PLAINS GP HOLDINGS LP 10-K

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Introduction The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical Consolidated Financial Statements and accompanying notes. Unless the context otherwise requires, references to “we,” “us,” “our,” and “PAGP” are intended to mean the business and operations of PAGP and its consolidated subsidiaries. Our discussion and analysis includes the following: • Executive Summary • Results of Operations • Liquidity and Capital Resources • Critical Accounting Policies and Estimates • Recent Accounting Pronouncements A comparative discussion of our 2022 to 2021 operating results and performance measures can be found in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2022 filed with the SEC on March 1, 2023. Executive Summary Company Overview We are a Delaware limited partnership formed in 2013 that has elected to be taxed as a corporation for United States federal income tax purposes. As of December 31, 2023, our sole cash-generating assets consisted of an approximate 84% limited partner interest in AAP through our ownership of approximately 196.4 million AAP units. We also own a 100% managing member interest in GP LLC. GP LLC is a Delaware limited liability company that holds the non-economic general partner interest in AAP. AAP is a Delaware limited partnership that, as of December 31, 2023, directly owned a limited partner interest in PAA through its ownership of approximately 232.7 million PAA common units (approximately 30% of PAA’s total outstanding common units and Series A preferred units combined). AAP is the sole member of PAA GP, a Delaware limited liability company that directly holds the non-economic general partner interest in PAA. PAA’s business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest midstream service providers in North America, PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. PAA’s assets and the services it provides are primarily focused on crude oil and NGL. Market Overview and Outlook Crude oil and other petroleum liquids are supplied to the global market by producers around the world, with the majority coming from the Organization of Petroleum Exporting Countries (“OPEC”), North American producers and the Russian Federation, among others. The chart below depicts the relationship between global supply of crude oil and other petroleum liquids and demand since the beginning of 2019 and the U.S. Energy Information Administration’s (“EIA”) Short-Term Energy Outlook as of January 2024: 71 Table of Contents Index to Financial Statements World Liquid Fuels Production and Consumption Balance (1) (in millions of barrels per day) (1) Barrels produced and consumed per quarter. We believe that the combination of population growth and progressively improving living standards for non-OECD (Organization for Economic Cooperation and Development) countries underpins increasing energy demand globally for decades to come. We believe reliable, affordable, and responsible energy resources are all critical components to maintain energy security and global stability, requiring all sources of energy including both hydrocarbons and renewables. Consistent with the forecast from the EIA’s Short-Term Energy Outlook (as depicted in the chart above), we expect crude oil demand to continue to increase, driven largely by our view that hydrocarbon-based fuels are the most efficient fuels for the transportation of people and goods, and hydrocarbon-based products provide the building blocks for modern civilization such as fertilizers, plastics and cement. North America has proven to be an essential and reliable source of crude oil and NGL production growth for the global market. This is driven by the lifting of the U.S. crude oil export ban, infrastructure debottlenecking in both the U.S. and Canada, and world-class geological formations unlocked through technological improvements and techniques. The Permian Basin continues to be one of the most prolific basins in the world and was the predominant driver of U.S. production growth in 2023. The remainder of the U.S. unconventional plays continue to see modest growth. We expect the Permian Basin to be a key contributor to global supply for years to come, based on strong economics and the recent wave of consolidation leading to more stable activity levels over a wide range of commodity price environments. It is against this macro energy market backdrop that we expect to generate significant positive free cash flow on a multi-year basis, supported by our existing asset base and integrated business model. Our financial strategy and long-term capital allocation framework is focused on generating meaningful multi-year free cash flow and improving shareholder returns by (i) increasing returns of capital to equity holders, primarily through increased distributions, (ii) making disciplined accretive investments and (iii) maintaining an investment grade credit profile and ensuring balance sheet flexibility. 72 Table of Contents Index to Financial Statements Overview of Operating Results We recognized net income of $1.425 billion for the year ended December 31, 2023 compared to net income of $1.163 billion for the year ended December 31, 2022. Our results include the benefit of higher tariff volumes and tariff escalations on our crude oil pipelines in 2023, as well as the impact of acquisitions. In addition, the 2022 comparative period includes higher costs from the increase in the accrual for estimated costs associated with the Line 901 incident. Additionally, net income for 2023 includes favorable impacts from gains on asset sales and the mark-to-market adjustment of the Preferred Distribution Rate Reset Option compared to losses in the 2022 period, which were partially offset by the benefit to the 2022 period of a gain recognized associated with the remeasurement of our previously held 65% interest in Cactus II to fair value in connection with our acquisition of an additional 5% interest in Cactus II in November 2022. See the “—Results of Operations” section below for further discussion. Results of Operations Consolidated Results The following table sets forth an overview of our consolidated financial results calculated in accordance with GAAP (in millions, except per share data): Year Ended December 31, Variance 2023 2022 $ % Product sales revenues $ 46,974 $ 55,948 $ (8,974) (16) % Services revenues 1,738 1,394 344 25 % Purchases and related costs (44,531) (53,176) 8,645 16 % Field operating costs (1,425) (1,315) (110) (8) % General and administrative expenses (356) (330) (26) (8) % Depreciation and amortization (1,051) (968) (83) (9) % Gains/(losses) on asset sales and asset impairments, net 152 (269) 421 157 % Equity earnings in unconsolidated entities 369 403 (34) (8) % Gains/(losses) on investments in unconsolidated entities, net 28 346 (318) (92) % Interest expense, net (386) (405) 19 5 % Other income/(expense), net 102 (219) 321 147 % Income tax expense (189) (246) 57 23 % Net income 1,425 1,163 262 23 % Net income attributable to noncontrolling interests (1,227) (995) (232) (23) % Net income attributable to PAGP $ 198 $ 168 $ 30 18 % Basic and diluted net income per Class A share $ 1.01 $ 0.86 $ 0.15 ** Basic and diluted weighted average Class A shares outstanding 195 194 1 ** ** Indicates that variance as a percentage is not meaningful. Revenues and Purchases Fluctuations in our consolidated revenues and purchases and related costs are primarily associated with our merchant activities and generally explained in large part by changes in commodity prices. Our crude oil and NGL merchant activities are not directly affected by the absolute level of prices because the commodities that we buy and sell are generally indexed to the same pricing indices. Both product sales revenues and purchases and related costs will fluctuate with market prices; however, the absolute margins related to those sales and purchases will not necessarily have a corresponding increase or decrease. Additionally, product sales revenues include the impact of gains and losses related to derivative instruments used to manage our exposure to commodity price risk associated with such sales and purchases. 73 Table of Contents Index to Financial Statements A majority of our sales and purchases are indexed to West Texas Intermediate (“WTI”). The following table presents the range of the NYMEX WTI benchmark price of crude oil over the last two years (in dollars per barrel): NYMEX WTI Crude Oil Price During the Year Ended December 31, Low High Average 2023 $ 67 $ 94 $ 78 2022 $ 71 $ 124 $ 94 Product sales revenues and purchases decreased for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to lower commodity prices in 2023. The impact of fluctuations of derivative mark-to-market valuations also resulted in lower product sales revenues in 2023 compared to 2022. Revenues from services increased for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to higher volumes and tariff escalations in 2023, as well as the impact of acquisitions, partially offset by the impact of lower commodity prices in 2023. See further discussion of net revenues (revenues less purchases and related costs) in the “—Analysis of Operating Segments” section below. Field Operating Costs See discussion of field operating costs in the “—Analysis of Operating Segments” section below. General and Administrative Expenses The increase in general and administrative expenses for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to (i) higher employee-related costs, including an increase in equity-indexed compensation expense (a portion of which is excluded in the calculation of Adjusted EBITDA and Segment Adjusted EBITDA) due to a higher PAA common unit price and higher number of outstanding units assumed probable of vesting and (ii) higher information systems costs due to ongoing systems integration work, partially offset by (iii) decreases across several categories. Depreciation and Amortization Depreciation and amortization expense increased for the year ended December 31, 2023 compared to the year ended December 31, 2022 largely driven by acquisitions, including an additional interest in Cactus II and the remaining 43% in OMOG. See Note 7 to our Consolidated Financial Statements for additional information. Gains/(Losses) on Asset Sales and Asset Impairments, Net The net gain on asset sales and asset impairments for the year ended December 31, 2023 was primarily comprised of a gain of approximately $140 million related to the sale of our Keyera Fort Saskatchewan facility in the first quarter of 2023. The net loss on asset sales and asset impairments for 2022 was primarily comprised of (i) a $330 million non-cash impairment charge recognized in the fourth quarter of 2022 related to certain crude oil assets in California, partially offset by (ii) gains recognized from the sale of land and related assets in Long Beach, California, as well as Line 901 and the Sisquoc to Pentland portion of Line 903, a portion of which relates to the transfer of an asset retirement obligation to the purchaser. See Note 6 and Note 7 to our Consolidated Financial Statements for additional information regarding these asset sales and asset impairments. Equity Earnings in Unconsolidated Entities See discussion of equity earnings in unconsolidated entities in the “—Analysis of Operating Segments” section below. 74 Table of Contents Index to Financial Statements Gains/(Losses) on Investments in Unconsolidated Entities, Net In the third quarter of 2023, we recognized a gain of $29 million related to the Permian JV’s acquisition of the remaining 43% interest in OMOG. See Note 7 to our Consolidated Financial Statements for additional information regarding this transaction. During the fourth quarter of 2022, we recognized (i) a gain of $370 million associated with the remeasurement of our previously held 65% interest in Cactus II to fair value in connection with our acquisition of an additional 5% interest in Cactus II in November 2022 and (ii) a loss of $25 million associated with the difference between the fair value and historical book value of assets contributed by the Permian JV in exchange for an additional interest in OMOG. See Note 7 and Note 8 to our Consolidated Financial Statements for additional information regarding these transactions. Interest Expense, Net The decrease in interest expense for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to a lower weighted average debt balance during the 2023 period largely driven by the repayment of $750 million of senior notes in March 2022, $400 million of senior notes in January 2023 and $700 million of senior notes in October 2023. See Note 10 to our Consolidated Financial Statements for additional information regarding our debt and related activities during the periods presented. Other Income/(Expense), Net The following table summarizes the components impacting Other income/(expense), net (in millions): Year Ended December 31, 2023 2022 Gain/(loss) on mark-to-market adjustment of Preferred Distribution Rate Reset Option embedded derivative (1) $ 58 $ (189) Net gain/(loss) on foreign currency revaluation (2) 15 (36) Other 29 6 $ 102 $ (219) (1) See Note 12 to our Consolidated Financial Statements for additional information. (2) The activity during the periods presented was primarily related to the impact from the change in the United States Dollar to Canadian dollar exchange rate on the portion of our intercompany net investment that is not long-term in nature. Income Tax (Expense)/Benefit The net favorable income tax variance for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to lower year-over-year income within our Canadian operations as impacted by fluctuations of derivative mark-to-market valuations. The favorable variance was partially offset by the tax impact of the Keyera Fort Saskatchewan divestiture and the impact of higher earnings at PAA on income attributable to PAGP. See Note 7 to our Consolidated Financial Statements for additional information regarding the Keyera Fort Saskatchewan divestiture. 75 Table of Contents Index to Financial Statements Non-GAAP Financial Measures To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. The primary additional measures used by management are Adjusted EBITDA and Adjusted EBITDA attributable to PAA. Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA and Adjusted EBITDA attributable to PAA are reconciled to Net Income, the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our Consolidated Financial Statements and accompanying notes. Performance Measures Adjusted EBITDA is defined as earnings before interest expense, income taxes, depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities), gains and losses on asset sales and asset impairments and gains or losses on investments in unconsolidated entities, adjusted for certain selected items impacting comparability. Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests in consolidated joint venture entities. Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) provide additional information about our core operating performance, (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions and (iii) present measures that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These non-GAAP financial performance measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our core operating results and/or (v) other items that we believe should be excluded in understanding our core operating performance. These measures may further be adjusted to include amounts related to deficiencies associated with minimum volume commitments whereby we have billed the counterparties for their deficiency obligation and such amounts are recognized as deferred revenue in “Other current liabilities” in our Consolidated Financial Statements. We also adjust for amounts billed by our equity method investees related to deficiencies under minimum volume commitments. Such amounts are presented net of applicable amounts subsequently recognized into revenue. We have defined all such items as “selected items impacting comparability.” We do not necessarily consider all of our selected items impacting comparability to be non-recurring, infrequent or unusual, but we believe that an understanding of these selected items impacting comparability is material to the evaluation of our operating results and prospects. Although we present selected items impacting comparability that management considers in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions, divestitures, investment capital projects and numerous other factors as discussed, as applicable, in “—Analysis of Operating Segments.” 76 Table of Contents Index to Financial Statements The following table sets forth the reconciliation of the non-GAAP financial performance measures Adjusted EBITDA and Adjusted EBITDA attributable to PAA from Net Income (in millions): Year Ended December 31, Variance 2023 2022 $ % Net income $ 1,425 $ 1,163 $ 262 23 % Interest expense, net 386 405 (19) (5) % Income tax expense 189 246 (57) (23) % Depreciation and amortization 1,051 968 83 9 % (Gains)/losses on asset sales and asset impairments, net (152) 269 (421) (157) % (Gains)/losses on investments in unconsolidated entities, net (28) (346) 318 92 % Depreciation and amortization of unconsolidated entities (1) 87 85 2 2 % Unallocated general and administrative expenses (2) 6 5 1 20 % Selected Items Impacting Comparability: Derivative activities and inventory valuation adjustments 159 (280) 439 ** Long-term inventory costing adjustments 35 (4) 39 ** Deficiencies under minimum volume commitments, net 12 7 5 ** Equity-indexed compensation expense 36 32 4 ** Foreign currency revaluation 24 4 20 ** Line 901 incident 10 95 (85) ** Transaction-related expenses 1 — 1 ** Selected Items Impacting Comparability - Segment Adjusted EBITDA (3) 277 (146) 423 ** Mark-to-market adjustment of Preferred Distribution Rate Reset Option embedded derivative (4) (58) 189 (247) ** Foreign currency revaluation (5) (16) 37 (53) ** Selected Items Impacting Comparability - Adjusted EBITDA (6) 203 80 123 ** Adjusted EBITDA (6) $ 3,167 $ 2,875 $ 292 10 % Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures (7) (456) (365) (91) (25) % Adjusted EBITDA attributable to PAA $ 2,711 $ 2,510 $ 201 8 % ** Indicates that variance as a percentage is not meaningful. (1) We exclude our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets. (2) Represents general and administrative expenses incremental to those of PAA, which are not allocated to our reporting segments in determining Segment Adjusted EBITDA and are excluded in the non-GAAP financial performance measures utilized by management. (3) For a more detailed discussion of these selected items impacting comparability, see the footnotes to the Segment Adjusted EBITDA Reconciliation table in Note 19 to our Consolidated Financial Statements. (4) The Preferred Distribution Rate Reset Option of PAA’s Series A preferred units was accounted for as an embedded derivative and recorded at fair value in our Consolidated Financial Statements. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability. See Note 12 to our Consolidated Financial Statements for additional information regarding the Preferred Distribution Rate Reset Option. (5) During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability. 77 Table of Contents Index to Financial Statements (6) Other income/(expense), net on our Consolidated Statements of Operations, adjusted for selected items impacting comparability (“Adjusted other income/(expense), net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA. (7) Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River. Analysis of Operating Segments We manage our operations through two operating segments: Crude Oil and NGL. Our CODM (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Adjusted EBITDA, segment volumes and maintenance capital investment. We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus (d) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (e) for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance and (f) to exclude the portion of all preceding items that is attributable to noncontrolling interests in consolidated joint venture entities (“Segment amounts attributable to noncontrolling interests in consolidated joint ventures”). See Note 19 to our Consolidated Financial Statements for a reconciliation of Segment Adjusted EBITDA to Net income attributable to PAGP. In connection with our merchant activities, our Crude Oil and NGL segments may enter into intersegment transactions for the purchase or sale of products, along with services such as the transportation, terminalling or storage of products. Intersegment transactions are conducted at rates similar to those charged to third parties or rates that we believe approximate market. Intersegment activities are eliminated in consolidation and we believe that the estimates with respect to these rates are reasonable. Also, our segment operating and general and administrative expenses reflect direct costs attributable to each segment; however, we also allocate certain operating expenses and general and administrative overhead expenses between segments based on management’s assessment of the business activities for the period. The proportional allocations by segment require judgment by management and may be adjusted in the future based on the business activities that exist during each period. We believe that the estimates with respect to these allocations are reasonable. Revenues and expenses from our Canadian based subsidiaries, which use CAD as their functional currency, are translated at the prevailing average exchange rates for the month. Crude Oil Segment Our Crude Oil segment operations generally consist of gathering and transporting crude oil using pipelines, gathering systems, trucks and at times on barges or railcars, in addition to providing terminalling, storage and other related services utilizing our integrated assets across the United States and Canada. Our assets serve third parties and are also supported by our merchant activities. Our merchant activities include the purchase of crude oil supply and the movement of this supply on our assets or third-party assets to sales locations, including our terminals, third-party connecting carriers, regional hubs or to refineries. Our merchant activities are subject to our risk management policies and may include the use of derivative instruments to manage exposure to commodity price risk and, at times, to provide upside opportunities. Our Crude Oil segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees, month-to-month and multi-year storage and terminalling agreements and the sale of gathered and bulk-purchased crude oil. Tariffs and other fees on our pipeline systems are typically based on volumes transported and vary by receipt point and delivery point. Fees for our terminalling and storage services are based on capacity leases and throughput volumes. Generally, results from our merchant activities are impacted by (i) increases or decreases in our lease gathering crude oil purchases volumes and (ii) volatility in commodity prices, as well as grade and regional differentials and time spreads. The segment results also include the direct fixed and variable field costs of operating the crude oil assets, as well as an allocation of indirect operating costs. 78 Table of Contents Index to Financial Statements The following tables set forth our operating results from our Crude Oil segment: Operating Results (1) (in millions) Year Ended December 31, Variance 2023 2022 $ % Revenues $ 47,174 $ 55,080 $ (7,906) (14) % Purchases and related costs (43,805) (52,088) 8,283 16 % Field operating costs (1,053) (1,003) (50) (5) % Segment general and administrative expenses (2) (271) (250) (21) (8) % Equity earnings in unconsolidated entities 369 403 (34) (8) % Adjustments (3) : Depreciation and amortization of unconsolidated entities 87 85 2 2 % Derivative activities and inventory valuation adjustments 17 (11) 28 ** Long-term inventory costing adjustments 22 (3) 25 ** Deficiencies under minimum volume commitments, net 12 7 5 ** Equity-indexed compensation expense 35 32 3 ** Foreign currency revaluation 19 3 16 ** Line 901 incident 10 95 (85) ** Transaction-related expenses 1 — 1 ** Segment amounts attributable to noncontrolling interests in consolidated joint ventures (454) (364) (90) ** Segment Adjusted EBITDA $ 2,163 $ 1,986 $ 177 9 % Maintenance capital expenditures $ 145 $ 112 $ 33 29 % Average Volumes Year Ended December 31, Variance 2023 2022 Volumes % Crude oil pipeline tariff (by region) (4) Permian Basin (5) 6,356 5,638 718 13 % Other (5) 2,104 1,927 177 9 % Total crude oil pipeline tariff 8,460 7,565 895 12 % Commercial crude oil storage capacity (5) (6) 72 72 — — % Crude oil lease gathering purchases (4) (7) 1,452 1,382 70 5 % ** Indicates that variance as a percentage is not meaningful. (1) Revenues and costs and expenses include intersegment amounts. (2) Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period. (3) Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 19 to our Consolidated Financial Statements for additional discussion of such adjustments. (4) Average daily volumes in thousands of barrels per day calculated as the total volumes (attributable to our interest for assets owned by unconsolidated entities or through undivided joint interests) for the year divided by the number of days in the year. Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period. (5) Includes volumes (attributable to our interest) from assets owned by unconsolidated entities. 79 Table of Contents Index to Financial Statements (6) Average monthly capacity in millions of barrels per day calculated as total volumes for the year divided by the number of months in the year. (7) Of this amount, approximately 1,147 and 1,073 thousand barrels per day were purchased in the Permian Basin for the years ended December 31, 2023 and 2022, respectively. Segment Adjusted EBITDA Crude Oil Segment Adjusted EBITDA increased for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to higher tariff volumes, tariff escalations and contributions from acquisitions. These items were partially offset by fewer market-based opportunities for our merchant activities. The following is a more detailed discussion of the significant factors impacting Segment Adjusted EBITDA for the year ended December 31, 2023 compared to the year ended December 31, 2022. Net Revenues and Equity Earnings. Our results were favorably impacted by (i) higher volumes across our pipeline systems, primarily driven by increased production and new well connections, (ii) tariff escalations and (iii) contributions from acquisitions. These benefits were partially offset by the impact of minimum volume commitment deficiency payments received in 2022. Additionally, our results for the year ended December 31, 2023 reflect net fewer market-based opportunities compared to 2022 as the 2022 period includes the benefit of the sale of excess linefill and inventory in a higher crude oil price environment. Field Operating Costs. For the year ended December 31, 2023 compared to the year ended December 31, 2022, we had higher expenses associated with (i) utilities costs due to a combination of higher volumes and prices and an increase in the amount of drag reducing agents used, (ii) incremental consolidated operating costs in connection with acquisitions, (iii) employee-related costs primarily resulting from higher average headcount and salaries and (iv) unrealized mark-to-market losses on power hedges (which impact our field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above). The unfavorable variance for the year ended December 31, 2023 compared to 2022 was partially offset by a decrease in additional estimated costs recognized associated with the Line 901 incident (which impact field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above). Maintenance Capital Maintenance capital consists of capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. The increase in maintenance capital spending for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to ongoing facility maintenance investments, tractor trailer leases, integrity projects and tank maintenance. NGL Segment Our NGL segment operations involve natural gas processing and NGL fractionation, storage, transportation and terminalling. Our NGL revenues are primarily derived from a combination of (i) providing gathering, fractionation, storage, and/or terminalling services to third-party customers for a fee, and (ii) extracting NGL mix from the gas stream processed at our Empress straddle plant facility as well as acquiring NGL mix, which is then transported, stored and fractionated into finished products and sold to customers. Our management of our commodity exposure is subject to our risk management policies and may include the use of derivative instruments to mitigate the risk of such exposure and, at times, to provide upside opportunities. Generally, our segment results are impacted by (i) increases or decreases in our NGL sales volumes, (ii) volatility in commodity prices, the differential between the price of natural gas and the extracted NGL (“frac spread”), as well as location differentials and time spreads, and (iii) the volume of natural gas transported on third-party assets through our Empress straddle plant. 80 Table of Contents Index to Financial Statements Our NGL operations are sensitive to weather-related demand, particularly during the approximate five-month peak heating season of November through March, and temperature differences from period-to-period may have a significant effect on NGL demand and thus our financial performance as well as the impact of comparative performance between financial reporting periods that bisect the five-month peak heating season. The following tables set forth our operating results from our NGL segment: Operating Results (1) (in millions) Year Ended December 31, Variance 2023 2022 $ % Revenues $ 1,935 $ 2,761 $ (826) (30) % Purchases and related costs (1,123) (1,587) 464 29 % Field operating costs (372) (312) (60) (19) % Segment general and administrative expenses (2) (79) (75) (4) (5) % Adjustments (3) : Derivative activities 142 (269) 411 ** Long-term inventory costing adjustments 13 (1) 14 ** Equity-indexed compensation expense 1 — 1 ** Foreign currency revaluation 5 1 4 ** Segment Adjusted EBITDA $ 522 $ 518 $ 4 1 % Maintenance capital expenditures $ 86 $ 99 $ (13) (13) % Year Ended December 31, Variance Average Volumes (in thousands of barrels per day) (4) 2023 2022 Volumes % NGL fractionation 115 137 (22) (16) % NGL pipeline tariff 180 192 (12) (6) % Propane and butane sales 86 94 (8) (9) % ** Indicates that variance as a percentage is not meaningful. (1) Revenues and costs and expenses include intersegment amounts. (2) Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period. (3) Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 19 to our Consolidated Financial Statements for additional discussion of such adjustments. (4) Average daily volumes are calculated as total volumes (attributable to our interest for assets owned through undivided joint interests) for the year divided by the number of days in the year. Segment Adjusted EBITDA NGL Segment Adjusted EBITDA for the year ended December 31, 2023 was in line with results for the year ended December 31, 2022, primarily due to (i) favorable NGL basis differentials and (ii) additional market-based opportunities, largely offset by (iii) lower straddle production driven by turnarounds at a third-party facility, (iv) increased field operating costs and (v) the impact of the sale of our ownership interest in the Keyera Fort Saskatchewan facility in the first quarter of 2023. Significant variances in the components of Segment Adjusted EBITDA are discussed in more detail below: 81 Table of Contents Index to Financial Statements Net Revenues. Net revenues include the impact of derivative activities and long-term inventory costing adjustments, which are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above. Excluding such impacts, net revenues increased for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to (i) favorable NGL basis differentials, (ii) additional market-based opportunities and (iii) higher processing revenues at our Empress straddle plants resulting from a commercial agreement executed in conjunction with the increase in our Empress ownership in the fourth quarter of 2022. This was partially offset by (iv) lower straddle production driven by turnarounds at a third-party facility, (v) the impact of the sale of our ownership interest in the Keyera Fort Saskatchewan facility in the first quarter of 2023 and (vi) higher gains at certain of our NGL facilities in 2022. Field Operating Costs. The increase in field operating costs for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to (i) an increase in unrealized mark-to-market losses on power hedges (which impact our field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above) and (ii) increased utilities-related costs largely as a result of the increase in our Empress ownership in the fourth quarter of 2022 and higher prices. The increase in utilities-related costs was largely offset by the benefit to net revenues from operating cost recoveries realized through commercial agreements. Maintenance Capital The decrease in maintenance capital spending for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due a scheduled turnaround at our Empress facility during 2022, partially offset by an increase in routine integrity activities. Liquidity and Capital Resources General Our primary sources of liquidity are (i) cash flow from operating activities and (ii) borrowings under PAA’s credit facilities or commercial paper program. In addition, we may supplement these primary sources of liquidity with proceeds from asset sales, and in the past have utilized funds received from sales of equity and debt securities. Our primary cash requirements include, but are not limited to, (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil, NGL and other products, payment of other expenses and interest payments on outstanding debt, (ii) investment and maintenance capital activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on long-term debt and (v) distributions to our Class A shareholders and noncontrolling interests. In addition, we may use cash for repurchases of common equity. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under credit facilities or PAA’s commercial paper program. In addition, we generally expect to fund our long-term needs, such as those resulting from investment capital activities, acquisitions or refinancing long-term debt, through a variety of sources, which may include any or a combination of the sources listed above. As of December 31, 2023, although we had a working capital deficit of $89 million, we had over $2.6 billion of liquidity available to meet our ongoing operating, investing and financing needs, subject to continued covenant compliance, as noted below (in millions): As of December 31, 2023 Availability under PAA senior unsecured revolving credit facility (1) (2) $ 1,350 Availability under PAA senior secured hedged inventory facility (1) (2) 1,279 Amounts outstanding under PAA commercial paper program (433) Subtotal 2,196 Cash and cash equivalents (3) 447 Total $ 2,643 (1) Represents availability prior to giving effect to borrowings outstanding under the PAA commercial paper program, which reduce available capacity under the facilities. (2) Available capacity under the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility was reduced by outstanding letters of credit issued under these facilities of less than $1 million and $71 million, respectively. 82 Table of Contents Index to Financial Statements (3) Excludes restricted cash of $6 million. Usage of PAA’s credit facilities, which provide the financial backstop for PAA’s commercial paper program, is subject to ongoing compliance with covenants, as discussed further below. PAA’s borrowing capacity and borrowing costs are also impacted by its credit rating. See Item 1A. “Risk Factors—Risks Related to PAA’s Business—Loss of PAA’s investment grade credit rating or the ability to receive open credit could negatively affect its borrowing costs, ability to purchase crude oil, NGL and natural gas supplies or to capitalize on market opportunities.” We believe that we have, and will continue to have, the ability to access PAA’s commercial paper program and credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under PAA’s credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow, including extended disruptions in the financial markets and/or energy price volatility resulting from current macroeconomic and geopolitical conditions, including actions by OPEC. A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity and cost of borrowing. See Item 1A. “Risk Factors” for further discussion regarding risks that may impact our liquidity and capital resources. Credit Agreements, Commercial Paper Program and Indentures PAA has three primary credit arrangements, which we use to meet our short-term cash needs. These include PAA’s $1.35 billion senior unsecured revolving credit facility maturing in 2028 (excluding a commitment of $64 million, which matures in 2027), $1.35 billion senior secured hedged inventory facility maturing in 2026 and $2.7 billion unsecured commercial paper program that is backstopped by PAA’s revolving credit facility and its hedged inventory facility. The credit agreements for PAA’s revolving credit facilities (which impact PAA’s ability to access its commercial paper program because they provide the financial backstop that supports PAA’s short-term credit ratings) and the indentures governing its senior notes contain cross-default provisions. A default under PAA’s credit agreements or indentures would permit the lenders to accelerate the maturity of the outstanding debt. As long as PAA is in compliance with the provisions in its credit agreements, its ability to make distributions of available cash is not restricted. PAA was in compliance with the covenants contained in its credit agreements and indentures as of December 31, 2023. Cash Flow from Operating Activities The primary drivers of cash flow from operating activities are (i) the collection of amounts related to the sale of crude oil, NGL and other products, the transportation of crude oil and other products for a fee, and the provision of storage and terminalling services for a fee and (ii) the payment of amounts related to the purchase of crude oil, NGL and other products and other expenses, principally field operating costs, general and administrative expenses and interest expense. Cash flow from operating activities can be materially impacted by the storage of crude oil in periods of a contango market, when the price of crude oil for future deliveries is higher than current prices. In the month we pay for the stored crude oil, we borrow under the PAA credit facilities or commercial paper program (or use cash on hand) to pay for the crude oil, which negatively impacts operating cash flow. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil. Similarly, the level of NGL and other product inventory stored and held for resale at period end affects our cash flow from operating activities. In periods when the market is not in contango, we typically sell our crude oil during the same month in which we purchase it and we do not rely on borrowings under the PAA credit facilities or commercial paper program to pay for the crude oil. During such market conditions, our accounts payable and accounts receivable generally move in tandem as we make payments and receive payments for the purchase and sale of crude oil in the same month, which is the month following such activity. In periods during which we build inventory, regardless of market structure, we may rely on the PAA credit facilities or commercial paper program to pay for the inventory. In addition, we use derivative instruments to manage the risks associated with the purchase and sale of our commodities. Therefore, our cash flow from operating activities may be impacted by the margin deposit requirements related to our derivative activities. See Note 12 to our Consolidated Financial Statements for a discussion regarding our derivatives and risk management activities. Net cash provided by operating activities for the years ended December 31, 2023 and 2022 was approximately $2.7 billion and $2.4 billion, respectively, and primarily resulted from earnings from our operations. Additionally, as discussed further below, changes during these periods in our inventory levels and associated margin balances required as part of our hedging activities impacted our cash flow from operating activities. 83 Table of Contents Index to Financial Statements The 2023 period was impacted by net positive changes in working capital items, largely associated with (i) lower NGL inventory driven by both the impact of the price environment and NGL supply volumes during the year, including the impact of changes in margin balances required as part of our hedging activities, and (ii) timing of payments associated with the settlement of certain obligations. Investing Activities Capital Expenditures In addition to our operating needs, we also use cash for our investment capital projects, maintenance capital activities and acquisition activities. We fund these expenditures with cash generated by operating activities, financing activities and/or proceeds from asset sales. In the near term, we do not plan to issue common equity to fund such expenditures. The following table summarizes our investment, maintenance and acquisition capital expenditures (in millions): Year Ended December 31, 2023 2022 Investment capital (1) (2) (3) $ 399 $ 334 Maintenance capital (1) (3) 231 211 Acquisition capital (2) (4) 431 284 $ 1,061 $ 829 (1) Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as “Investment capital.” Capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as “Maintenance capital.” (2) Contributions to unconsolidated entities, accounted for under the equity method of accounting, that are related to investment capital projects by such entities are recognized in “Investment capital.” Acquisitions of initial investments or additional interests in unconsolidated entities are included in “Acquisition capital.” (3) Investment capital and maintenance capital, net to our 65% interest in the Permian JV, was approximately $310 million and $214 million, respectively, for 2023, and approximately $265 million and $202 million, respectively, for 2022. (4) Acquisition capital for 2023 primarily includes the acquisition by the Permian JV of (i) the remaining 43% interest in OMOG JV Holdings LLC and (ii) gathering assets in the Southern and Northern Delaware Basins. Acquisition capital for 2022 includes (i) an additional ownership interest in certain straddle plants included in our NGL segment, (ii) the purchase of an additional 5% interest in Cactus II and (iii) the remaining 50% interest in Advantage Pipeline Holdings LLC by the Permian JV. See Note 7 to our Consolidated Financial Statements for additional information. Acquisition capital, net to our 65% interest in the Permian JV, was approximately $281 million and $258 million for 2023 and 2022, respectively. Investment Capital Projects Our investment capital programs consist of investments in midstream infrastructure projects that build upon our core assets and operations. The majority of this investment capital consists of highly-contracted projects that complement our broader system capabilities and support the long-term needs of the upstream and downstream sectors of the industry value chain. The following table summarizes our investment in capital projects (in millions): Year Ended December 31, Projects 2023 2022 Complementary Permian Basin Projects (1) $ 266 $ 191 Permian Basin Takeaway Pipeline Projects (2) 34 33 Selected Facilities/Downstream Projects (3) 71 28 Other Projects 28 82 Total $ 399 $ 334 84 Table of Contents Index to Financial Statements (1) Includes projects associated with assets included in the Permian JV. (2) Represents pipeline projects with takeaway capacity out of the Permian Basin, including investments for our proportionate share of the projects of Wink to Webster Pipeline and Cactus II Pipeline. (3) Includes projects at our St. James and Fort Saskatchewan terminals. Projected 2024 Capital Expenditures. Total investment capital for the year ending December 31, 2024 is currently projected to be approximately $465 million ($375 million net to our interest). Approximately half of our projected investment capital expenditures are expected to be invested in the Permian JV assets. Additionally, maintenance capital for 2024 is currently projected to be approximately $250 million ($230 million net to our interest). We expect to fund our 2024 investment and maintenance capital expenditures primarily with retained cash flow. Divestitures Proceeds from the sale of assets have generally been used to fund our investment capital projects and reduce debt levels. The following table summarizes the proceeds received from divestitures during the last two years (in millions): Year Ended December 31, 2023 2022 Proceeds from divestitures (1) $ 328 $ 60 (1) Represents proceeds, including working capital adjustments, net of transaction costs. The proceeds from divestitures for the year ended December 31, 2023 are primarily from the sale of our 21% non-operated/undivided joint interest in the Keyera Fort Saskatchewan facility in February 2023. See Note 7 to our Consolidated Financial Statements for additional information. Ongoing Activities Related to Strategic Transactions We are continuously engaged in the evaluation of potential transactions that support our current business strategy. In the past, such transactions have included the acquisition of assets that complement our existing footprint, the sale of non-core assets, the sale of partial interests in assets to strategic joint venture partners, and large investment capital projects. With respect to a potential acquisition or divestiture, we may conduct an auction process or participate in an auction process conducted by a third party or we may negotiate a transaction with one or a limited number of potential sellers (in the case of an acquisition) or buyers (in the case of a divestiture). Such transactions could have a material effect on our financial condition and results of operations. We typically do not announce a transaction until after we have executed a definitive agreement. In certain cases, in order to protect our business interests or for other reasons, we may defer public announcement of a transaction until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future efforts with respect to any such transactions will be successful, and we can provide no assurance that our financial expectations with respect to such transactions will ultimately be realized. See Item 1A. “Risk Factors—Risks Related to PAA’s Business—Acquisitions and divestitures involve risks that may adversely affect PAA’s business.” Financing Activities Our financing activities primarily relate to funding investment capital projects, acquisitions and refinancing of debt maturities, as well as short-term working capital (including borrowings for NYMEX and ICE margin deposits) and hedged inventory borrowings related to our NGL business and contango market activities. Borrowings and Repayments Under Credit Arrangements During the year ended December 31, 2023, we had net borrowings under the PAA commercial paper program of $433 million. The net borrowings resulted primarily from borrowings during the year related to funding needs for capital investments, inventory purchases and other general partnership purposes. 85 Table of Contents Index to Financial Statements We had no net borrowings or repayments under the PAA credit facilities or commercial paper program during the year ended December 31, 2022. Senior Notes Repayments of PAA Senior Notes. During 2023 and 2022, PAA repaid the following senior unsecured notes in full (in millions): Year Description Repayment Date 2023 $700 million 3.85% PAA Senior Notes due October 2023 October 2023 (1) 2023 $400 million 2.85% PAA Senior Notes due January 2023 January 2023 (1) 2022 $750 million 3.65% PAA Senior Notes due June 2022 March 2022 (1) (1) PAA repaid these senior notes with cash on hand and borrowings under its commercial paper program. Registration Statements PAGP Registration Statements. We have filed with the SEC a shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to a specified amount of equity securities (“PAGP Traditional Shelf”). At December 31, 2023, we had approximately $939 million of unsold securities available under the PAGP Traditional Shelf. We also have access to a universal shelf registration statement (“PAGP WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of equity securities, subject to market conditions and its capital needs. PAA Registration Statements . PAA periodically accesses the capital markets for both equity and debt financing. PAA has filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows PAA to issue up to a specified amount of debt or equity securities (“PAA Traditional Shelf”), under which PAA had approximately $1.1 billion of unsold securities available at December 31, 2023. PAA also has access to a universal shelf registration statement (“PAA WKSI Shelf”), which provides it with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and capital needs. Common Equity Repurchase Program In November 2020, the board of directors of our general partner approved a $500 million common equity repurchase program (the “Program”) to be utilized as an additional method of returning capital to investors. The Program authorizes the repurchase from time to time of up to $500 million of PAA’s common units and/or our Class A shares via open market purchases or negotiated transactions conducted in accordance with applicable regulatory requirements. Ultimately, the amount, timing and pace of potential repurchase activity will be determined by a number of factors, including market conditions, PAA’s financial performance and flexibility, PAA’s actual and expected free cash flow after distributions, the absolute and relative equity prices of PAA’s common units and our Class A shares, and the extent to which PAA is positioned to achieve and maintain its targeted leverage ratio. No time limit has been set for completion of the Program, and the Program may be suspended or discontinued at any time. The Program does not obligate PAA or us to acquire a particular number of common units or Class A shares. Any PAA common units or Class A shares that are repurchased will be canceled. There were no repurchases under the Program during the year ended December 31, 2023. PAA repurchased common units under the Program during the year ended December 31, 2022 for a total purchase price of $74 million, including commissions and fees. The remaining available capacity under the Program as of December 31, 2023 was $198 million. 86 Table of Contents Index to Financial Statements Distributions to Our Class A Shareholders We distribute 100% of our available cash to our Class A shareholders of record within 55 days following the end of each quarter. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. Our levels of financial reserves are established by our general partner and include reserves for, among other things, the proper conduct of our business (including future capital expenditures and anticipated credit needs), compliance with legal or contractual obligations and funding of future distributions to our shareholders. See Item 5. “Market for Registrant’s Shares, Related Shareholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy” for additional discussion regarding distributions. On February 14, 2024, we paid a quarterly distribution of $0.3175 per Class A share ($1.27 per Class A share on an annualized basis). The distribution was paid to Class A shareholders of record as of January 31, 2024, with respect to the quarter ended December 31, 2023. See Note 11 to our Consolidated Financial Statements for details of distributions paid during the three years ended December 31, 2023. Distributions to Noncontrolling Interests Distributions to noncontrolling interests represent amounts paid on interests in consolidated entities that are not owned by us. As of December 31, 2023, noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 70% interest in PAA’s common units and PAA’s Series A preferred units combined and 100% of PAA’s Series B preferred units, (ii) an approximate 16% limited partner interest in AAP, (iii) a 35% interest in the Permian JV, (iv) a 30% interest in Cactus II and (v) a 33% interest in Red River. See Note 11 to our Consolidated Financial Statements for details of distributions paid to noncontrolling interests during the three years ended December 31, 2023. Distributions to PAA’s Series A preferred unitholders. Holders of PAA’s Series A preferred units are entitled to receive quarterly distributions, subject to customary anti-dilution adjustments, of $0.615 per unit ($2.46 per unit annualized). Distributions to PAA’s Series B preferred unitholders. Holders of PAA’s Series B preferred units are entitled to receive, when, as and if declared by PAA’s general partner out of legally available funds for such purpose, cumulative cash distributions, as applicable. Distributions on the Series B preferred units accumulate based on the applicable three-month SOFR, plus a credit spread adjustment of 0.26121%, plus 4.11% per annum. The distribution rate for the quarterly distribution paid on February 15, 2024 was 9.75093% per annum ($24.92 per Series B preferred unit). Distributions to PAA’s common unitholders. On February 14, 2024, PAA paid a quarterly distribution of $0.3175 per common unit ($1.27 per common unit on an annualized basis). The total distribution of $223 million was paid to common unitholders of record as of January 31, 2024, with respect to the quarter ended December 31, 2023. See Note 11 to our Consolidated Financial Statements for details of distributions paid during the three years ended December 31, 2023. Contingencies For a discussion of contingencies that may impact us, see Note 18 to our Consolidated Financial Statements. Commitments See Note 10 to our Consolidated Financial Statements for information regarding our debt obligations and Note 18 for information regarding our leases and other commitments. Purchase Obligations In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years, with a limited number of contracts with remaining terms extending up to 11 years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate. 87 Table of Contents Index to Financial Statements The following table includes our best estimate and the timing of these payments as of December 31, 2023 (in millions): 2024 2025 2026 2027 2028 2029 and Thereafter Total Crude oil, NGL and other purchases (1) $ 22,938 $ 19,743 $ 17,910 $ 15,817 $ 12,795 $ 30,341 $ 119,544 (1) Amounts are primarily based on estimated volumes and market prices based on average activity during December 2023. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control. Letters of Credit. In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the product is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At December 31, 2023 and 2022, we had outstanding letters of credit of approximately $205 million and $102 million, respectively. Off-Balance Sheet Arrangements We have no off-balance sheet arrangements as defined by Item 303 of Regulation S-K. Investments in Unconsolidated Entities We have invested in entities that are not consolidated in our financial statements. None of these entities had debt outstanding as of December 31, 2023. We may elect at any time to make additional capital contributions to any of these entities. The following table sets forth selected information regarding these entities as of December 31, 2023 (unaudited, dollars in millions): Entity Type of Operation Our Ownership Interest Total Entity Assets Total Cash and Restricted Cash BridgeTex Pipeline Company, LLC Crude Oil Pipeline 20% $ 786 $ 11 Capline Pipeline Company LLC Crude Oil Pipeline 54% $ 1,249 $ 46 Diamond Pipeline LLC Crude Oil Pipeline (1) 50% $ 876 $ 1 Eagle Ford Pipeline LLC Crude Oil Pipeline (1) 50% $ 780 $ 34 Eagle Ford Terminals Corpus Christi LLC Crude Oil Terminal and Dock (1) 50% $ 210 $ 5 Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 30% $ 600 $ 21 White Cliffs Pipeline, LLC Crude Oil Pipeline 36% $ 377 $ 6 Wink to Webster Pipeline LLC Crude Oil Pipeline 16% $ 2,324 $ 73 Other investments $ 520 $ 30 (1) We serve as operator of the asset. Critical Accounting Policies and Estimates The preparation of financial statements in conformity with GAAP and rules and regulations of the SEC requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities, at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from these estimates. On a regular basis, we evaluate our assumptions, judgments and estimates. We also discuss our critical accounting policies and estimates with the Audit Committee of the Board of Directors. 88 Table of Contents Index to Financial Statements We believe that the assumptions, judgments and estimates involved in the accounting for our (i) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (ii) fair value of derivatives, (iii) accruals and contingent liabilities, (iv) property and equipment, depreciation and amortization expense and asset retirement obligations, (v) impairment assessments of property and equipment, investments in unconsolidated entities and intangible assets and (vi) inventory valuations have the greatest potential impact on our Consolidated Financial Statements. These areas are key components of our results of operations and are based on complex rules which require us to make judgments and estimates. Therefore, we consider these to be our critical accounting policies and estimates, which are discussed below. For further information on all of our significant accounting policies, see Note 2 to our Consolidated Financial Statements. Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets. In accordance with Financial Accounting Standards Board (“FASB”) guidance regarding business combinations, with each acquisition, we allocate the cost of the acquired entity to the assets acquired and liabilities assumed based on their estimated fair values at the date of acquisition. If the initial accounting for the business combination is incomplete when the combination occurs, an estimate will be recorded. We also expense the transaction costs as incurred in connection with each acquisition, except for acquisitions of equity method investments. In addition, we are required to recognize intangible assets separately from goodwill. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, acreage dedications and other contracts, involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets acquired and, to the extent available, third-party assessments. In the third quarter of 2023, our Permian JV acquired the remaining 43% interest in OMOG JV Holdings LLC (“OMOG”) and certain gathering assets in the Southern Delaware basin from Rattler Midstream Operating LLC. The transaction had an aggregate purchase price of $294 million ($191 million net to our 65% interest in the Permian JV). As a result of the transaction, the Permian JV now owns 100% of OMOG and its subsidiaries and such entities are reflected as consolidated subsidiaries in our Consolidated Financial Statements. Prior to this transaction, the Permian JV’s 57% interest in OMOG was accounted for as an equity method investment. See Note 7 to our Consolidated Financial Statements for discussion of the methods, assumptions and estimates used in the determination of the fair value of the assets and liabilities acquired and identification of associated intangible assets. In November 2022, we and Enbridge Inc. (“Enbridge”) purchased Western Midstream Partners, LP (“WES”)’s 15% interest in Cactus II Pipeline, LLC (“Cactus II”) for an aggregate amount of $265 million. Enbridge acquired 10% and we acquired 5% of Cactus II, with each paying a proportionate share of the purchase price. We and Enbridge are now the sole owners of Cactus II, with 70% and 30% respective ownership interests. We previously accounted for our 65% interest in Cactus II as an equity method investment. In addition to the change in ownership, there were changes in governance which led to a change in control. We now control Cactus II and reflect Cactus II as a consolidated subsidiary in our Consolidated Financial Statements, with Enbridge’s 30% interest reflected as a noncontrolling interest. See Note 7 to our Consolidated Financial Statements for discussion of the methods, assumptions and estimates used in the determination of the fair value of the assets and liabilities acquired and identification of associated intangible assets. In October 2021, we and Oryx Midstream completed the formation of the Permian JV. See Note 7 to our Consolidated Financial Statements for discussion of the methods, assumptions and estimates used in the determination of the fair value of the assets and liabilities acquired and identification of associated intangible assets. Fair Value of Derivatives. The fair value of a derivative at a particular period end does not reflect the end results of a particular transaction, and will most likely not reflect the gain or loss at the conclusion of a transaction. We reflect estimates for these items based on our internal records and information from third parties. We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value on our Consolidated Balance Sheets. The valuations of our derivatives that are exchange traded are based on market prices on the applicable exchange on the last day of the period. For our derivatives that are not exchange traded, the estimates we use are based on indicative broker quotations or an internal valuation model. Our valuation models utilize market observable inputs such as price, volatility, correlation and other factors and may not be reflective of the price at which they can be settled due to the lack of a liquid market. Less than 1% of total annual revenues are based on estimates derived from internal valuation models. Although the resolution of the uncertainties involved in these estimates has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note 12 to our Consolidated Financial Statements for a discussion regarding our derivatives and risk management activities. 89 Table of Contents Index to Financial Statements Accruals and Contingent Liabilities. We record accruals or liabilities for, among other things, environmental remediation, potential legal claims or settlements and fees for legal services associated with loss contingencies, and bonuses. Accruals are made when our assessment indicates that it is probable that a liability has occurred and the amount of liability can be reasonably estimated. Our estimates are based on all known facts at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our environmental remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment, the duration of the natural resource damage assessment and the ultimate amount of damages determined, the determination and calculation of fines and penalties, the possibility of existing legal claims giving rise to additional claims and the nature, extent and cost of legal services that will be required in connection with lawsuits, claims and other matters. Our estimates for contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved. A hypothetical variance of 5% in our aggregate estimate for the accruals and contingent liabilities discussed above would have an impact on earnings of up to approximately $14 million. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. Property and Equipment, Depreciation and Amortization Expense and Asset Retirement Obligations. We compute depreciation and amortization based on estimated useful lives. These estimates are based on various factors including condition, manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We record retirement obligations associated with tangible long-lived assets based on estimates related to the costs associated with cleaning, purging and, in some cases, completely removing the assets and returning the land to its original state. In addition, our estimates include a determination of the settlement date or dates for the potential obligation, which may or may not be determinable. Uncertainties that impact these estimates include the costs associated with these activities and the timing of incurring such costs. A hypothetical variance of 5% in our aggregate estimate for the retirement obligations discussed above would have an impact on earnings of up to approximately $6 million. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. See Note 6 and Note 9 to our Consolidated Financial Statements for additional information on our property and equipment, intangible assets and depreciation and amortization expense. See Note 2 to our Consolidated Financial Statements for additional information on our asset retirement obligations. Impairment Assessments of Property and Equipment, Investments in Unconsolidated Entities and Intangible Assets. We periodically evaluate property and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. Any evaluation is highly dependent on the underlying assumptions of related cash flows. We consider the fair value estimate used to calculate impairment of property and equipment a critical accounting estimate. In determining the existence of an impairment of carrying value, we make a number of subjective assumptions as to: • whether there is an event or circumstance that may be indicative of an impairment; • the grouping of assets; • the intention of “holding”, “abandoning” or “selling” an asset; • the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and • if an impairment exists, the fair value of the asset or asset group. In addition, when we evaluate property and equipment and other long-lived assets for recoverability, it may also be necessary to review related depreciation estimates and methods. 90 Table of Contents Index to Financial Statements Investments in unconsolidated entities accounted for under the equity method of accounting are assessed for impairment when events or circumstances suggest that a decline in value may be other than temporary. Examples of such events or circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s core business. When it is determined that an indicated impairment is other than temporary, a charge is recognized for the difference between the investment’s carrying amount and its estimated fair value. We consider the fair value estimate used to calculate the impairment of investments in unconsolidated entities a critical accounting estimate. In determining the existence of an other-than-temporary impairment of carrying value, we make a number of subjective assumptions as to: • whether there is an event or circumstance that may be indicative of a decline in value of the investment; • whether the decline in value is other than temporary; and • the fair value of the investment. Intangible assets with indefinite lives are not amortized but are instead periodically assessed for impairment. Intangible assets with finite lives are amortized over their estimated useful life as determined by management. Impairment testing entails estimating future net cash flows relating to the business, based on the grouping of assets and management’s estimate of future revenues, future cash flows and market conditions including pricing, demand, competition, operating costs and other factors. Uncertainties associated with these estimates include changes in production decline rates, production interruptions, fluctuations in refinery capacity or product slates, economic obsolescence factors in the area and potential future sources of cash flow. In addition, changes in our weighted average cost of capital from our estimates could have a significant impact on fair value. We cannot provide assurance that actual amounts will not vary significantly from estimated amounts. Resolutions of these uncertainties have resulted, and in the future may result, in impairments that impact our results of operations and financial condition. A change in our outlook or use could result in impairments that may be material to our results of operations or financial condition. See “—Executive Summary— Market Overview and Outlook” and Note 6, Note 8 and Note 9 to our Consolidated Financial Statements for additional information. Inventory Valuations. Inventory, including long-term inventory, primarily consists of crude oil and NGL and is valued at the lower of cost or net realizable value, with cost determined using an average cost method within specific inventory pools. At the end of each reporting period, we assess the carrying value of our inventory and use estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact our estimates are the applicable quality and location differentials to include in our net realizable value analysis. Additionally, we estimate the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value. During the years ended December 31, 2023, 2022 and 2021, we did not record any charges related to the valuation adjustment of our inventory. See Note 5 to our Consolidated Financial Statements for further discussion regarding inventory. Line 901 Incident Insurance Receivable. In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. We have estimated that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $750 million, which includes actual and projected emergency response and clean-up costs, natural resource damage assessments, fines and penalties payable pursuant to the Consent Decree, certain third-party claims settlements, and estimated costs associated with our remaining Line 901 lawsuits and claims, as well as estimates for certain legal fees and statutory interest where applicable. As of December 31, 2023, we have recognized a long-term receivable of approximately $225 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected. Insurers responsible for the majority of our remaining insurance coverage have formally communicated a denial of coverage. We intend to vigorously pursue recovery from our insurers of all amounts for which we have claimed reimbursement. We believe that our claim for reimbursement from our insurers is strong and that our ultimate recovery of such amounts is probable. Various factors could impact the timing and amount of recovery of our insurance receivable, including future developments that adversely impact our assessment of the strength of our coverage claims, the outcome of any dispute resolution proceedings with respect to our coverage claims and the extent to which insurers may become insolvent in the future. Without limiting our view that our claim for reimbursement is strong and that ultimate recovery is probable, we cannot provide complete assurance that actual receivable amounts will not vary significantly from our estimated amounts. See Note 18 to our Consolidated Financial Statements for further discussion regarding the Line 901 incident and our related insurance receivable. 91 Table of Contents Index to Financial Statements Recent Accounting Pronouncements See Note 2 to our Consolidated Financial Statements for information regarding the effect of recent accounting pronouncements on our Consolidated Financial Statements.