
| | Comprehensive Income | $ | 5,484 |
| 5,714 |
| 2,498 |
| (8,070 | ) | 5,626 |
|
| | | | | | | | | | | | | | | Millions of Dollars | | | Year Ended December 31, 2016 | | Statement of Income | Phillips 66 |
| Phillips 66 Company |
| All Other Subsidiaries |
| Consolidating Adjustments |
| Total Consolidated |
| | Revenues and Other Income | | | | | | | Sales and other operating revenues | $ | — |
| 58,822 |
| 25,457 |
| — |
| 84,279 |
| | Equity in earnings of affiliates | 1,797 |
| 1,839 |
| 296 |
| (2,518 | ) | 1,414 |
| | Net gain (loss) on dispositions | — |
| (9 | ) | 19 |
| — |
| 10 |
| | Other income | — |
| 42 |
| 32 |
| — |
| 74 |
| | Intercompany revenues | — |
| 864 |
| 9,160 |
| (10,024 | ) | — |
| | Total Revenues and Other Income | 1,797 |
| 61,558 |
| 34,964 |
| (12,542 | ) | 85,777 |
| | | | | | | | | Costs and Expenses | | | | | | | Purchased crude oil and products | — |
| 48,171 |
| 24,102 |
| (9,805 | ) | 62,468 |
| | Operating expenses | — |
| 3,465 |
| 846 |
| (36 | ) | 4,275 |
| | Selling, general and administrative expenses | 6 |
| 1,236 |
| 406 |
| (10 | ) | 1,638 |
| | Depreciation and amortization | — |
| 821 |
| 347 |
| — |
| 1,168 |
| | Impairments | — |
| 1 |
| 4 |
| — |
| 5 |
| | Taxes other than income taxes | — |
| 5,477 |
| 8,211 |
| — |
| 13,688 |
| | Accretion on discounted liabilities | — |
| 16 |
| 5 |
| — |
| 21 |
| | Interest and debt expense | 366 |
| 21 |
| 124 |
| (173 | ) | 338 |
| | Foreign currency transaction gains | — |
| — |
| (15 | ) | — |
| (15 | ) | | Total Costs and Expenses | 372 |
| 59,208 |
| 34,030 |
| (10,024 | ) | 83,586 |
| | Income before income taxes | 1,425 |
| 2,350 |
| 934 |
| (2,518 | ) | 2,191 |
| | Income tax expense (benefit) | (130 | ) | 553 |
| 124 |
| — |
| 547 |
| | Net Income | 1,555 |
| 1,797 |
| 810 |
| (2,518 | ) | 1,644 |
| | Less: net income attributable to noncontrolling interests | — |
| — |
| 89 |
| — |
| 89 |
| | Net Income Attributable to Phillips 66 | $ | 1,555 |
| 1,797 |
| 721 |
| (2,518 | ) | 1,555 |
| | | | | | | | | Comprehensive Income | $ | 1,213 |
| 1,455 |
| 451 |
| (1,817 | ) | 1,302 |
|
| | | | | | | | | | | | | | | Millions of Dollars | | | Year Ended December 31, 2015 | | Statement of Income | Phillips 66 |
| Phillips 66 Company |
| All Other Subsidiaries |
| Consolidating Adjustments |
| Total Consolidated |
| | Revenues and Other Income | | | | | | | Sales and other operating revenues | $ | — |
| 68,478 |
| 30,497 |
| — |
| 98,975 |
| | Equity in earnings (losses) of affiliates | 4,470 |
| 2,812 |
| (134 | ) | (5,575 | ) | 1,573 |
| | Net gain (loss) on dispositions | — |
| (115 | ) | 398 |
| — |
| 283 |
| | Other income | — |
| 81 |
| 37 |
| — |
| 118 |
| | Intercompany revenues | — |
| 1,071 |
| 9,845 |
| (10,916 | ) | — |
| | Total Revenues and Other Income | 4,470 |
| 72,327 |
| 40,643 |
| (16,491 | ) | 100,949 |
| | | | | | | | | Costs and Expenses | | | | | | | Purchased crude oil and products | — |
| 54,925 |
| 29,221 |
| (10,747 | ) | 73,399 |
| | Operating expenses | 4 |
| 3,412 |
| 917 |
| (39 | ) | 4,294 |
| | Selling, general and administrative expenses | 5 |
| 1,265 |
| 416 |
| (16 | ) | 1,670 |
| | Depreciation and amortization | — |
| 818 |
| 260 |
| — |
| 1,078 |
| | Impairments | — |
| 4 |
| 3 |
| — |
| 7 |
| | Taxes other than income taxes | — |
| 5,505 |
| 8,572 |
| — |
| 14,077 |
| | Accretion on discounted liabilities | — |
| 16 |
| 5 |
| — |
| 21 |
| | Interest and debt expense | 365 |
| 25 |
| 34 |
| (114 | ) | 310 |
| | Foreign currency transaction losses | — |
| 1 |
| 48 |
| — |
| 49 |
| | Total Costs and Expenses | 374 |
| 65,971 |
| 39,476 |
| (10,916 | ) | 94,905 |
| | Income before income taxes | 4,096 |
| 6,356 |
| 1,167 |
| (5,575 | ) | 6,044 |
| | Income tax expense (benefit) | (131 | ) | 1,886 |
| 9 |
| — |
| 1,764 |
| | Net Income | 4,227 |
| 4,470 |
| 1,158 |
| (5,575 | ) | 4,280 |
| | Less: net income attributable to noncontrolling interests | — |
| — |
| 53 |
| — |
| 53 |
| | Net Income Attributable to Phillips 66 | $ | 4,227 |
| 4,470 |
| 1,105 |
| (5,575 | ) | 4,227 |
| | | | | | | | | Comprehensive Income | $ | 4,105 |
| 4,348 |
| 1,032 |
| (5,327 | ) | 4,158 |
|
| | | | | | | | | | | | | | | Millions of Dollars | | | At December 31, 2017 | | Balance Sheet | Phillips 66 |
| Phillips 66 Company |
| All Other Subsidiaries |
| Consolidating Adjustments |
| Total Consolidated |
| | Assets | | | | | | | Cash and cash equivalents | $ | — |
| 1,411 |
| 1,708 |
| — |
| 3,119 |
| | Accounts and notes receivable | 10 |
| 5,317 |
| 4,476 |
| (2,297 | ) | 7,506 |
| | Inventories | — |
| 2,386 |
| 1,009 |
| — |
| 3,395 |
| | Prepaid expenses and other current assets | 2 |
| 276 |
| 92 |
| — |
| 370 |
| | Total Current Assets | 12 |
| 9,390 |
| 7,285 |
| (2,297 | ) | 14,390 |
| | Investments and long-term receivables | 32,125 |
| 23,483 |
| 9,959 |
| (51,626 | ) | 13,941 |
| | Net properties, plants and equipment | — |
| 13,117 |
| 8,343 |
| — |
| 21,460 |
| | Goodwill | — |
| 2,853 |
| 417 |
| — |
| 3,270 |
| | Intangibles | — |
| 722 |
| 154 |
| — |
| 876 |
| | Other assets | 12 |
| 266 |
| 158 |
| (2 | ) | 434 |
| | Total Assets | $ | 32,149 |
| 49,831 |
| 26,316 |
| (53,925 | ) | 54,371 |
| | | | | | | | | Liabilities and Equity | | | | | | | Accounts payable | $ | — |
| 7,272 |
| 3,052 |
| (2,297 | ) | 8,027 |
| | Short-term debt | — |
| 9 |
| 32 |
| — |
| 41 |
| | Accrued income and other taxes | — |
| 451 |
| 551 |
| — |
| 1,002 |
| | Employee benefit obligations | — |
| 513 |
| 69 |
| — |
| 582 |
| | Other accruals | 55 |
| 298 |
| 102 |
| — |
| 455 |
| | Total Current Liabilities | 55 |
| 8,543 |
| 3,806 |
| (2,297 | ) | 10,107 |
| | Long-term debt | 6,972 |
| 50 |
| 3,047 |
| — |
| 10,069 |
| | Asset retirement obligations and accrued environmental costs | — |
| 467 |
| 174 |
| — |
| 641 |
| | Deferred income taxes | — |
| 3,349 |
| 1,661 |
| (2 | ) | 5,008 |
| | Employee benefit obligations | — |
| 639 |
| 245 |
| — |
| 884 |
| | Other liabilities and deferred credits | 8 |
| 4,700 |
| 3,814 |
| (8,288 | ) | 234 |
| | Total Liabilities | 7,035 |
| 17,748 |
| 12,747 |
| (10,587 | ) | 26,943 |
| | Common stock | 9,396 |
| 24,952 |
| 10,125 |
| (35,077 | ) | 9,396 |
| | Retained earnings | 16,335 |
| 7,748 |
| 1,306 |
| (9,083 | ) | 16,306 |
| | Accumulated other comprehensive loss | (617 | ) | (617 | ) | (205 | ) | 822 |
| (617 | ) | | Noncontrolling interests | — |
| — |
| 2,343 |
| — |
| 2,343 |
| | Total Liabilities and Equity | $ | 32,149 |
| 49,831 |
| 26,316 |
| (53,925 | ) | 54,371 |
|
| | | | | | | | | | | | | | | Millions of Dollars | | | At December 31, 2016 | | Balance Sheet | Phillips 66 |
| Phillips 66 Company |
| All Other Subsidiaries |
| Consolidating Adjustments |
| Total Consolidated |
| | Assets | | | | | | | Cash and cash equivalents | $ | — |
| 854 |
| 1,857 |
| — |
| 2,711 |
| | Accounts and notes receivable | 13 |
| 4,336 |
| 3,276 |
| (1,228 | ) | 6,397 |
| | Inventories | — |
| 2,198 |
| 952 |
| — |
| 3,150 |
| | Prepaid expenses and other current assets | 2 |
| 317 |
| 103 |
| — |
| 422 |
| | Total Current Assets | 15 |
| 7,705 |
| 6,188 |
| (1,228 | ) | 12,680 |
| | Investments and long-term receivables | 31,165 |
| 22,733 |
| 8,588 |
| (48,952 | ) | 13,534 |
| | Net properties, plants and equipment | — |
| 13,044 |
| 7,811 |
| — |
| 20,855 |
| | Goodwill | — |
| 2,853 |
| 417 |
| — |
| 3,270 |
| | Intangibles | — |
| 719 |
| 169 |
| — |
| 888 |
| | Other assets | 15 |
| 245 |
| 168 |
| (2 | ) | 426 |
| | Total Assets | $ | 31,195 |
| 47,299 |
| 23,341 |
| (50,182 | ) | 51,653 |
| | | | | | | | | Liabilities and Equity | | | | | | | Accounts payable | $ | — |
| 5,626 |
| 2,663 |
| (1,228 | ) | 7,061 |
| | Short-term debt | 500 |
| 30 |
| 20 |
| — |
| 550 |
| | Accrued income and other taxes | — |
| 348 |
| 457 |
| — |
| 805 |
| | Employee benefit obligations | — |
| 475 |
| 52 |
| — |
| 527 |
| | Other accruals | 59 |
| 371 |
| 90 |
| — |
| 520 |
| | Total Current Liabilities | 559 |
| 6,850 |
| 3,282 |
| (1,228 | ) | 9,463 |
| | Long-term debt | 6,920 |
| 150 |
| 2,518 |
| — |
| 9,588 |
| | Asset retirement obligations and accrued environmental costs | — |
| 501 |
| 154 |
| — |
| 655 |
| | Deferred income taxes | — |
| 4,391 |
| 2,354 |
| (2 | ) | 6,743 |
| | Employee benefit obligations | — |
| 948 |
| 268 |
| — |
| 1,216 |
| | Other liabilities and deferred credits | 1,297 |
| 3,337 |
| 4,060 |
| (8,431 | ) | 263 |
| | Total Liabilities | 8,776 |
| 16,177 |
| 12,636 |
| (9,661 | ) | 27,928 |
| | Common stock | 10,777 |
| 25,403 |
| 10,117 |
| (35,520 | ) | 10,777 |
| | Retained earnings | 12,637 |
| 6,714 |
| (269 | ) | (6,474 | ) | 12,608 |
| | Accumulated other comprehensive loss | (995 | ) | (995 | ) | (478 | ) | 1,473 |
| (995 | ) | | Noncontrolling interests | — |
| — |
| 1,335 |
| — |
| 1,335 |
| | Total Liabilities and Equity | $ | 31,195 |
| 47,299 |
| 23,341 |
| (50,182 | ) | 51,653 |
|
| | | | | | | | | | | | | | | Millions of Dollars | | | Year Ended December 31, 2017 | | Statement of Cash Flows | Phillips 66 |
| Phillips 66 Company |
| All Other Subsidiaries |
| Consolidating Adjustments |
| Total Consolidated |
| | Cash Flows From Operating Activities | | | | | | | Net Cash Provided by Operating Activities | $ | 2,619 |
| 2,702 |
| 1,747 |
| (3,420 | ) | 3,648 |
| | | | | | | | | Cash Flows From Investing Activities | | | | | | | Capital expenditures and investments* | — |
| (1,133 | ) | (839 | ) | 140 |
| (1,832 | ) | | Proceeds from asset dispositions** | — |
| 265 |
| 84 |
| (263 | ) | 86 |
| | Intercompany lending activities | 401 |
| 1,453 |
| (1,854 | ) | — |
| — |
| | Advances/loans—related parties | — |
| (10 | ) | — |
| — |
| (10 | ) | | Collection of advances/loans—related parties | — |
| 75 |
| 251 |
| — |
| 326 |
| | Restricted cash received from consolidation of business | — |
| — |
| 318 |
| — |
| 318 |
| | Other | — |
| (26 | ) | (8 | ) | — |
| (34 | ) | | Net Cash Provided by (Used in) Investing Activities | 401 |
| 624 |
| (2,048 | ) | (123 | ) | (1,146 | ) | | | | | | | | | Cash Flows From Financing Activities | | | | | | | Issuance of debt | 1,500 |
| — |
| 2,008 |
| — |
| 3,508 |
| | Repayment of debt | (1,500 | ) | (17 | ) | (2,161 | ) | — |
| (3,678 | ) | | Issuance of common stock | 35 |
| — |
| — |
| — |
| 35 |
| | Repurchase of common stock | (1,590 | ) | — |
| — |
| — |
| (1,590 | ) | | Dividends paid on common stock | (1,395 | ) | (2,752 | ) | (668 | ) | 3,420 |
| (1,395 | ) | | Distributions to noncontrolling interests | — |
| — |
| (120 | ) | — |
| (120 | ) | | Net proceeds from issuance of Phillips 66 Partners LP common and preferred units | — |
| — |
| 1,205 |
| — |
| 1,205 |
| | Other* | (70 | ) | — |
| (129 | ) | 123 |
| (76 | ) | | Net Cash Provided by (Used in) Financing Activities | (3,020 | ) | (2,769 | ) | 135 |
| 3,543 |
| (2,111 | ) | | | | | | | | | Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash | — |
| — |
| 17 |
| — |
| 17 |
| | | | | | | | | Net Change in Cash, Cash Equivalents and Restricted Cash | — |
| 557 |
| (149 | ) | — |
| 408 |
| | Cash, cash equivalents and restricted cash at beginning of period | — |
| 854 |
| 1,857 |
| — |
| 2,711 |
| | Cash, Cash Equivalents and Restricted Cash at End of Period | $ | — |
| 1,411 |
| 1,708 |
| — |
| 3,119 |
| | * Includes intercompany capital contributions. | | ** Includes return of investments in equity affiliates. |
| | | | | | | | | | | | | | | Millions of Dollars | | | Year Ended December 31, 2016 | | Statement of Cash Flows | Phillips 66 |
| Phillips 66 Company |
| All Other Subsidiaries* |
| Consolidating Adjustments |
| Total Consolidated |
| | Cash Flows From Operating Activities | | | | | | | Net Cash Provided by Operating Activities | $ | 3,491 |
| 2,307 |
| 1,552 |
| (4,387 | ) | 2,963 |
| | | | | | | | | Cash Flows From Investing Activities | | | | | | | Capital expenditures and investments** | — |
| (1,425 | ) | (1,457 | ) | 38 |
| (2,844 | ) | | Proceeds from asset dispositions*** | — |
| 1,007 |
| 156 |
| (1,007 | ) | 156 |
| | Intercompany lending activities | (1,139 | ) | 2,046 |
| (907 | ) | — |
| — |
| | Advances/loans—related parties | — |
| (75 | ) | (357 | ) | — |
| (432 | ) | | Collection of advances/loans—related parties | — |
| — |
| 108 |
| — |
| 108 |
| | Other | — |
| 18 |
| (164 | ) | — |
| (146 | ) | | Net Cash Provided by (Used in) Investing Activities | (1,139 | ) | 1,571 |
| (2,621 | ) | (969 | ) | (3,158 | ) | | | | | | | | | Cash Flows From Financing Activities | | | | | | | Issuance of debt | — |
| — |
| 2,090 |
| — |
| 2,090 |
| | Repayment of debt | — |
| (26 | ) | (807 | ) | — |
| (833 | ) | | Issuance of common stock | 34 |
| — |
| — |
| — |
| 34 |
| | Repurchase of common stock | (1,042 | ) | — |
| — |
| — |
| (1,042 | ) | | Dividends paid on common stock | (1,282 | ) | (3,604 | ) | (783 | ) | 4,387 |
| (1,282 | ) | | Distributions to noncontrolling interests | — |
| — |
| (75 | ) | — |
| (75 | ) | | Net proceeds from issuance of Phillips 66 Partners LP common units | — |
| — |
| 972 |
| — |
| 972 |
| | Other** | (62 | ) | 31 |
| (980 | ) | 969 |
| (42 | ) | | Net Cash Provided by (Used in) Financing Activities | (2,352 | ) | (3,599 | ) | 417 |
| 5,356 |
| (178 | ) | | | | | | | | | Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash | — |
| — |
| 10 |
| — |
| 10 |
| | | | | | | | | Net Change in Cash, Cash Equivalents and Restricted Cash | — |
| 279 |
| (642 | ) | — |
| (363 | ) | | Cash, cash equivalents and restricted cash at beginning of period | — |
| 575 |
| 2,499 |
| — |
| 3,074 |
| | Cash, Cash Equivalents and Restricted Cash at End of Period | $ | — |
| 854 |
| 1,857 |
| — |
| 2,711 |
| | * Revised to eliminate a purchase and sale transaction between two entities consolidated within the column. This revision increased net cash provided by operating activities by $1,049 million, with an offsetting decrease of $1,049 million in net cash provided by financing activities. The revision did not impact any issuer or guarantor column, nor did it impact our consolidated cash flows. | | ** Includes intercompany capital contributions. | | *** Includes return of investments in equity affiliates. |
| | | | | | | | | | | | | | | Millions of Dollars | | | Year Ended December 31, 2015 | | Statement of Cash Flows | Phillips 66 |
| Phillips 66 Company |
| All Other Subsidiaries |
| Consolidating Adjustments |
| Total Consolidated |
| | Cash Flows From Operating Activities | | | | | | | Net Cash Provided by Operating Activities | $ | 1,060 |
| 4,879 |
| 2,564 |
| (2,790 | ) | 5,713 |
| | | | | | | | | Cash Flows From Investing Activities | | | | | | | Capital expenditures and investments* | — |
| (2,815 | ) | (5,283 | ) | 2,334 |
| (5,764 | ) | | Proceeds from asset dispositions** | — |
| 774 |
| 178 |
| (882 | ) | 70 |
| | Intercompany lending activities | 2,461 |
| (3,153 | ) | 692 |
| — |
| — |
| | Advances/loans—related parties | — |
| (50 | ) | — |
| — |
| (50 | ) | | Collection of advances/loans—related parties | — |
| 50 |
| — |
| — |
| 50 |
| | Other | — |
| 6 |
| (50 | ) | — |
| (44 | ) | | Net Cash Provided by (Used in) Investing Activities | 2,461 |
| (5,188 | ) | (4,463 | ) | 1,452 |
| (5,738 | ) | | | | | | | | | Cash Flows From Financing Activities | | | | | | | Issuance of debt | — |
| — |
| 1,169 |
| — |
| 1,169 |
| | Repayment of debt | (800 | ) | (23 | ) | (103 | ) | — |
| (926 | ) | | Issuance of common stock | 31 |
| — |
| — |
| — |
| 31 |
| | Repurchase of common stock | (1,512 | ) | — |
| — |
| — |
| (1,512 | ) | | Dividends paid on common stock | (1,172 | ) | (1,172 | ) | (1,576 | ) | 2,748 |
| (1,172 | ) | | Distributions to controlling interests | — |
| — |
| (186 | ) | 186 |
| — |
| | Distributions to noncontrolling interests | — |
| — |
| (46 | ) | — |
| (46 | ) | | Net proceeds from issuance of Phillips 66 Partners LP common units | — |
| — |
| 384 |
| — |
| 384 |
| | Other* | (68 | ) | 34 |
| 1,585 |
| (1,596 | ) | (45 | ) | | Net Cash Provided by (Used in) Financing Activities | (3,521 | ) | (1,161 | ) | 1,227 |
| 1,338 |
| (2,117 | ) | | | | | | | | | Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash | — |
| — |
| 9 |
| — |
| 9 |
| | | | | | | | | Net Change in Cash, Cash Equivalents and Restricted Cash | — |
| (1,470 | ) | (663 | ) | — |
| (2,133 | ) | | Cash, cash equivalents and restricted cash at beginning of period | — |
| 2,045 |
| 3,162 |
| — |
| 5,207 |
| | Cash, Cash Equivalents and Restricted Cash at End of Period | $ | — |
| 575 |
| 2,499 |
| — |
| 3,074 |
| | * Includes intercompany capital contributions. | | ** Includes return of investments in equity affiliates. |
Note 30—Subsequent Event
On February 13, 2018, we entered into a Stock Purchase and Sale Agreement (Purchase Agreement) with Berkshire Hathaway Inc. and National Indemnity Company, a wholly owned subsidiary of Berkshire Hathaway, to repurchase 35 million shares of Phillips 66 common stock for an aggregate purchase price of approximately $3.3 billion. Pursuant to the Purchase Agreement, the purchase price per share of $93.725 was based on the volume-weighted-average price of our common stock on the New York Stock Exchange on February 13, 2018. The transaction closed on February 14, 2018. We funded the repurchase with cash on hand of approximately $1.9 billion and borrowings of approximately $1.4 billion under our commercial paper program. This specific share repurchase transaction was separately authorized by our Board of Directors and therefore does not impact previously announced authorizations which total up to $12.0 billion.
| | | | | | Selected Quarterly Financial Data (Unaudited) |
| | | | | | | | | | | | | | | | | | Millions of Dollars | | Per Share of Common Stock | | | Sales and Other Operating Revenues* |
| Income Before Income Taxes |
| Net Income |
| Net Income Attributable to Phillips 66 |
| | Net Income Attributable to Phillips 66 | | | | Basic |
| Diluted |
| | 2017 | | | | | | | | | First | $ | 22,894 |
| 797 |
| 563 |
| 535 |
| | 1.02 |
| 1.02 |
| | Second | 24,087 |
| 848 |
| 581 |
| 550 |
| | 1.06 |
| 1.06 |
| | Third | 25,627 |
| 1,256 |
| 849 |
| 823 |
| | 1.60 |
| 1.60 |
| | Fourth** | 29,746 |
| 654 |
| 3,255 |
| 3,198 |
| | 6.29 |
| 6.25 |
| | | | | | | | | | | 2016 | | | | | | | | | First | $ | 17,409 |
| 596 |
| 398 |
| 385 |
| | 0.72 |
| 0.72 |
| | Second | 21,849 |
| 720 |
| 516 |
| 496 |
| | 0.94 |
| 0.93 |
| | Third | 21,624 |
| 813 |
| 536 |
| 511 |
| | 0.97 |
| 0.96 |
| | Fourth | 23,397 |
| 62 |
| 194 |
| 163 |
| | 0.31 |
| 0.31 |
|
* Includes excise taxes on sales of petroleum products.
** Includes a $2,721 million provisional income tax benefit from the enactment of the U.S. Tax Cuts and Jobs Act on December 22, 2017.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Item 9A. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of December 31, 2017,2023, with the participation of management, our ChairmanPresident and Chief Executive Officer and our Executive Vice President Finance and Chief Financial Officer carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our ChairmanPresident and Chief Executive Officer and our Executive Vice President Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of December 31, 2017.2023.
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, 2017,2023, 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.
Item 9B. OTHER INFORMATION
None.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).
Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
PART III
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 for therelating to our 2024 Annual Meeting of Stockholders to be held on May 9, 2018,15, 2024, which will be filed within 120 days after December 31, 2017 (20182023 (2024 Definitive Proxy Statement).*
Item 11. EXECUTIVE COMPENSATION
The information required by Item 11 of Part III is incorporated herein by reference from our 20182024 Definitive Proxy Statement.*
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by Item 12 of Part III is incorporated herein by reference from our 20182024 Definitive Proxy Statement.*
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Item 13 of Part III is incorporated herein by reference from our 20182024 Definitive Proxy Statement.*
Item 14. PRINCIPAL ACCOUNTINGACCOUNTANT FEES AND SERVICES
The information required by Item 14 of Part III is incorporated herein by reference from our 20182024 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 20182024 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
Item 15. EXHIBITS,EXHIBIT AND FINANCIAL STATEMENT SCHEDULES
| | | | | | | | | | (a) | | | (a) | 1. | Financial Statements and Supplementary Data The financial statements and supplementary information listed in the Index to Financial Statements, which appears on page 70,83, 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 138164 to 141,170, are filed as part of this Annual Report on Form 10-K. | | | | (c) | | Pursuant to Rule 3-09 of Regulation S-X, the financial statements of Chevron Phillips Chemical Company LLC as of December 31, 2017 and 2016, and for each of the three years ended December 31, 2017, are included as an exhibit to this Annual Report on Form 10-K. |
Item 16. FORM 10-K SUMMARY
None.
PHILLIPS 66
INDEX TO EXHIBITS | | | | | | | | | | | | | Incorporated by Reference | Exhibit Number | | Exhibit Description | Form | Exhibit Number |
| Filing Date | SEC File No. | | | | | | | | | | | | 8-K | 2.1 |
| 05/01/2012 | 001-35349 | | | | | | | | | | | | 8-K | 3.1 |
| 05/01/2012 | 001-35349 | | | | | | | | | | | | 8-K | 3.1 |
| 02/09/2017 | 001-35349 | | | | | | | | | | | Indenture, dated as of March 12, 2012, among Phillips 66, as issuer, Phillips 66 Company, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee, in respect of senior debt securities of Phillips 66. | 10 | 4.3 |
| 04/05/2012 | 001-35349 | | | | | | | | | | | | As permitted by Item 601(b)(4)(iii)(A) of Regulation S-K, the company has not filed with this Annual Report on Form 10-K certain instruments defining the rights of holders of long-term debt of the company and its subsidiaries because the total amount of securities authorized thereunder does not exceed 10 percent of the total assets of the company and its subsidiaries on a consolidated basis. The company agrees to furnish a copy of such agreements to the Commission upon request. | | | | | | | | | | | | | | | | 10 | 4.1 |
| 03/01/2012 | 001-35349 | | | | | | | | | | | | 10-Q | 10.1 |
| 05/01/2014 | 001-35349 | | | | | | | | | | | | 10-K | 10.3 |
| 02/20/2015 | 001-35349 | | | | | | | | | | | | 10-K | 10.4 |
| 02/17/2017 | 001-35349 | | | | | | | | | | | | 10-Q | 10.14 |
| 08/03/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10 | 10.12 |
| 03/01/2012 | 001-35349 | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Incorporated by Reference | | | | | | | | | Exhibit
Number | | Exhibit Description | Form | Exhibit
Number | Filing
Date | SEC
File No. | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 2.1 | | 05/01/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 2.1 | | 10/27/2021 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | Agreement and Plan of Merger, dated January 5, 2023, by and among Phillips 66, Phillips 66 Project Development Inc., Dynamo Merger Sub LLC, DCP Midstream, LP, DCP Midstream GP, LP and DCP Midstream GP, LLC. | 8-K | 2.1 | | 01/06/2023 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 3.1 | | 05/01/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 3.1 | | 12/09/2022 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-K | 4.1 | | 02/21/2020 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | Indenture, dated as of March 12, 2012, among Phillips 66, as issuer, Phillips 66 Company, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee, in respect of senior debt securities of Phillips 66. | 10-12B/A | 4.3 | | 04/05/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-12B/A | 4.4 | | 04/05/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.2 | | 11/17/2014 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.2 | | 11/17/2014 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.3 | | 03/01/2018 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.1 | | 04/09/2020 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.3 | | 04/09/2020 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.3 | | 06/10/2020 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.3 | | 11/18/2020 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.4 | | 11/18/2020 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.2 | | 11/15/2021 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Incorporated by Reference | | | | | | | | | Exhibit
Number | | Exhibit Description | Form | Exhibit
Number | Filing
Date | SEC
File No. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Indenture, dated as of May 5, 2022, among Phillips 66 Company, as issuer, Phillips 66, as guarantor, and U.S. Bank Trust Company, National Association, as trustee, in respect of senior debt securities of Phillips 66 Company. | 8-K | 4.1 | 05/05/2022 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.2 | 05/05/2022 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.3 | 05/05/2022 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.4 | 05/05/2022 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.5 | 05/05/2022 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.6 | 05/05/2022 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.7 | 05/05/2022 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.8 | 05/05/2022 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.2 | 03/29/2023 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.3 | 03/29/2023 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | Registration Rights Agreement, dated as of May 5, 2022, among Phillips 66 Company, as issuer, Phillips 66, as guarantor, and Barclays Capital Inc., J.P. Morgan Securities LLC and RBC Capital Markets, LLC, as dealer managers. | 8-K | 4.9 | 05/05/2022 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.1 | 09/30/2010 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | Third Supplemental Indenture dated as of June 14, 2012 to Indenture dated as of September 30, 2010 between DCP Midstream Operating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee. | 8-K | 4.1 | 06/14/2012 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | Incorporated by Reference | Exhibit
Number | | Exhibit Description | Form | Exhibit
Number |
| Filing
Date | SEC
File No. | | | | | | | | | | | | 10 | 10.13 |
| 03/01/2012 | 001-35349 | | | | | | | | | | | | 10 | 10.14 |
| 03/01/2012 | 001-35349 | | | | | | | | | | | | 10 | 10.15 |
| 03/01/2012 | 001-35349 | | | | | | | | | | | | 10 | 10.16 |
| 03/01/2012 | 001-35349 | | | | | | | | | | | | 10-Q | 10.1 |
| 10/30/2014 | 001-35349 | | | | | | | | | | | | 8-K | 10.1 |
| 05/01/2012 | 001-35349 | | | | | | | | | | | | 8-K | 10.2 |
| 05/01/2012 | 001-35349 | | | | | | | | | | | | 8-K | 10.3 |
| 05/01/2012 | 001-35349 | | | | | | | | | | | | 8-K | 10.4 |
| 05/01/2012 | 001-35349 | | | | | | | | | | | | 10-Q | 10.1 |
| 05/02/2013 | 001-35349 | | | | | | | | | | | | 8-K | 10.5 |
| 05/01/2012 | 001-35349 | | | | | | | | | | | | DEF14A | App. A |
| 03/27/2013 | 001-35349 | | | | | | | | | | | | 10-Q | 10.15 |
| 08/03/2012 | 001-35349 | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Incorporated by Reference | | | | | | | | | Exhibit
Number | | Exhibit Description | Form | Exhibit
Number | Filing
Date | SEC
File No. | | | | | | | | | | | | | | | | | | | | | | | | | | Fifth Supplemental Indenture dated as of March 14, 2013 to Indenture dated as of September 30, 2010 between DCP Midstream Operating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee. | 8-K | 4.3 | 03/14/2013 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | Sixth Supplemental Indenture dated as of March 13, 2014 to Indenture dated as of September 30, 2010 between DCP Midstream Operating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee. | 8-K | 4.3 | 03/14/2014 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Seventh Supplemental Indenture dated as of July 17, 2018 to Indenture dated as of September 30, 2010 between DCP Midstream Operating, LP, as issuer, DCP Midstream, LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee. | 8-K | 4.3 | 07/17/2018 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | Eighth Supplemental Indenture dated as of May 10, 2019 to Indenture dated as of September 30, 2010 between DCP Midstream Operating, LP, as issuer, DCP Midstream, LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee. | 8-K | 4.3 | 05/10/2019 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | Ninth Supplemental Indenture dated as of June 24, 2020 to Indenture dated as of September 30, 2010 between DCP Midstream Operating, LP, as issuer, DCP Midstream, LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee. | 8-K | 4.3 | 06/24/2020 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | Tenth Supplemental Indenture dated as of November 19, 2021 to Indenture dated as of September 20, 2010 between DCP Midstream Operating, LP, as issuer, DCP Midstream, LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee. | 8-K | 4.3 | 11/19/2021 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.1 | 01/06/2017 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.1 | 08/16/2000 | 000-31095 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.3 | 01/06/2017 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.4 | 01/06/2017 | 001-32678 | | | | | | | | |
| | | | | | | | | | | | | Incorporated by Reference | Exhibit
Number | | Exhibit Description | Form | Exhibit
Number |
| Filing
Date | SEC
File No. | | | | | | | | | | | | 10-K | 10.18 |
| 02/22/2013 | 001-35349 | | | | | | | | | | | | 10-Q | 10.1 |
| 07/29/2016 | 001-35349 | | | | | | | | | | | | 10-Q | 10.17 |
| 08/03/2012 | 001-35349 | | | | | | | | | | | | 10-Q | 10.18 |
| 08/03/2012 | 001-35349 | | | | | | | | | | | | 10-Q | 10.19 |
| 08/03/2012 | 001-35349 | | | | | | | | | | | | 10-K | 10.24 |
| 02/22/2013 | 001-35349 | | | | | | | | | | | | 10-Q | 10.20 |
| 08/03/2012 | 001-35349 | | | | | | | | | | | | 10-K | 10.26 |
| 02/22/2013 | 001-35349 | | | | | | | | | | | | 10-K | 10.27 |
| 02/22/2013 | 001-35349 | | | | | | | | | | | | 8-K | 10.1 |
| 11/08/2013 | 001-35349 | | | | | | | | | | | | 10-Q | 10.23 |
| 08/03/2012 | 001-35349 | | | | | | | | | | | | 10-K | 10.29 |
| 02/22/2013 | 001-35349 | | | | | | | | | | | | 10-K | 10.30 |
| 02/22/2013 | 001-35349 |
| | | | | | | | | | 10-K | 10.31 |
| 02/22/2013 | 001-35349 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Incorporated by Reference | | | | | | | | | Exhibit
Number | | Exhibit Description | Form | Exhibit
Number | Filing
Date | SEC
File No. | | | | | | | | | | | | | | | | | | | | | | | | | | Eleventh Supplemental Indenture, dated January 1, 2017, by and between DCP Midstream Operating, LP, DCP Midstream, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank). | 8-K | 4.8 | 01/06/2017 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | Twelfth Supplemental Indenture, dated January 1, 2017, by and among DCP Midstream Operating, LP (as successor to DCP Midstream, LLC (formerly known as Duke Energy Field Services, LLC)), DCP Midstream Partners, LP and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank). | 8-K | 4.9 | 01/06/2017 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.10 | 01/06/2017 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.11 | 01/06/2017 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 4.12 | 01/06/2017 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 10.1 | 06/24/2022 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 10.1 | 03/29/2023 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.14 | 08/03/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-K | 10.6 | 02/23/2018 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.1 | 07/27/2018 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.1 | 04/30/2021 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Incorporated by Reference | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exhibit
Number | | Exhibit Description | Form | Exhibit
Number | Filing
Date | SEC
File No. | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 10.1 | 05/01/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 10.2 | 05/01/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 10.4 | 05/01/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.1 | 05/02/2013 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 10.5 | 05/01/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | DEF14A | App. A | 03/27/2013 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | DEF14A | App. A | 03/31/2022 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.15 | 08/03/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-K | 10.18 | 02/22/2013 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.1 | 07/29/2016 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.17 | 08/03/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.18 | 08/03/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.19 | 08/03/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-K | 10.24 | 02/22/2013 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.20 | 08/03/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-K | 10.26 | 02/22/2013 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.1 | 04/30/2019 | 001-35349 | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Incorporated by Reference | | | | | | | | | Exhibit
Number | | Exhibit Description | Form | Exhibit
Number | Filing
Date | SEC
File No. | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-K | 10.27 | 02/22/2013 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-K | 10.1 | 11/08/2013 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.23 | 08/03/2012 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-K | 10.31 | 02/21/2020 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-K | 10.32 | 02/21/2020 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-K | 10.33 | 02/21/2020 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.2 | 05/04/2023 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.3 | 05/04/2023 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.4 | 05/04/2023 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | | 10-Q | 10.5 | 05/04/2023 | 001-35349 | | | | | | | | | | | | | | | | | | | | | | | | | | Fifth Amendment to Receivables Financing Agreement, dated July 29, 2022, among DCP Receivables LLC, as borrower, DCP Midstream, LP, as initial servicer, the lenders, LC participants and group agents that are parties thereto from time to time, PNC Bank, National Association, as Administrative Agent and LC Bank, and PNC Capital Markets LLC, as Structuring Agent. | 10-Q | 10.1 | 11/03/2022 | 001-32678 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Incorporated by Reference | | | | | | | | | Exhibit
Number | | Exhibit Description | Form | Exhibit
Number |
Filing
Date | Filing
Date | SEC
File No. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 101.INS* | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 101.INS* | | Inline XBRL Instance Document.Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 101.SCH* | | Inline XBRL Schema Document. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 101.CAL* | | Inline XBRL Calculation Linkbase Document. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 101.LAB* | | Inline XBRL Labels Linkbase Document. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 101.PRE* | | Inline XBRL Presentation Linkbase Document. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 101.DEF* | | Inline XBRL Definition Linkbase Document. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 104* | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | | | | | | | | | | | | | | | | | | | | | | | | | | | |
* Filed herewith. ** Management contracts and compensatory plans or arrangements.
*** Furnished herewith.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | | | | | | | PHILLIPS 66 | | | | | | | | | | | Date: | February 21, 2024 | /s/ Mark E. Lashier | | | PHILLIPS 66 | | | | | | | | | | Date: | February 23, 2018 | /s/ Greg C. Garland | | | Greg C. GarlandMark E. Lashier
Chairman of the Board of Directors
President and Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below, as of February 23, 2018,21, 2024, by the following persons on behalf of the registrant and in the capacities indicated.
| | | | | | | | | | Signature | | Title | | | | | Signature | | Title | | | | | | | | | /s/ Greg C. GarlandMark E. Lashier | | Chairman of the Board of Directors | Greg C. Garland | | President and Chief Executive Officer and Director | | Mark E. Lashier | | (Principal executive officer) | | | | | | | | /s/ Kevin J. Mitchell | | Executive Vice President Financeand Chief Financial Officer | | Kevin J. Mitchell | | and Chief Financial Officer | | | (Principal financial officer) | | | | | | | /s/ Chukwuemeka A. OyoluJ. Scott Pruitt | | Vice President and Controller | Chukwuemeka A. OyoluJ. Scott Pruitt | | (Principal accounting officer) | | | |
| | | | | | | | | | | | | | | | /s/ Greg C. Garland | | Executive Chairman of the Board of Directors | | Greg C. Garland | | | | | | | | | | /s/ Gary K. Adams | | Director | | Gary K. Adams | | | | | | | | | | /s/ Julie L. Bushman | | Director | | Julie L. Bushman | | | | | | | | | | /s/ Lisa A. Davis | | Director | | Lisa A. Davis | | | | | | | | | | /s/ Gregory J. Hayes | | Director | | Gregory J. Hayes | | | | | | | | | /s/ J. Brian FergusonCharles M. Holley | | Director | J. Brian FergusonCharles M. Holley | | | | | | | | | /s/ William R. Loomis Jr. | | Director | William R. Loomis Jr. | | | | | | | | | | /s/ John E. Lowe | | Director | | John E. Lowe | | | | | | | | | /s/ Harold W. McGraw III | | Director | Harold W. McGraw III | | | | | | | | | | /s/ Denise L. Ramos | | Director | | Denise L. Ramos | | | | | | | | | | /s/ Denise R. Singleton | | Director | | Denise R. Singleton | | | | | | | | | | /s/ Douglas T. Terreson | | Director | | Douglas T. Terreson | | | | | | | | | | /s/ Glenn F. Tilton | | Director | | Glenn F. Tilton | | | | | | | | | /s/ Victoria J. Tschinkel | | Director | Victoria J. Tschinkel | | | | | | | | | | /s/ Marna C. Whittington | | Director | | Marna C. Whittington | | |
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