PAGP

HOUSTON, Aug. 07, 2026 (GLOBE NEWSWIRE) -- Plains All American Pipeline, L.P. (Nasdaq: PAA) and Plains GP Holdings (Nasdaq: PAGP) today reported second-quarter 2026 results and provided the following highlights: Second-Quarter 2026 Results Second-quarter Net income attributable to PAA of $1.830 billion, including a net gain of approximately $1.6 billion from the Canadian NGL Business divestiture, and Net cash provided by operating activities of $956 million Delivered strong second-quarter Adjusted EBITDA attributable to PAA of $738 million Pro forma leverage ratio at quarter-end was 3.3x reflecting approximately $2.9 billion of debt reduction funded with proceeds from the Canadian NGL Business divestiture and toward the low-end of our target range of 3.25 to 3.75x Paid a quarterly cash distribution of $0.4175 per unit ($1.67 per unit annualized), representing a current distribution yield of ~7% Highlights and Recent Announcements Executing on three key initiatives for the year: closed the NGL sale, captured $50 million of synergies on the Cactus III acquisition and delivering on $50 million of targeted cost reductions through year-end 2026 Increased 2026 organic growth capital from $350 million to a range of $400 to $450 million including a 75 Mbbl/d expansion of the Cactus III pipeline, Canadian gathering systems and Permian gathering projects across the Delaware and Midland basins Maintenance capital guidance is being reduced by $10 million to $175 million largely based on timing of the NGL divestiture “Strong results in the quarter mark a significant improvement from first quarter levels and place us on-track to deliver on our full-year Adjusted EBITDA guidance. Year-to-date we are on pace to accomplish all three key initiatives outlined for 2026. In May, we successfully closed on the sale of our Canadian NGL business, completing a transition to a premier pure play crude oil midstream provider. Proceeds from the NGL sale were used to bring our leverage ratio back within our established target range. Cactus III synergies have been captured and we are now seeing additional upside potential from expanding the capacity of the pipeline by 75 Mbbl/d. Finally, we remain on-track to capture streamlining efficiencies throughout the organization this year. The combination of these key initiatives along with contributions from new organic investment opportunities and Permian volume growth provides momentum for the organization heading into 2027. The oil macro environment remains volatile but our well positioned asset footprint, integrated business model, and commercial relationships position us well to capture opportunities across our portfolio,” said Willie Chiang, Chairman, CEO and President. Financial Reporting Considerations from Sale of Canadian NGL Business On May 12, 2026, we completed the sale of substantially all of our NGL business in Canada (the “Canadian NGL Business”) to Keyera Corp. (“Keyera”), pursuant to a definitive share purchase agreement (as amended to date, the “SPA”) entered into on June 17, 2025. We determined that the operations of the Canadian NGL Business met the criteria for classification as held for sale and for discontinued operations reporting. Results throughout this release specify if they are presented from continuing operations (which exclude results related to the Canadian NGL Business) and/or discontinued operations. Plains All American Pipeline Summary Financial Information (unaudited)(in millions, except per unit data) Disaggregation of Adjusted EBITDA by Product (1) (2) (unaudited)(in millions) Second-quarter 2026 Adjusted EBITDA from Crude Oil increased 19% versus comparable 2025 results. Favorable results in the 2026 period from (i) contributions from our Cactus III pipeline acquisition, which was completed during the fourth quarter of 2025, (ii) higher volumes on our pipelines and (iii) market opportunities and optimization initiatives were partially offset by the impact of (iv) certain Permian long-haul pipeline contract rate resets. Second-quarter 2026 Adjusted EBITDA from NGL decreased 54% versus comparable 2025 results primarily due to the sale of the Canadian NGL Business, which closed on May 12, 2026. Plains GP Holdings PAGP owns an indirect non-economic controlling interest in PAA’s general partner and an indirect limited partner interest in PAA. As the control entity of PAA, PAGP consolidates PAA’s results into its financial statements, which is reflected in the condensed consolidating balance sheet and income statement tables attached hereto. Conference Call and Webcast Instructions PAA and PAGP will hold a joint conference call at 9:00 a.m. CT on Friday, August 7, 2026 to discuss second-quarter performance and related items. To access the internet webcast, please go to https://edge.media-server.com/mmc/p/d62hd2t2/lan/en. Alternatively, the webcast can be accessed on our website at https://ir.plains.com/news-events/events-presentations. Following the live webcast, an audio replay will be available on our website and will be accessible for a period of 365 days. Slides will be posted prior to the call at the above referenced website. Non-GAAP Financial Measures and Selected Items Impacting Comparability 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 and to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. The primary additional measures used by management are Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied Distributable Cash Flow (“DCF”), Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions. Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied DCF and certain other non-GAAP financial performance measures are reconciled to Net Income, and Adjusted Free Cash Flow, Adjusted Free Cash Flow after Distributions and certain other non-GAAP financial liquidity measures are reconciled to Net Cash Provided by Operating Activities (the most directly comparable measures as reported in accordance with GAAP) for the historical periods presented in the tables attached to this release, and should be viewed in addition to, and not in lieu of, our Consolidated Financial Statements and accompanying notes. In addition, we encourage you to visit the Investor Relations section of our website at www.plains.com (navigate to the “Financials” tab, then click on “Quarterly Results”), which presents a reconciliation of our commonly used non-GAAP and supplemental financial measures. We do not reconcile non-GAAP financial measures on a forward-looking basis as it is impractical to do so without unreasonable effort. Non-GAAP Financial Performance Measures Adjusted EBITDA is defined as earnings from continuing operations and discontinued operations before (i) interest expense, (ii) income tax (expense)/benefit from continuing operations and discontinued operations, (iii) depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities) from continuing operations and discontinued operations, (iv) gains and losses on asset sales, asset impairments and other, net from continuing operations and discontinued operations, (v) gains on investments in unconsolidated entities, net and (vi) interest income on promissory notes by and among certain Plains entities, and (vii) adjusted for certain selected items impacting comparability. Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests. Adjusted EBITDA disaggregated by product (e.g., Adjusted EBITDA from Crude Oil and Adjusted EBITDA from NGL) excludes amounts related to Other income/(expense). Management believes that the presentation of Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF 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 operating performance and ability to fund distributions to our unitholders through cash generated by our operations and (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions. We also present these and additional non-GAAP financial measures, including adjusted net income attributable to PAA and basic and diluted adjusted net income per common unit, as they are 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 operating results and/or (v) other items that we believe should be excluded in understanding our operating performance. These measures may be further 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. Furthermore, the calculation of these measures contemplates tax effects as a separate reconciling item, where applicable. We have defined all such items as “selected items impacting comparability.” Due to the nature of the selected items, certain selected items impacting comparability may impact certain non-GAAP financial measures, referred to as adjusted results, but not impact other non-GAAP financial measures. 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. These types of variations may not be separately identified in this release, but will be discussed, as applicable, in management’s discussion and analysis of operating results in our Quarterly Report on Form 10-Q. Non-GAAP Financial Liquidity Measures Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Adjusted Free Cash Flow is defined as Net Cash Provided by Operating Activities, less Net Cash Provided by/(Used in) Investing Activities, which primarily includes acquisition, investment and maintenance capital expenditures, investments in unconsolidated entities and related party notes and the impact from the purchase and sale of linefill, net of proceeds from the sales of assets and further impacted by distributions to and contributions from noncontrolling interests and proceeds from the issuance of related party notes. Adjusted Free Cash Flow is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions. We also present these measures and additional non-GAAP financial liquidity measures as they are measures that investors have indicated are useful. We present Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) for use in assessing our underlying business liquidity and cash flow generating capacity excluding fluctuations caused by timing of when amounts earned or incurred were collected, received or paid from period to period. Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) is defined as Adjusted Free Cash Flow excluding the impact of “Changes in assets and liabilities, net of acquisitions” on our Condensed Consolidated Statements of Cash Flows. In addition, we exclude impacts related to the Canadian NGL Business divestiture. Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities). Non-GAAP Financial Measures and Discontinued Operations From June 17, 2025, the date we entered into the SPA with Keyera to sell the Canadian NGL Business, through the closing of the divestiture on May 12, 2026, management reviewed such business as a component of our overall company performance and ability to fund distributions to our unitholders in the near term. As such, certain Non-GAAP financial performance measures, such as Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied DCF, and certain Non-GAAP financial liquidity measures, such as Adjusted Free Cash Flow and Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities), are presented on a consolidated basis (e.g., the aggregate of continuing operations and discontinued operations) to provide relevant and useful information regarding our historical performance and results of operations and to assist in reconciling results presented in historical periods. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS(in millions, except per unit data) PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATED BALANCE SHEET DATA(in millions) DEBT CAPITALIZATION RATIOS (1)(in millions, except percentages) PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) COMPUTATION OF BASIC AND DILUTED NET INCOME PER COMMON UNIT(in millions, except per unit data) PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATED CASH FLOW DATA(in millions) PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY(unaudited) CAPITAL EXPENDITURES(1)(in millions) PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY(unaudited) NON-GAAP RECONCILIATIONS(in millions, except per unit and ratio data) Net Income Per Common Unit to Adjusted Net Income Per Common Unit Reconciliation (1): PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation: PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) Net Income Per Common Unit to Implied DCF Per Common Unit and Common Unit Equivalent Reconciliation (1): PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) SELECTED ITEMS IMPACTING COMPARABILITY (in millions) PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) SELECTED FINANCIAL DATA BY CRUDE OIL(in millions) PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) SELECTED FINANCIAL DATA BY NGL(in millions) PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) DISCONTINUED OPERATIONS DETAIL(in millions) Components of Income from Discontinued Operations, Net of Tax: Reconciliation of Adjusted EBITDA from NGL Discontinued Operations: Investment Capital from NGL Discontinued Operations: PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) OPERATING DATA (1) PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) SUPPLEMENTAL NON-GAAP RECONCILIATIONS(in millions) Supplemental Adjusted EBITDA attributable to PAA Reconciliation: PLAINS GP HOLDINGS AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS(in millions, except per share data) PLAINS GP HOLDINGS AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS(in millions, except per share data) PLAINS GP HOLDINGS AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATING BALANCE SHEET DATA(in millions) PLAINS GP HOLDINGS AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) COMPUTATION OF BASIC AND DILUTED NET INCOME PER CLASS A SHARE(in millions, except per share data) Forward-Looking Statements Except for the historical information contained herein, the matters discussed in this release consist of forward-looking statements that involve certain risks and uncertainties that could cause actual results or outcomes to differ materially from results or outcomes anticipated in the forward-looking statements. These risks and uncertainties include, among other things, the following: general economic, market or business conditions in the United States and elsewhere (including the potential for a recession or significant slowdown in economic activity levels, the risk of persistently high inflation and supply chain issues, the impact of global public health events, such as pandemics, on demand and growth, and the timing, pace and extent of economic recovery) that impact (i) demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide and (ii) commercial opportunities available to us; declines in global crude oil demand and/or crude oil prices or other factors that correspondingly lead to a significant reduction of North American crude oil production (whether due to reduced producer cash flow to fund drilling activities or the inability of producers to access capital, or both, the unavailability of pipeline and/or storage capacity, the shutting-in of production by producers, government-mandated pro-ration orders, or other factors), which in turn could result in significant declines in the actual or expected volume of crude oil shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets and/or the reduction of the margins we can earn or the commercial opportunities that might otherwise be available to us; impacts of global geopolitical events, including conflicts in the Middle East and elsewhere, on commodity price volatility and crude oil supply and demand, as well as broader impacts on financial markets and the global macroeconomic environment; fluctuations in refinery capacity and other factors affecting demand for various grades of crude oil and resulting changes in pricing conditions or transportation throughput requirements; unanticipated changes in crude oil market structure, grade differentials and volatility (or lack thereof); the effects of competition and capacity overbuild in areas where we operate, including downward pressure on rates, volumes and margins, contract renewal risk and the risk of loss of business to other midstream operators who are willing or under pressure to aggressively reduce transportation rates in order to capture or preserve customers; the availability of, and our ability to consummate, acquisitions, divestitures, joint ventures or other strategic opportunities and realize benefits therefrom; the successful operation of joint ventures and joint operating arrangements we enter into from time to time, whether relating to assets operated by us or by third parties, and the successful integration and future performance of acquired assets or businesses; environmental liabilities, litigation or other events that are not covered by an indemnity, insurance or existing reserves; negative societal sentiment regarding the hydrocarbon energy industry and the continued development and consumption of hydrocarbons, which could influence consumer preferences and governmental or regulatory actions that adversely impact our business; the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event that materially impacts our operations, including cyber or other attacks on our or our service providers’ electronic and computer systems; weather interference with business operations or project construction, including the impact of extreme weather events or conditions (including hurricanes, floods, wildfires and drought); the impact of current and future laws, rulings, legislation, governmental regulations, executive orders, trade policies, trade tariffs, accounting standards and statements, and related interpretations that (i) prohibit, restrict or regulate the development of oil and gas resources and the related infrastructure on lands dedicated to or served by our pipelines or (ii) negatively impact our ability to develop, operate or repair midstream assets, or (iii) otherwise negatively impact our business or increase our exposure to risk; negative impacts on production levels in the Permian Basin or elsewhere due to issues associated with (or laws, rules or regulations relating to) hydraulic fracturing and related activities (including wastewater injection or disposal), including earthquakes, subsidence, expansion or other issues; the pace of development of natural gas or other infrastructure and its impact on expected crude oil production growth in the Permian Basin; the refusal or inability of our customers or counterparties to perform their obligations under their contracts with us (including commercial contracts, asset sale agreements and other agreements), whether justified or not and whether due to financial constraints (such as reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors; loss of key personnel and inability to attract and retain new talent; disruptions to futures markets for crude oil and other petroleum products, which may impair our ability to execute our commercial or hedging strategies; the effectiveness of our risk management activities; shortages or cost increases of supplies, materials or labor; maintenance of our credit ratings and ability to receive open credit from our suppliers and trade counterparties; our inability to perform our obligations under our contracts, whether due to non-performance by third parties, including our customers or counterparties, market constraints, third-party constraints, supply chain issues, legal constraints (including governmental orders or guidance), or other factors or events; the incurrence of costs and expenses related to unexpected or unplanned capital or maintenance expenditures, third-party claims or other factors; failure to implement or capitalize, or delays in implementing or capitalizing, on investment capital projects, whether due to permitting delays, permitting withdrawals or other factors; failure to implement or realize anticipated benefits from operational and organizational streamlining and efficiency efforts and initiatives; tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, investment capital projects, working capital requirements and the repayment or refinancing of indebtedness; the amplification of other risks caused by volatile or closed financial markets, capital constraints, liquidity concerns and inflation; the use or availability of third-party assets upon which our operations depend and over which we have little or no control; the currency exchange rate of the Canadian dollar to the United States dollar; the deferral of current revenue recognition attributable to deficiency payments received from customers who fail to ship or move their minimum contracted volumes; significant under-utilization of our assets and facilities; increased costs, or lack of availability, of insurance; fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans; risks related to the development and operation of our assets; and other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil and other petroleum products as discussed in the Partnerships’ filings with the Securities and Exchange Commission. About Plains: PAA is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services primarily for crude oil. PAA owns an extensive network of pipeline gathering and transportation systems, in addition to terminalling, storage, processing, fractionation and other infrastructure assets serving key producing basins, transportation corridors and major market hubs and export outlets in the United States and Canada. PAGP is a publicly traded entity that owns an indirect, non-economic controlling general partner interest in PAA and an indirect limited partner interest in PAA, one of the largest energy infrastructure and logistics companies in North America. PAA and PAGP are headquartered in Houston, Texas. For more information, please visit www.plains.com. Contacts: Blake FernandezVice President, Investor Relations(866) 809-1291 Ross HovdeDirector, Investor Relations(866) 809-1291

This article first appeared on GuruFocus. Adjusted EBITDA (Attributable to Plains): $738 million for the second quarter of 2026. Full-Year 2026 Adjusted EBITDA Guidance: Expected to be $2.88 billion, plus or minus $75 million. Crude Oil Segment Adjusted EBITDA: $690 million for the second quarter, a significant increase from the first quarter level. NGL Segment Adjusted EBITDA: $40 million for the second quarter, reflecting the mid-May closing date on the sale of the Canadian NGL business. Leverage Ratio: Pro forma leverage ratio of 3.3 times at the end of the second quarter, reflecting approximately $2.9 billion of debt reduction from the NGL divestiture. Growth Capital Spending (2026): Increased from $350 million to a range of $400 million to $450 million. Maintenance Capital (2026): Decreased to $175 million, largely due to the timing of the NGL sale. Free Cash Flow (2026): Expected to generate approximately $1.75 billion. Permian Production Growth (2026): Expected to be approximately 100,000 to 200,000 barrels per day on an exit-to-exit basis versus 2025. Cactus Pipeline Expansion: Sanctioned a capital-efficient expansion adding 75,000 barrels per day, bringing total capacity to 725,000 barrels per day. One-off Expenses: Second quarter results include approximately $14 million of one-off environmental remediation expenses. Cost Savings: Expect to realize $50 million of deficiencies by year-end 2026, with an additional $50 million by the end of 2027. Warning! GuruFocus has detected 11 Warning Signs with PAGP. Is PAGP fairly valued? Test your thesis with our free DCF calculator. Release Date: August 07, 2026 For the complete transcript of the earnings call, please refer to the full earnings call transcript. Plains GP Holdings LP (NASDAQ:PAGP) reported second-quarter adjusted EBITDA of $738 million, on track to meet its full-year 2026 guidance of $2.88 billion. The company successfully closed the sale of its Canadian NGL business, reducing leverage to 3.3 times and strengthening its balance sheet. Increased 2026 growth capital spending to $400-$450 million for high-return, quick-hit projects, including Permian gathering expansions and a capital-efficient Cactus Street pipeline expansion. Raised Permian production growth forecast to 100,000-200,000 barrels per day exit-to-exit for 2026, driven by earlier-than-expected natural gas egress, creating momentum into 2027. Expects to capture $50 million in cost efficiencies by year-end 2026 and an additional $50 million by the end of 2027, enhancing operational streamlining. Generated approximately $1.75 billion in free cash flow in 2026, allowing for significant capital returns to unit holders while maintaining financial flexibility. Identified additional organic investment opportunities in Canada, including expansions in the Clearwater and DuVernay formations, backed by producer commitments. The macro environment remains volatile due to Middle East conflicts and supply disruptions from the Strait of Hormuz, creating uncertainty in oil markets. Second-quarter results included approximately $14 million in one-off environmental remediation expenses, impacting quarterly earnings. The company left its 2026 EBITDA guidance unchanged despite higher volume outlook, as the benefits are expected to materialize more significantly in 2027. Pipeline loss allowance revenue is only 70% hedged for the balance of the year at an average WTI price around $62, leaving exposure to price fluctuations. Future Cactus Street expansion phases will take longer to sanction and require customer commitments, with costs potentially higher than the initial phase. The NGL segment's adjusted EBITDA of $40 million reflects the mid-May sale closing, and the company will remove NGL segment reporting in the third quarter, simplifying but reducing segment diversity. Q: Can you discuss the sustainability of the revised $400-$450 million growth capital expenditure level into 2027 and beyond, given the mix of Canadian, Permian, and Cactus projects?A: Chris Chandler, COO: The 2026 increase is driven by typical 18-24 month projects, so spending will carry into 2027 and potentially 2028. We do not expect 2027 to look significantly different from 2026, though it is trending slightly higher than our historical $300-$400 million range. Formal 2027 guidance will be provided in early 2027. Q: How quickly will the Cactus 75,000 barrel-per-day expansion be filled, and can you continue to add these bite-sized expansions before needing a larger project?A: Jeremy Goebel, Chief Commercial Officer: Our marketing affiliate can fill the space immediately to capture current market volatility. The long-term goal is to contract the capacity on a term basis. The expansion was executed quickly and capital-efficiently due to market volatility and growing production. We continue to evaluate similar capital-efficient opportunities. Q: Why did you raise the Permian production growth forecast to 100,000-200,000 barrels per day but leave 2026 EBITDA guidance unchanged?A: Al Swanson, CFO: The second quarter EBITDA of $690 million was a significant increase from Q1. Our guidance midpoint for the second half is above that, in the low $700 million range, which already models a strong exit to the year. The increased production volumes primarily set up momentum for 2027 rather than providing upside to the current year's guidance. Q: How do you balance adding incremental Cactus capacity against maintaining a tighter market that could benefit recontracting rates?A: Jeremy Goebel, Chief Commercial Officer: The 75,000 barrels per day expansion will not change the overall market dynamics, as production growth is substantially higher. The project is highly capital-efficient with strong returns. The existing Cactus pipelines are well-contracted, and this expansion does not impact our ability to contract at strong rates. The volatility also presents opportunities to pay for the expansion quickly. Q: Can you provide a progress update on capturing the $50 million of cost efficiencies in 2026 and the additional $50 million planned for 2027?A: Chris Chandler, COO: We have made good progress, realizing a little less than half of the $50 million target year-to-date. The NGL sale was a catalyst, but not the only driver. Efficiencies come from streamlining organizational structure, reducing leadership roles, rightsizing the trucking business, and consolidating marketing offices. We are on track to capture the remaining amount in 2026 and the additional $50 million in 2027. Q: What are the moving pieces for Canadian gathering system expansions, and what is the timing and potential size of the Rangeland capacity?A: Jeremy Goebel, Chief Commercial Officer: Rangeland expansions are filling latent capacity, while Rainbow involves expanding mainline capacity and building laterals. We will first look to fill existing egress on Moscana and Rangeland. There may be more capital-efficient projects to work on with counterparties around Cushing and other locations. A Rangeland expansion would likely not be competitive with larger egress projects based on scale. Q: Given the recent market volatility, has the commercial organization's performance exceeded expectations, and can you provide specific examples of captured opportunities?A: Willie Chiang, CEO: Our team has performed well, achieving record crude exports out of the Gulf Coast in Q2. We have captured value around the shape of the forward curve and sourced barrels to facilitate movement. Additionally, discussions with producer partners on their pinch points have set up new capital projects. We also have some unhedged pipeline loss allowance barrels that could provide upside for the rest of the year. Q: How do you view the impact of growing Venezuelan heavy barrels in the Gulf Coast and potential Canadian egress expansions on heavy differentials and marketing opportunities?A: Jeremy Goebel, Chief Commercial Officer: The pace of growth in Canada and Venezuela will dictate the impact. If Venezuelan barrels push back Canadian barrels and widen differentials, there are spreads to capture. The timing of Canadian egress additions and sustained Venezuelan production growth are key variables. Any dislocation creates opportunities for our team, but our preference is to move barrels first. Willie Chiang added that Venezuelan barrels were originally designed for the Gulf Coast, and their presence pushes other barrels back, creating more opportunities. Q: What are your views on Permian rig count and the potential for accelerated crude volumes, possibly approaching 8 million barrels per day?A: Jeremy Goebel, Chief Commercial Officer: Gas egress has come online quicker than expected, and plants are filling up. We have a positive bias on volumes based on recent trends. Productivity has improved, making current rigs more efficient. A path to north of 7 million barrels per day is favorable, but reaching 8 million requires continued improvements in recoveries, lower breakeven prices, and supportive commodity prices. Willie Chiang noted that producers are touting the ability to produce more efficiently. Q: Is there a specific oil price for 2027 that would make producers more active?A: Jeremy Goebel, Chief Commercial Officer: It is less about price and more about activity. Operators are discussing deeper benches in the Midland Basin and continued expansion in New Mexico, both vertically and horizontally. The basin continues to expand its resource base, which is exciting as it sits under our footprint. For the complete transcript of the earnings call, please refer to the full earnings call transcript.

HOUSTON, July 06, 2026 (GLOBE NEWSWIRE) -- Plains All American Pipeline, L.P. (Nasdaq: PAA) and Plains GP Holdings (Nasdaq: PAGP) announced today their quarterly distributions with respect to the second quarter of 2026 and also announced timing of second quarter 2026 earnings. Second Quarter Distribution Declaration PAA and PAGP announced the following quarterly cash distributions, each of which will be payable on August 14, 2026, to holders of the respective securities at the close of business on July 31, 2026: PAA Common Units – $0.4175 per Common Unit ($1.67 per unit on an annualized basis), which is unchanged from the distribution paid in May 2026. PAGP Class A Shares – $0.4175 per Class A Share ($1.67 per Class A Share on an annualized basis), which is unchanged from the distribution paid in May 2026. PAA Series A Preferred Units – $0.61524 per Series A Preferred Unit (approximately $2.46 per unit on an annualized basis). For its Series B Preferred Units, PAA announced a quarterly distribution of $20.50 per Series B Unit (based on the applicable quarterly floating rate), which will be payable on August 17, 2026, to holders of record at the close of business on August 3, 2026. Although equity holders should consult their own tax advisor regarding their particular circumstances, following the close of the NGL asset sale, it is possible that PAGP will report positive current earnings and profits for the Tax Year 2026, making part of its Class A Share cash distribution taxable as a dividend. The transaction is not estimated to result in a material change in the previous forecast regarding when routine PAGP distributions will shift from being a return of capital to being taxed as dividends or when PAGP will become a taxpaying entity. Following payment of quarterly distributions, Plains will publish Form 8937, Report of Organizational Actions Affecting Basis of Securities to clarify the expected portion of the quarterly distribution that will be taxed as a dividend. In addition, to the extent any cash distribution exceeds a Class A Shareholder’s tax basis, it should be taxable as a capital gain. Qualified Notices under Treasury Regulation Section 1.1446 with respect to the PAA Common Unit distribution and PAA Series B Preferred Unit distribution will be posted on the Plains website under “Investor Relations – Unit Information.” Second Quarter 2026 Earnings Timing PAA and PAGP also announced that they will release second quarter 2026 earnings before market open on Friday, August 7, 2026. Following the announcement, PAA and PAGP will host a conference call at 9:00 a.m. CT (10 a.m. ET) with analysts and investors to discuss earnings. The call will be webcast live on the internet and may be accessed through the "Investors Relations” section of the website at www.plains.com. An audio replay will be available on the website after the call. About Plains PAA is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services primarily for crude oil. PAA owns an extensive network of pipeline gathering and transportation systems, in addition to terminalling, storage, and other infrastructure assets serving key producing basins, transportation corridors and major market hubs and export outlets in the United States and Canada. PAGP is a publicly traded entity that owns an indirect, non-economic controlling general partner interest in PAA and an indirect limited partner interest in PAA, one of the largest energy infrastructure and logistics companies in North America. PAA and PAGP are headquartered in Houston, Texas. More information is available at www.plains.com. Investor Relations Contacts:Blake FernandezRoss [email protected](866) 809-1291

Our analysts just identified a stock with the potential to be the next Nvidia. Tell us how you invest and we'll show you why it's our #1 pick. Tap here. Management increased 2026 EBITDA guidance by $130 million, citing a constructive oil macro environment driven by global destocking and the closure of the Strait of Hormuz. The NGL segment outperformed expectations by $45 million in Q1 due to higher straddle production from increased border flows and improving frac spreads in March. Crude oil segment performance was impacted by temporary headwinds, including winter weather in the Permian, system maintenance, and the timing of minimum volume commitments. Strategic positioning as a pure-play crude midstream company is intended to capture value as North America becomes a critical source for global energy security. The acquisition of Cactus III last year is providing timely tax mitigation for unitholders regarding the NGL divestiture, eliminating the need for a previously anticipated special distribution. Operational growth is currently paced by three core initiatives: the NGL asset sale, Cactus III synergy capture, and organizational streamlining. Guidance assumes Permian crude production remains relatively flat for 2026, with potential upside in 2027 as natural gas takeaway constraints are resolved later this year. Management expects a 'restocking phenomenon' longer term as countries replenish strategic petroleum reserves, potentially above prewar levels, supporting sustained demand. The NGL divestiture is expected to close in May 2026 with net proceeds of approximately $3.3 billion, roughly $100 million higher than prior estimates. Leverage is projected to migrate toward the low end of the 3.25x to 3.75x target range by year-end 2026 following debt repayment from sale proceeds. Future capital allocation will prioritize distribution growth, organic investments, and potential preferred unit repurchases once leverage targets are secured. The Competition Bureau is challenging the pending transaction with Keyera, though management stated this does not legally prevent the parties from closing this month. Current and deferred taxes appeared elevated this quarter due to restructuring activities associated with the NGL sale, though there was no cash tax impact in Q1. Permian production faces a near-term 'throttle' due to natural gas takeaway limits and flaring restrictions, which may delay the impact of recent rig additions. Management identified approximately 200,000 to 300,000 barrels per day of oil 'behind pipe' in the Permian Basin awaiting infrastructure relief. One stock. Nvidia-level potential. 30M+ investors trust Moby to find it first. Get the pick. Tap here. Management clarified that Q1 and the 2026 guide are minimally impacted by current $85 pricing because the company was highly hedged at $60 to $65 levels entering the year. Incremental upside to the crude segment exists for the second half of the year if the elevated commodity environment persists beyond current captured optimizations. While 15 rigs have been added recently, producers likely require more assurance on the back end of the curve (prices above $75) before significantly increasing activity. Physical crude markets are currently tighter than financial markets indicate, suggesting the back end of the curve must rise to incent further production. Expansion of Cactus III will be paced with market demand and commercial contracts rather than as a single binary project. The asset offers a flexible, phased approach to adding volume, which management believes is well-suited for the current volatile market environment. The company remains on track to capture $50 million in efficiencies by 2026 and an additional $50 million in 2027. Efforts include both general organizational changes and specific adjustments made in anticipation of the NGL transaction.

Image source: The Motley Fool. Friday, May 8, 2026 at 10 a.m. ET Chairman, President, and Chief Executive Officer — Willie Chiang Executive Vice President and Chief Financial Officer — Al Swanson Executive Vice President and Chief Commercial Officer — Jeremy L. Goebel Executive Vice President and Chief Operating Officer — Christopher R. Chandler Senior Vice President, Investor Relations and Communications — Blake Michael Fernandez Need a quote from a Motley Fool analyst? Email [email protected] Willie Chiang: Thank you, Blake. Good morning, everyone, and thank you for joining us. This morning, we reported first quarter adjusted EBITDA attributable to Plains GP Holdings, L.P. of $730 million. Al will cover the details on our results in his portion of the call. Let me start with the macro environment, which has changed significantly since our last call. Recent geopolitical events have reiterated the importance of reliable, secure, and responsibly produced energy. The closure of the Strait of Hormuz has significantly disrupted global shipping channels and Middle East supply, contributing to stronger commodity prices over the past couple of months. In response, excess floating storage has been drawn down, and strategic petroleum reserves are being released globally. While this helps balance the market deficit on a short-term basis, we are seeing a more constructive oil market developing on a longer-term basis. We expect this destocking environment to continue over the next number of months and ultimately drive a restocking phenomenon longer term as countries replenish depleted strategic petroleum reserves globally. Postwar, we would not be surprised to see several countries restock their SPRs above prewar levels, essentially creating an additional layer of demand into the future, which should support prices and incent producer activity. On the supply side, OPEC production capacity postwar remains uncertain, but we suspect spare capacity will be tighter based on a slower recovery of shut-in production and infrastructure damage during the war. We believe the conflict shifts the focus towards more geopolitically stable regions to ensure security of supply. Against this backdrop, North America, including the Permian, remains well positioned to play a critical role in meeting global demand. As this occurs, the value of existing infrastructure in the ground should continue to increase over time. For these reasons, we believe Plains GP Holdings, L.P. is well positioned for both the near-term volatility and longer-term macro environment. Based on these market dynamics and the growth trajectory that we see for our business, we have increased our initial 2026 EBITDA guidance. As highlighted on slide four, we are increasing the midpoint of our full-year 2026 adjusted EBITDA guidance by $130 million to $2.88 billion. The NGL segment EBITDA is now expected to be $170 million this year, following first quarter outperformance of $45 million and the updated divestiture timing now in May 2026. Our trajectory of growth this year is underpinned by three key drivers: the sale of our NGL assets, Cactus III synergy capture and streamlining. The growth of our EBITDA is paced with the execution of these initiatives and is enhanced by capturing optimization opportunities that have been substantially secured over the next three quarters. We are also seeing increased producer interest in both Canada and the United States for additional connections to our system. The combination of all these factors will ramp up through the year and position us well into the future. Our premier crude oil footprint continues to support stable fee-based cash flows in a variety of macro backdrops. As global markets turn to North America for long-term energy supply, we are well positioned across key producing basins and downstream markets to drive multiyear growth. We remain committed to our efficient growth strategy, generating significant free cash flow, optimizing our assets, maintaining a flexible balance sheet, and continuing to return cash to unitholders via our disciplined capital allocation framework. With that, I will turn the call over to Al to cover our quarterly performance and other financial matters. Al Swanson: Thanks, Willie. Slides five and six contain adjusted EBITDA walks that provide additional details on our performance. For the first quarter, we reported crude oil segment adjusted EBITDA of $582 million, which was broadly in line with our internal estimate and includes a full-quarter contribution from the Cactus III acquisition, offset by a number of one-off items, including winter weather impact in the Permian, system maintenance, and timing of minimum volume commitments. Moving to the NGL segment, we reported adjusted EBITDA of $145 million, reflecting a stronger-than-expected contribution from higher straddle production and improving frac spreads in March. A summary of 2026 guidance and key assumptions are on slide seven. Growth capital remains $350 million while maintenance capital was increased to $185 million reflecting ownership of the NGL assets into May. Regarding the $130 million increase in EBITDA guidance, key drivers are outlined in the waterfall on slide eight. The NGL segment increased by $70 million, driven by outperformance in the first quarter along with the ownership of NGL assets into May. The oil segment was increased by $60 million, driven by captured optimization opportunities, FERC tariff escalators, increased spot tariff volumes, and increased West Coast volumes. To the extent that the elevated commodity environment persists into the second half of the year, we would expect to capture incremental opportunities. For 2026 guidance, we continue to assume Permian crude oil production to be relatively flat year over year. While we have yet to see a meaningful shift in U.S. producer behavior, any increase in activity would likely benefit 2027 and beyond. We expect an improving back end of the crude oil curve and removal of natural gas takeaway constraints as new egress projects start up later this year to drive incremental activity throughout the year. Illustrated on slide nine, we remain committed to generating significant free cash flow and returning capital to unitholders while maintaining financial flexibility. For 2026, we expect to generate approximately $1.85 billion of adjusted free cash flow excluding changes in assets and liabilities, and excluding sales proceeds from the NGL divestiture. Our pro forma leverage at the end of the first quarter was 4.1x, reflecting the Cactus III acquisition. First quarter leverage pro forma for the NGL sale would decrease to approximately 3.5x, and we would expect leverage to migrate towards the low end of our target range of 3.25x to 3.75x by the end of the year. We expect net proceeds from the NGL sale to be approximately $3.3 billion, which is approximately $100 million higher than our prior estimate. Our acquisition of Cactus III last year has mitigated the tax liability of the unitholders resulting from the NGL divestiture. As a result, we no longer expect to pay a special distribution following the closing of the NGL sale. Before handing it back to Willie, I would note that both current and deferred taxes are elevated on the statement of operations this quarter because of the restructuring activities associated with the NGL sale. There was no cash tax impact in the quarter, as payment of the related taxes will be made in conjunction with closing or in future periods. With that, I will turn the call back to Willie. Willie Chiang: Thanks, Al. In the midst of volatile energy markets, we remain steadfast and focused on our three initiatives for 2026: closing the NGL sale, driving synergies on Cactus III, and advancing our streamlining initiatives. Our efficient growth strategy has positioned us well to execute through a range of market environments, generating durable cash flow and creating long-term value. Importantly, the improving oil macro environment is starting to present additional organic investment opportunities with strong returns. We continue to evaluate both organic and inorganic opportunities in a disciplined manner. Capital investments help underpin long-term EBITDA growth, but they must meet our return thresholds and provide visibility into future return of capital to unitholders. Our transition to a pure-play crude midstream company, coupled with the acquisition of Cactus III, is proving timely, as tensions in the Middle East position North America as a key source of global energy supply into the future. Before I turn the call over to Blake, I would like to make a brief comment about our pending transaction with Keyera. In terms of timing, as reported by both Keyera and Plains GP Holdings, L.P. in separate releases earlier this week, we are targeting to close the transaction this month. While it is unfortunate that the Competition Bureau has chosen to challenge the transaction, their lawsuit does not prevent the parties from closing the transaction, which both Plains GP Holdings, L.P. and Keyera are committing to do. I realize you may have some additional questions, but I hope you understand it would be inappropriate for us to comment any further on this matter, so we would appreciate it if you would refrain from asking questions regarding the transaction. Blake, I am now going to turn it over to you to lead us through Q&A. Blake Michael Fernandez: Thanks, Willie. As we enter the Q&A session, please limit yourself to two questions. This will allow us to address as many questions as possible from participants in our available time this morning. With that, Michelle, we are ready for questions. Operator: Thank you. If your question has been answered and you would like to remove yourself from the queue, please press 11 again. Our first question comes from Brandon B. Bingham with Scotiabank. Your line is open. Brandon B. Bingham: Thanks. Good morning, everybody. Just wanted to ask on the new guide. If I look at your sensitivity and the new crude price expectations, it would imply that, at least on price movements alone, the crude contribution should probably be higher than what is currently shown. Could you just walk us through what is baked into the new guide and maybe the embedded outlook in there? And, in light of some of the commentary in your prepared remarks about a more constructive longer-term market and the macro environment as it stands today, how are you thinking about the potential for the EPIC expansion at this point? Al Swanson: Sure, Brandon. Yes, our original guidance for the year assumed a $60 to $65 environment for 2026, call it a $62 average. We came into the year highly hedged at roughly those levels. The $85 environment that we are talking about for the future is roughly the strip from June through December when we looked at it. So there would be some benefit based on crude prices on our PLA, but we had hedged quite a bit before entering the year. That sensitivity we give is just a raw sensitivity; in order to make it more meaningful, we would have had to have disclosed the hedge position at the beginning of the year, which we have not historically done. So what I would say is that the first quarter performance and the nine months of our guide are very minimally impacted by actual PLA pricing. Jeremy L. Goebel: Brandon, good morning. We are excited about the opportunities around our entire long-haul portfolio and are having constructive dialogue with existing customers and new customers looking for secure supply from the United States. That results in some spot activity, but longer term, the expectation is to contract at higher rates than before with potentially new counterparties. That would apply to recontracting the existing pipeline capacity and expansions as well. We are looking at all of the above and hope to have updates in the coming quarters on how that looks. Operator: Our next question comes from Gabriel Philip Moreen with Mizuho. Your line is open. Gabriel Philip Moreen: Hey, good morning, everyone. Maybe I will just ask the Permian macro question, Willie, in terms of your best outlook. I think previous years you had talked about roughly 200,000 barrels a day year-over-year growth. Best venture at this point—do you think that goes significantly higher from here, 400,000, 500,000 in 2027? I am just curious what your latest thoughts are there. And then, can you talk about the sustainability of some of the marketing opportunities you are currently seeing—spreads, the value of dock space, whether you are debating terming some of those out at higher prices—and how the steepness of the curve and backwardation are impacting your storage? Willie Chiang: Gabe, the U.S. producers have remained very disciplined as far as capital allocation, and they are looking at the back end of the curve to see where it goes. WTI is roughly $70, and our view is when you start getting into $75 and above, increased activity happens. There are also some other short-term operating constraints limiting production a bit. The Permian has some natural gas takeaway constraints. There are new lines being built and being commissioned as early as later this year, so the thought is that alleviates itself. Our assumption for the Permian this year was flat, and if there is some upside, obviously, we benefit from it. We are not giving a formal guide, but we would expect growth going forward and probably some momentum of volumes behind that which is going to increase production here, maybe with a little bit of a flush later this year. So I think it really depends on the back end of the curve, but the systems are ready to go. Jeremy L. Goebel: Gabe, without getting into specific strategies—time, location, quality spreads and volatility—we benefit from all of those because we have the assets, the supply position, and the trading function to capture those opportunities. While it is hard to forecast those, when they arrive we can take advantage by, for example, selling a barrel now and buying it back later by emptying a tank, or capturing differences in grades between Canada and the United States and across Gulf Coast grades. We are excited about those opportunities. What we have put in the forecast has been substantially captured. It is a very volatile time period; we have only been in this 60 to 70 days, so it is hard to forecast that to continue. But if it continues, we would expect to capture more opportunities going forward. We also estimate there is close to 200,000 to 300,000 barrels per day of oil behind pipe in the Permian Basin. That flush production is substantial, and a lot of that is in the more constrained areas of the Delaware Basin, where we have a broader footprint, including New Mexico and other places. If you look at the Waha spread, flat price in Waha has been largely negative since last September; that is what is accumulating all of this behind pipe. As gas prices recover, productive capacity is already there to add. As you add more, that puts more pressure on potentially long-haul spreads and the ability to term up contracts at greater rates. We are seeing more demand from new customers, and we are seeing potentially flushed production. Those should all help convert short-term opportunities into longer-term opportunities. Willie Chiang: If you look at our numbers, long haul has increased and the margins on that have also improved. I think we are moving to a more structurally full-pipe situation as we go forward, which should be constructive for us. Operator: Our next question comes from Manav Gupta with UBS. Manav Gupta: Good morning. I just wanted to focus a little bit on the weather impact. I think it was about $49 million quarter over quarter. I am trying to understand the timing of minimum volume commitments. Is there a possibility some of this can be reversed in 2Q—some of what you lost in the current quarter comes back into the second quarter? And if you could also talk about the very strong NGL segment in the first quarter versus the last quarter—some of the drivers that helped you deliver much stronger earnings in that segment quarter over quarter? Al Swanson: Yes, Manav. Those are two different things. First, with regard to weather, weather is just production shut in for a period. You cannot make that back, but the flush production does come back. With regard to the timing of MVCs, that is continuous in our process. If you look at some of the earnings calls from others about their dock performance or other things in the first quarter, freight was really expensive and margins did not have people moving, so long-haul volumes were down across the industry. But that has completely reversed in timing, so you would absolutely expect that to be recovered. It is just a question of those MVCs accrued versus when they are paid. All the pipelines are full again, and the MVCs are being reversed. If you are referring to slide five, there are a bunch of one-time events in that negative $49 million that will not occur again as we go forward. Jeremy L. Goebel: On the NGL segment, higher border flows than expected drove stronger results. You had very full storage in Canada and continued production, which required volumes to be exported. Those were exported through our Empress asset, so higher border flows led to more straddle production, and that would all be unhedged and impact results. We also saw higher frac spreads toward the end of the first quarter. Those two factors continued into the second quarter, which is reflected in the increase in guidance for the NGL business through closing. Operator: Our next question comes from Michael Jacob Blum with Wells Fargo. Michael Jacob Blum: Thanks. Good morning, everyone. My question is on the guidance for the crude segment. It sounds like most of the increase is optimization that you have already locked in, and then maybe the rest is PLA. Is that right? And if prices stay elevated for the balance of the year, would there be upside to the crude segment guide, or is that already baked into the numbers? Willie Chiang: Michael, great question. Our assumptions are that the numbers in there are what we have captured that roll off through the year that we will actualize on optimization efforts. You are correct. If we have a stronger macro environment and higher prices, there definitely is upside. Michael Jacob Blum: Great. Thank you. Operator: Our next question comes from Jeremy Tonet with JPMorgan Securities. Your line is open. Jeremy Tonet: Hi. Good morning. What are you seeing locally, ear to the ground, as far as producer activity—rigs being picked up by the independents or larger drillers—and what would need to be seen across the strip to gain the comfort to do that? How do you think production could uptick here, and what do you see? And how do you think that impacts basis over time and what it could mean for future egress expansion? Jeremy L. Goebel: Jeremy, good morning. Since this started, you have already seen about 15 rigs added back, and we would expect some to continue. But as Willie mentioned, there is a bit of a throttle right now: you cannot add more natural gas to the system and flaring is not allowed. Productive capacity is there; rigs being added now would impact 2027. There is a bit of confusion in the market in that the products market and the physical crude market are substantially tighter than the financial markets would indicate, which means the back end of the curve has to come up. It is very difficult, even if you opened the Strait of Hormuz tomorrow, to get everything back in order the way it was. It will take a while for shipping to start; you have to empty tanks before you start back up production. Products markets are empty in some places. There is real dislocation that will take time. Some integrators have stated it is roughly three days to get back up for every day it is down, so it is potential for months to get out of this even if it were resolved today. Producers likely need more assurance on the back end of the curve before bringing rigs on. Service companies have stacked equipment; it takes capital and commitments to bring that back in. The longer this goes, the more likely that will occur, but the current dislocation on the back end of the curve is causing some hesitancy, and that prolongs the problem. On basis and egress, it is constructive for basis—more production and more demand on the water. Specifically to the Corpus market and some of the efficient docks on the water, you are seeing higher pricing relative to the screen. On a prolonged basis, that suggests new buyers coming to America and vessels re-pointed to the United States for a while. You are seeing that on the NGL side; you will see it on LNG and on crude. More buyers and more demand are generally constructive for spreads, and we would expect to match either our supply or our customers with that and hopefully offer service at a higher rate. Willie Chiang: On Cactus III, we have expansion capacity. As we have always said, we will pace that with market demand and commercial contracts. As we have gotten to know the project and assessed it, we have the ability to do that in a phased approach. It is fairly flexible for us to get additional volumes; it is not a binary big expansion. There are ways to do it in phases which should match customer demand. Generally speaking, in a higher price environment, there are more opportunities because there is a pull on the whole system. In that kind of market, market and optimization opportunities become more prevalent versus a lower price environment where less is moving and there are fewer opportunities. Operator: Our next question comes from Analyst with Goldman Sachs. Your line is open. Analyst: Hi, good morning. Thank you so much for the time. First, could you comment on the progress of your cost reduction initiatives? Are these on track with expectations at this point, and is there any potential for upside capture here? When should we expect Plains GP Holdings, L.P. to realize more significant efficiencies through the year? And then shifting to capital allocation—with debt reduction as a near-term focus, particularly following the pending NGL sale—when do we expect a shift from debt paydown to a larger focus on potential buybacks or preferred paydowns? Christopher R. Chandler: Good morning. We are on track to capture the efficiencies—$50 million by 2026 and an additional $50 million in 2027. We have already made a number of changes, some unrelated to the NGL transaction and some in anticipation of the NGL transaction. We feel confident in the number. There is always upside; we are always looking for additional opportunities and we will certainly pursue any that we find. We are not prepared at this time to change the $100 million target we have through 2027, but we are on track and things are going well. Al Swanson: On capital allocation, with the proceeds from NGL, we anticipate paying down a little over $3 billion of debt, which would be the term loan, the outstanding CP we have, and a $750 million note that matures later this year. Post that, we expect to be right at the midpoint of our leverage range, about 3.5x, and expect that to migrate down toward the low end, which will put us back where we were for several years prior to the EPIC acquisition—leverage toward the low end of our range. Our capital allocation priorities remain: maintaining distribution growth; funding investments, whether organic or M&A-related; taking out preferreds should leverage remain at or below the bottom end of the range; and opportunistic share repurchases. So once we get through the NGL sale and deploy the proceeds, we return to the framework we have been operating under for the last several years. Operator: Thank you. I am showing no further questions at this time. I would like to turn the call back over to Willie Chiang, President, CEO and Chairman, for closing remarks. Willie Chiang: Michelle, thanks. We appreciate everyone’s support and attention, and we look forward to seeing you on the roads. Stay safe. Thank you very much. Operator: Thank you for your participation. You may now disconnect. Everyone, have a great day. Before you buy stock in Plains Gp, consider this: The Motley Fool Stock Advisor analyst team just identified what they believe are the 10 best stocks for investors to buy now… and Plains Gp wasn’t one of them. The 10 stocks that made the cut could produce monster returns in the coming years. 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As with all our articles, The Motley Fool does not assume any responsibility for your use of this content, and we strongly encourage you to do your own research, including listening to the call yourself and reading the company's SEC filings. Please see our Terms and Conditions for additional details, including our Obligatory Capitalized Disclaimers of Liability. The Motley Fool has no position in any of the stocks mentioned. The Motley Fool has a disclosure policy. Plains GP (PAGP) Q1 2026 Earnings Transcript was originally published by The Motley Fool

HOUSTON, May 08, 2026 (GLOBE NEWSWIRE) -- Plains All American Pipeline, L.P. (Nasdaq: PAA) and Plains GP Holdings (Nasdaq: PAGP) today reported first-quarter 2026 results and raised full-year 2026 Adjusted EBITDA Guidance. First-Quarter 2026 Results First-quarter Net income attributable to PAA of $152 million and Net cash provided by operating activities of $418 million Delivered first-quarter Adjusted EBITDA attributable to PAA of $730 million Pro forma leverage ratio of 4.1x at quarter-end; expect to return toward the midpoint of the target range of 3.25 to 3.75x following closing of the NGL divestiture and migrating toward lower-end of the range by year-end Paid a quarterly cash distribution of $0.4175 per unit ($1.67 per unit annualized), representing a current distribution yield of ~7.5% 2026 Updated Outlook Increasing midpoint of full-year 2026 Adjusted EBITDA guidance attributable to PAA by $130 million to $2.880 billion +/- $75 million (reflecting a strong oil macro environment and NGL contribution into May 2026) Growth capital remains $350 million with maintenance capital increasing to $185 million, reflecting ownership of NGL assets into May 2026 Full-year 2026 Adjusted Free Cash Flow guidance increased to approximately $1.850 billion (excluding changes in Assets & Liabilities and anticipated cash proceeds from the NGL divestiture) “Global events this year illustrate the importance of reliable, secure and responsibly produced energy and have accelerated the timing of our view for a more constructive crude oil market. Our integrated business model and asset base connecting U.S. crude production to the global markets are critical to meeting global energy demand. As a result, we are increasing the midpoint of our 2026 Adjusted EBITDA guidance by $130 million to reflect a constructive oil macro environment and extended ownership of our Canadian NGL business into May. The closing of the NGL divestiture will mark a transition to a premier pure play crude oil midstream provider. We remain focused on executing key initiatives in 2026, including closing the pending NGL sale and realizing $100 million of contribution between Cactus III synergies and capturing efficiencies across our system. The combination of these internal initiatives coupled with a healthy oil macro backdrop positions Plains with momentum into 2027 and beyond. Finally, we remain committed to financial discipline and maintaining a strong balance sheet, while continuing to return capital to unit holders,” said Willie Chiang, Chairman, CEO and President. Financial Reporting Considerations for Pending Sale of Canadian NGL Business On June 17, 2025, we entered into a definitive agreement to sell substantially all of our NGL business in Canada (the “Canadian NGL Business”) to Keyera Corp. This transaction is expected to close in May 2026. As part of the sale, we will divest the Canadian NGL Business, which includes substantially all of our NGL assets; the NGL assets that we will retain are located in the United States. We have determined that the operations of the Canadian NGL Business meet the criteria for classification as held for sale and for discontinued operations reporting and have applied these changes retrospectively to all periods presented. Results throughout this release specify if they are presented from continuing operations (which exclude the results of the Canadian NGL Business) and/or discontinued operations. Plains All American Pipeline Summary Financial Information (unaudited) (in millions, except per unit data) ________________________________ ** Indicates that variance as a percentage is not meaningful. (1) Includes results from continuing operations and discontinued operations for all periods presented. See the tables attached hereto for additional information. (2) Excludes amounts attributable to noncontrolling interests in the Plains Oryx Permian Basin LLC (the “Permian JV”), Cactus II Pipeline LLC and Red River Pipeline LLC joint ventures. (3) See the section of this release entitled “Non-GAAP Financial Measures and Selected Items Impacting Comparability” and the tables attached hereto for information regarding our Non-GAAP financial measures, including their reconciliation to the most directly comparable measures as reported in accordance with GAAP, and certain selected items that PAA believes impact comparability of financial results between reporting periods. (4) For the three months ended March 31, 2025, includes the impact of a net cash outflow of $624 million for bolt-on acquisitions. (5) For the three months ended March 31, 2026, amount excludes approximately $216 million of current income tax expense associated with certain planning and restructuring activities within our organizational structure in connection with the pending Canadian NGL Business divestiture that had income tax consequences that required recognition during the first quarter of 2026. Disaggregation of Adjusted EBITDA by Product (1) (2) (unaudited) (in millions) ________________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) See the section of this release entitled “Non-GAAP Financial Measures and Selected Items Impacting Comparability” and the tables attached hereto for information regarding our Non-GAAP financial measures, including their reconciliation to the most directly comparable measures as reported in accordance with GAAP, and certain selected items that PAA believes impact comparability of financial results between reporting periods. First-quarter 2026 Adjusted EBITDA from Crude Oil increased 4% versus comparable 2025 results. Favorable results in the 2026 period from (i) contributions from recently completed bolt-on acquisitions, including our Cactus III pipeline acquisition, and (ii) higher volumes on our pipelines were partially offset by the impact of (iii) certain Permian long-haul pipeline contract rate resets. First-quarter 2026 Adjusted EBITDA from NGL decreased 23% versus comparable 2025 results primarily due to lower weighted average frac spreads and reduced sales volumes from warmer weather. Plains GP Holdings PAGP owns an indirect non-economic controlling interest in PAA’s general partner and an indirect limited partner interest in PAA. As the control entity of PAA, PAGP consolidates PAA’s results into its financial statements, which is reflected in the condensed consolidating balance sheet and income statement tables attached hereto. Conference Call and Webcast Instructions PAA and PAGP will hold a joint conference call at 9:00 a.m. CT on Friday, May 8, 2026 to discuss first-quarter performance and related items. To access the internet webcast, please go to https://edge.media-server.com/mmc/p/3u4m5omt/lan/en/. Alternatively, the webcast can be accessed on our website at https://ir.plains.com/news-events/events-presentations. Following the live webcast, an audio replay will be available on our website and will be accessible for a period of 365 days. Slides will be posted prior to the call at the above referenced website. Non-GAAP Financial Measures and Selected Items Impacting Comparability 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 and to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. The primary additional measures used by management are Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied Distributable Cash Flow (“DCF”), Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions. Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied DCF and certain other non-GAAP financial performance measures are reconciled to Net Income, and Adjusted Free Cash Flow, Adjusted Free Cash Flow after Distributions and certain other non-GAAP financial liquidity measures are reconciled to Net Cash Provided by Operating Activities (the most directly comparable measures as reported in accordance with GAAP) for the historical periods presented in the tables attached to this release, and should be viewed in addition to, and not in lieu of, our Consolidated Financial Statements and accompanying notes. In addition, we encourage you to visit the Investor Relations section of our website at www.plains.com (navigate to the “Financials” tab, then click on “Quarterly Results”), which presents a reconciliation of our commonly used non-GAAP and supplemental financial measures. We do not reconcile non-GAAP financial measures on a forward-looking basis as it is impractical to do so without unreasonable effort. Non-GAAP Financial Performance Measures Adjusted EBITDA is defined as earnings from continuing operations and discontinued operations before (i) interest expense, (ii) income tax (expense)/benefit from continuing operations and discontinued operations, (iii) depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities) from continuing operations and discontinued operations, (iv) gains and losses on asset sales, asset impairments and other, net from continuing operations and discontinued operations, (v) gains on investments in unconsolidated entities, net and (vi) interest income on promissory notes by and among certain Plains entities, and (vii) adjusted for certain selected items impacting comparability. Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests. Adjusted EBITDA disaggregated by product (e.g., Adjusted EBITDA from Crude Oil and Adjusted EBITDA from NGL) excludes amounts related to Other income/(expense). Management believes that the presentation of Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF 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 operating performance and ability to fund distributions to our unitholders through cash generated by our operations and (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions. We also present these and additional non-GAAP financial measures, including adjusted net income attributable to PAA and basic and diluted adjusted net income per common unit, as they are 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 operating results and/or (v) other items that we believe should be excluded in understanding our operating performance. These measures may be further 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. Furthermore, the calculation of these measures contemplates tax effects as a separate reconciling item, where applicable. We have defined all such items as “selected items impacting comparability.” Due to the nature of the selected items, certain selected items impacting comparability may impact certain non-GAAP financial measures, referred to as adjusted results, but not impact other non-GAAP financial measures. 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. These types of variations may not be separately identified in this release, but will be discussed, as applicable, in management’s discussion and analysis of operating results in our Quarterly Report on Form 10-Q. Non-GAAP Financial Liquidity Measures Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Adjusted Free Cash Flow is defined as Net Cash Provided by Operating Activities, less Net Cash Provided by/(Used in) Investing Activities, which primarily includes acquisition, investment and maintenance capital expenditures, investments in unconsolidated entities and related party notes and the impact from the purchase and sale of linefill, net of proceeds from the sales of assets and further impacted by distributions to and contributions from noncontrolling interests and proceeds from the issuance of related party notes. Adjusted Free Cash Flow is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions. We also present these measures and additional non-GAAP financial liquidity measures as they are measures that investors have indicated are useful. We present Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) for use in assessing our underlying business liquidity and cash flow generating capacity excluding fluctuations caused by timing of when amounts earned or incurred were collected, received or paid from period to period. Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) is defined as Adjusted Free Cash Flow excluding the impact of “Changes in assets and liabilities, net of acquisitions” on our Condensed Consolidated Statements of Cash Flows. In addition, we exclude impacts related to the pending Canadian NGL Business divestiture. Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities). Non-GAAP Financial Measures and Discontinued Operations Management believes that the presentation of certain Non-GAAP financial performance measures, such as Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied DCF, Adjusted Net Income attributable to PAA, Adjusted Net Income per Common Unit, Adjusted EBITDA from Crude Oil and Adjusted EBITDA from NGL, and certain Non-GAAP financial liquidity measures, such as Adjusted Free Cash Flow and Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities), on a consolidated basis (e.g., the aggregate of continuing operations and discontinued operations) provides more relevant and useful information regarding our performance and results of operations than presenting such metrics only on a continuing operations or discontinued operations basis. In addition, as the potential sale of the Canadian NGL Business is not anticipated to close until May 2026, management continues to view the Canadian NGL Business as a component of our overall company performance and ability to fund distributions to our unitholders in the near term. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (in millions, except per unit data) ________________________________ (1) Certain Plains entities have issued promissory notes by and among such entities to facilitate financing. For the three months ended March 31, 2026 and 2025, “Interest expense, net” and “Other income, net” each include $23 million and $20 million, respectively, related to interest on such related party promissory notes. These amounts offset and do not impact Net Income or Non-GAAP metrics such as Adjusted EBITDA, Implied DCF and Adjusted Free Cash Flow. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATED BALANCE SHEET DATA (in millions) ________________________________ (1) Includes current assets of discontinued operations of $602 million and $479 million as of March 31, 2026 and December 31, 2025, respectively. (2) Includes current liabilities of discontinued operations of $561 million and $382 million as of March 31, 2026 and December 31, 2025, respectively. DEBT CAPITALIZATION RATIOS (1) (in millions, except percentages) ________________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) COMPUTATION OF BASIC AND DILUTED NET INCOME PER COMMON UNIT (in millions, except per unit data) ________________________________ (1) We calculate net income from continuing operations allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. (2) Net income/(loss) from discontinued operations allocated to common unitholders is “Income/(loss) from discontinued operations, net of tax” as presented on our Condensed Consolidated Statements of Operations. (3) The possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit from continuing operations for each of the three months ended March 31, 2026 and 2025 as the effect was antidilutive. (4) Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATED CASH FLOW DATA (in millions) ________________________________ (1) Certain Plains entities have issued promissory notes by and among such entities to facilitate financing. For the three months ended March 31, 2025, “Net cash used in investing activities” includes a cash outflow of approximately $330 million associated with our investment in related party notes. An equal and offsetting cash inflow associated with our issuance of related party notes is included in “Net cash used in financing activities.” (2) For the three months ended March 31, 2025, includes a net cash outflow of $624 million for bolt-on acquisitions. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CAPITAL EXPENDITURES (1) (in millions) ________________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) Excludes expenditures attributable to noncontrolling interests. (3) See the “Discontinued Operations Detail” section for amounts attributable to discontinued operations. (4) See the “Selected Financial Data by NGL” section for amounts attributable to discontinued operations. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) NON-GAAP RECONCILIATIONS (in millions, except per unit and ratio data) Computation of Basic and Diluted Adjusted Net Income Per Common Unit (1) (2): ________________________________ (1) We calculate adjusted net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. (2) Includes results from continuing operations and discontinued operations for all periods presented. (3) See the “Selected Items Impacting Comparability” table for additional information. (4) The possible conversion of our Series A preferred units was excluded from the calculation of diluted adjusted net income per common unit for each of the three months ended March 31, 2026 and 2025 as the effect was antidilutive. (5) Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. Net Income Per Common Unit to Adjusted Net Income Per Common Unit Reconciliation (1): ________________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) See the “Selected Items Impacting Comparability” and the “Computation of Basic and Diluted Net Income Per Common Unit” tables for additional information. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation: ________________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) Represents “Interest expense, net” as reported on our Condensed Consolidated Statements of Operations, net of interest income associated with promissory notes by and among certain Plains entities. (3) Adjustment to exclude our proportionate share of depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities. (4) See the “Selected Items Impacting Comparability” table for additional information. (5) Amount excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps and is net of interest income associated with promissory notes by and among certain Plains entities. (6) Investment capital expenditures attributable to noncontrolling interests that reduce Implied DCF available to PAA common unitholders. (7) For the three months ended March 31, 2026, excludes approximately $216 million of current income tax expense associated with the tax impact of certain planning and restructuring activities within our organizational structure in connection with the pending Canadian NGL Business divestiture that had income tax consequences that were recorded during the first quarter of 2026. (8) Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, and selected items impacting comparability of unconsolidated entities) (9) Cash distributions paid during the period presented. (10) Implied DCF Available to Common Unitholders for the period divided by the weighted average common units outstanding for the period. (11) Implied DCF Available to Common Unitholders for the period, adjusted for Series A preferred unit cash distributions paid, divided by the weighted average common units and common unit equivalents outstanding for the period. Our Series A preferred units are convertible into common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, in whole or in part, subject to certain minimum conversion amounts. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) Net Income Per Common Unit to Implied DCF Per Common Unit and Common Unit Equivalent Reconciliation (1): ________________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) Represents adjustments to Net Income to calculate Implied DCF Available to Common Unitholders. See the “Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation” table for additional information. (3) Based on weighted average common units outstanding for the three months ended March 31, 2026 and 2025 of 706 million and 704 million, respectively. (4) Based on weighted average common units outstanding for the periods, as well as weighted average Series A preferred units outstanding for three months ended March 31, 2026 and 2025 of 58 million and 63 million, respectively. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) Net Cash Provided by Operating Activities to Non-GAAP Financial Liquidity Measures Reconciliation (1): ________________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) Certain Plains entities have issued promissory notes by and among such entities to facilitate financing. “Proceeds from the issuance of related party notes” has an equal and offsetting cash outflow associated with our investment in related party notes, which is included as a component of “Net cash used in investing activities.” (3) For the three months ended March 31, 2025, includes a net cash outflow of $624 million for bolt-on acquisitions. (4) Cash distributions paid during the period presented. (5) Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Adjusted Free Cash Flow after Distributions shortages, if any, may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program. (6) Cash distributions paid to preferred and common unitholders during the period. (7) Excess Adjusted Free Cash Flow after Distributions is retained to establish reserves for future distributions, capital expenditures, debt reduction and other partnership purposes. Adjusted Free Cash Flow after Distributions shortages may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program. (8) Excludes the income tax impacts related to the pending Canadian NGL Business divestiture. See the “Condensed Consolidated Cash Flow Data” table for information regarding changes in assets and liabilities. (9) Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) and Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities) to assess the underlying business liquidity and cash flow generating capacity excluding fluctuations caused by timing of when amounts earned or incurred were collected, received or paid from period to period. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) SELECTED ITEMS IMPACTING COMPARABILITY (in millions) ________________________________ (1) Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability. See the “Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation” and “Computation of Basic and Diluted Adjusted Net Income Per Common Unit” tables for additional details on how these selected items impacting comparability affect such measures. (2) Includes results from continuing operations and discontinued operations for all periods presented. (3) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify differences in the timing of earnings from the derivative instruments and the underlying transactions and exclude the related gains and losses in determining adjusted results such that the earnings from the derivative instruments and the underlying transactions impact adjusted results in the same period. In addition, we exclude gains and losses on derivatives that are related to (i) investing activities, such as the purchase of linefill, and (ii) purchases of long-term inventory. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. (4) We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We treat the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and write-downs of such inventory that result from price declines as a selected item impacting comparability. (5) We, and certain of our equity method investees, have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue or equity earnings, as a selected item impacting comparability. We believe the inclusion of the contractually committed revenues associated with that period is meaningful to investors as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. (6) Depreciation and amortization on the long-lived assets of the Canadian NGL Business disposal group ceased upon meeting the criteria to be classified as assets held for sale. Management believes that the presentation of Adjusted EBITDA and Implied DCF on a consolidated basis (e.g., the aggregate of continuing operations and discontinued operations) provides more relevant and useful information regarding our performance and results of operations than presenting such metrics only on a continuing operations or discontinued operations basis. We therefore include an adjustment for the impact of amortization of the rail fleet associated with the Canadian NGL Business. (7) Our total equity-indexed compensation expense includes expense associated with awards that will be settled in units and awards that will be settled in cash. The awards that will be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We consider the compensation expense associated with these awards as a selected item impacting comparability as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will be settled in cash is not considered a selected item impacting comparability. (8) During the periods presented, there were fluctuations in the value of the Canadian dollar to the U.S. dollar, 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. (9) We agreed to potential earnout payments associated with recently completed acquisitions, primarily our Cactus III acquisition. We consider the non-cash change in the estimated fair value of such earnout payments as a selected item impacting comparability. (10) Primarily related to deal-specific costs incurred during the period. (11) In connection with the pending Canadian NGL Business divestiture, we have continued to progress certain planning and restructuring activities within our organizational structure. Certain of these activities had income tax consequences that required recognition during the first quarter of 2026. We consider the impacts related to the pending Canadian NGL Business divestiture as a selected item impacting comparability. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) SELECTED FINANCIAL DATA BY CRUDE OIL (in millions) ________________________________ (1) Includes intersegment amounts. (2) Field operating costs and Segment general and administrative expenses include equity-indexed compensation expense. (3) 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. (4) Represents adjustments utilized by our CODM in the evaluation of segment results. Many of these adjustments are also considered selected items impacting comparability when calculating consolidated non-GAAP financial measures such as Adjusted EBITDA. See the “Selected Items Impacting Comparability” table for additional discussion. (5) Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II Pipeline LLC and Red River Pipeline LLC. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) SELECTED FINANCIAL DATA BY NGL (in millions) ________________________________ (1) Includes intersegment amounts. (2) Field operating costs and Segment general and administrative expenses include certain costs that are part of the overhead of continuing operations, including information technology, insurance and other shared services costs. (3) 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. (4) Includes results from continuing operations and excludes amounts related to discontinued operations for all periods presented. (5) See the “Reconciliation of Adjusted EBITDA from NGL Discontinued Operations” table for a reconciliation to the most directly comparable measure as reported in accordance with GAAP. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) DISCONTINUED OPERATIONS DETAIL (in millions) Components of Income/(Loss) from Discontinued Operations, Net of Tax: Reconciliation of Adjusted EBITDA from NGL Discontinued Operations: ________________________________ (1) See the “Selected Items Impacting Comparability” table for additional information. Investment Capital from NGL Discontinued Operations: PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) OPERATING DATA (1) ________________________________ (1) Average 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 period divided by the number of days in the period. Volumes associated with assets acquired during the period represent total volumes for the number of days we actually owned the assets divided by the number of days in the period. (2) Includes volumes (attributable to our interest) from assets owned by unconsolidated entities. (3) Includes volumes from assets associated with continuing operations and discontinued operations. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) SUPPLEMENTAL NON-GAAP RECONCILIATIONS (in millions) Supplemental Adjusted EBITDA attributable to PAA Reconciliation: ________________________________ (1) See the “Reconciliation of Adjusted EBITDA from NGL Discontinued Operations” table for a reconciliation to the most directly comparable measure as reported in accordance with GAAP. (2) Represents “Other income, net” as reported on our Condensed Consolidated Statements of Operations, excluding interest income on promissory notes by and among certain Plains entities, as well as other income, net attributable to noncontrolling interests, adjusted for selected items impacting comparability. See the “Selected Items Impacting Comparability” table for additional information. (3) See the “Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation” table for reconciliation to Net Income. PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (in millions, except per share data) ________________________________ (1) Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP. (2) See the “Computation of Basic and Diluted Net Income Per Class A Share” table for additional information. PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATING BALANCE SHEET DATA (in millions) ________________________________ (1) Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP. (2) Includes current assets of discontinued operations of $602 million and $479 million as of March 31, 2026 and December 31, 2025, respectively. (3) Includes current liabilities of discontinued operations of $561 million and $382 million as of March 31, 2026 and December 31, 2025, respectively. PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) COMPUTATION OF BASIC AND DILUTED NET INCOME PER CLASS A SHARE (in millions, except per share data) Forward-Looking Statements Except for the historical information contained herein, the matters discussed in this release consist of forward-looking statements that involve certain risks and uncertainties that could cause actual results or outcomes to differ materially from results or outcomes anticipated in the forward-looking statements. These risks and uncertainties include, among other things, the following: risks related to the Canadian NGL Business divestiture (as defined herein), including the risk that the Canadian NGL Business divestiture is not consummated on the terms expected or on the anticipated schedule, or at all, and the effect of the announcement or pendency of the Canadian NGL Business divestiture on our business relationships, operating results, employees, stakeholders and business generally; general economic, market or business conditions in the United States and elsewhere (including the potential for a recession or significant slowdown in economic activity levels, the risk of persistently high inflation and supply chain issues, the impact of global public health events, such as pandemics, on demand and growth, and the timing, pace and extent of economic recovery) that impact (i) demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide and (ii) commercial opportunities available to us; declines in global crude oil demand and/or crude oil prices or other factors that correspondingly lead to a significant reduction of North American crude oil and NGL production (whether due to reduced producer cash flow to fund drilling activities or the inability of producers to access capital, or both, the unavailability of pipeline and/or storage capacity, the shutting-in of production by producers, government-mandated pro-ration orders, or other factors), which in turn could result in significant declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets and/or the reduction of the margins we can earn or the commercial opportunities that might otherwise be available to us; impacts of global geopolitical events, including conflicts in the Middle East and elsewhere, on commodity price volatility and crude oil supply and demand, as well as broader impacts on financial markets and the global macroeconomic environment; fluctuations in refinery capacity and other factors affecting demand for various grades of crude oil and NGL and resulting changes in pricing conditions or transportation throughput requirements; unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof); the effects of competition and capacity overbuild in areas where we operate, including downward pressure on rates, volumes and margins, contract renewal risk and the risk of loss of business to other midstream operators who are willing or under pressure to aggressively reduce transportation rates in order to capture or preserve customers; the availability of, and our ability to consummate, acquisitions, divestitures, joint ventures or other strategic opportunities and realize benefits therefrom, including the Canadian NGL Business divestiture (as defined herein); the successful operation of joint ventures and joint operating arrangements we enter into from time to time, whether relating to assets operated by us or by third parties, and the successful integration and future performance of acquired assets or businesses; environmental liabilities, litigation or other events that are not covered by an indemnity, insurance or existing reserves; negative societal sentiment regarding the hydrocarbon energy industry and the continued development and consumption of hydrocarbons, which could influence consumer preferences and governmental or regulatory actions that adversely impact our business; the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event that materially impacts our operations, including cyber or other attacks on our or our service providers’ electronic and computer systems; weather interference with business operations or project construction, including the impact of extreme weather events or conditions (including hurricanes, floods, wildfires and drought); the impact of current and future laws, rulings, legislation, governmental regulations, executive orders, trade policies, trade tariffs, accounting standards and statements, and related interpretations that (i) prohibit, restrict or regulate the development of oil and gas resources and the related infrastructure on lands dedicated to or served by our pipelines or (ii) negatively impact our ability to develop, operate or repair midstream assets, or (iii) otherwise negatively impact our business or increase our exposure to risk; negative impacts on production levels in the Permian Basin or elsewhere due to issues associated with (or laws, rules or regulations relating to) hydraulic fracturing and related activities (including wastewater injection or disposal), including earthquakes, subsidence, expansion or other issues; the pace of development of natural gas or other infrastructure and its impact on expected crude oil production growth in the Permian Basin; the refusal or inability of our customers or counterparties to perform their obligations under their contracts with us (including commercial contracts, asset sale agreements and other agreements), whether justified or not and whether due to financial constraints (such as reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors; loss of key personnel and inability to attract and retain new talent; disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair our ability to execute our commercial or hedging strategies; the effectiveness of our risk management activities; shortages or cost increases of supplies, materials or labor; maintenance of our credit ratings and ability to receive open credit from our suppliers and trade counterparties; our inability to perform our obligations under our contracts, whether due to non-performance by third parties, including our customers or counterparties, market constraints, third-party constraints, supply chain issues, legal constraints (including governmental orders or guidance), or other factors or events; the incurrence of costs and expenses related to unexpected or unplanned capital or maintenance expenditures, third-party claims or other factors; failure to implement or capitalize, or delays in implementing or capitalizing, on investment capital projects, whether due to permitting delays, permitting withdrawals or other factors; failure to implement or realize anticipated benefits from operational and organizational streamlining and efficiency efforts and initiatives; tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, investment capital projects, working capital requirements and the repayment or refinancing of indebtedness; the amplification of other risks caused by volatile or closed financial markets, capital constraints, liquidity concerns and inflation; the use or availability of third-party assets upon which our operations depend and over which we have little or no control; the currency exchange rate of the Canadian dollar to the United States dollar; the deferral of current revenue recognition attributable to deficiency payments received from customers who fail to ship or move their minimum contracted volumes; significant under-utilization of our assets and facilities; increased costs, or lack of availability, of insurance; fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans; risks related to the development and operation of our assets; and other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the processing, transportation, fractionation, storage and marketing of NGL as discussed in the Partnerships’ filings with the Securities and Exchange Commission. About Plains: PAA is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil and natural gas liquids (“NGL”). PAA owns an extensive network of pipeline gathering and transportation systems, in addition to terminalling, storage, processing, fractionation and other infrastructure assets serving key producing basins, transportation corridors and major market hubs and export outlets in the United States and Canada. On average, PAA handles over 9 million barrels per day of crude oil and NGL. PAGP is a publicly traded entity that owns an indirect, non-economic controlling general partner interest in PAA and an indirect limited partner interest in PAA, one of the largest energy infrastructure and logistics companies in North America. PAA and PAGP are headquartered in Houston, Texas. For more information, please visit www.plains.com. Contacts:

HOUSTON, April 06, 2026 (GLOBE NEWSWIRE) -- Plains All American Pipeline, L.P. (Nasdaq: PAA) and Plains GP Holdings (Nasdaq: PAGP) announced today their quarterly distributions with respect to the first quarter of 2026 and also announced timing of first quarter 2026 earnings. First Quarter Distribution Declaration PAA and PAGP announced the following quarterly cash distributions, each of which will be payable on May 15, 2026, to holders of the respective securities at the close of business on May 1, 2026: PAA Common Units – $0.4175 per Common Unit ($1.67 per unit on an annualized basis), which is unchanged from the distribution paid in February 2026. PAGP Class A Shares – $0.4175 per Class A Share ($1.67 per Class A Share on an annualized basis), which is unchanged from the distribution paid in February 2026. PAA Series A Preferred Units – $0.61524 per Series A Preferred Unit (approximately $2.46 per unit on an annualized basis). For its Series B Preferred Units, PAA announced a quarterly distribution of $19.84 per Series B Unit (based on the applicable quarterly floating rate), which will be payable on May 15, 2026, to holders of record at the close of business on May 1, 2026. Although equity holders should consult their own tax advisor regarding their particular circumstances, due to the pending NGL assets sale, it is possible that PAGP will report positive current earnings and profits for the Tax Year 2026, making part of its Class A Share cash distribution taxable as a dividend. The transaction is not estimated to result in a material change in the previous forecast regarding when routine PAGP distributions will shift from being a return of capital to being taxed as dividends or when PAGP will become a taxpaying entity. After the transaction closes, and upon payment of quarterly distributions throughout 2026, Plains will publish Form 8937, Report of Organizational Actions Affecting Basis of Securities to clarify the expected portion of the quarterly distribution that will be taxed as a dividend. In addition, to the extent any cash distribution exceeds a Class A Shareholder’s tax basis, it should be taxable as a capital gain. Qualified Notices under Treasury Regulation Section 1.1446 with respect to the PAA Common Unit distribution and PAA Series B Preferred Unit distribution will be posted on the Plains website under “Investor Relations – Unit Information.” First Quarter 2026 Earnings Timing PAA and PAGP also announced that they will release first quarter 2026 earnings before market open on Friday, May 8, 2026. Following the announcement, PAA and PAGP will host a conference call at 9:00 a.m. CT (10 a.m. ET) with analysts and investors to discuss earnings. The call will be webcast live on the internet and may be accessed through the "Investors Relations” section of the website at www.plains.com. An audio replay will be available on the website after the call. About Plains PAA is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil and natural gas liquids (NGL). PAA owns an extensive network of pipeline gathering and transportation systems, in addition to terminalling, storage, processing, fractionation and other infrastructure assets serving key producing basins, transportation corridors and major market hubs and export outlets in the United States and Canada. On average, PAA handles approximately nine million barrels per day of crude oil and NGL. PAGP is a publicly traded entity that owns an indirect, non-economic controlling general partner interest in PAA and an indirect limited partner interest in PAA, one of the largest energy infrastructure and logistics companies in North America. PAA and PAGP are headquartered in Houston, Texas. More information is available at www.plains.com. Investor Relations Contacts: Blake Fernandez Ross Hovde [email protected] (866) 809-1291

This article first appeared on GuruFocus. Adjusted EBITDA (Q4 2025): $738 million. Adjusted EBITDA (Full-Year 2025): $2.833 billion. Crude Oil Segment Adjusted EBITDA (Q4 2025): $611 million. NGL Segment Adjusted EBITDA (Q4 2025): $122 million. 2026 Adjusted EBITDA Guidance: $2.75 billion at midpoint, plus or minus $75 million. Oil Segment EBITDA Guidance (2026): $2.64 billion, implying 13% growth year-over-year. Distribution Increase: 10% increase in quarterly distribution, annualized to $1.67 per unit. Targeted Annualized Distribution Growth: $0.15 per unit. Growth Capital Investment (2026): Approximately $350 million. Maintenance Capital (2026): Approximately $165 million. Adjusted Free Cash Flow (2026): Approximately $1.8 billion, excluding changes in assets and liabilities. Senior Unsecured Notes Issued: $750 million, with $300 million due in 2031 at 4.7% and $450 million due in 2036 at 5.6%. Leverage Ratio Target: 3.25 to 3.75 times. Warning! GuruFocus has detected 8 Warning Signs with PAGP. Is PAGP fairly valued? Test your thesis with our free DCF calculator. Release Date: February 06, 2026 For the complete transcript of the earnings call, please refer to the full earnings call transcript. Plains GP Holdings LP (NASDAQ:PAGP) reported a strong adjusted EBITDA of $738 million for the fourth quarter and $2.833 billion for the full year 2025. The company is transitioning to a pure-play crude company, enhancing cash flow quality and durability through strategic divestitures and acquisitions. PAGP is targeting $100 million in annual savings through efficiency initiatives, with 50% expected to be realized in 2026. The acquisition of the WildHorse terminal adds 4 million barrels of storage capacity, expected to generate returns above internal thresholds. PAGP announced a 10% increase in quarterly distribution, reflecting confidence in future cash flow and distribution growth. The market environment in 2025 was challenging due to geopolitical unrest, OPEC actions, and economic uncertainties from tariffs. The NGL segment's adjusted EBITDA was impacted by warm weather and weak frac spreads, reflecting seasonal volatility. PAGP's Permian crude production is expected to remain flat in 2026, with growth anticipated to resume only in 2027. The company is reducing its distribution coverage ratio threshold from 160% to 150%, indicating a more conservative approach. The divestiture of the NGL business will result in a slight decline in headline EBITDA, although distributable cash flow is expected to increase. Q: Can you elaborate on the synergy benefits from the Cactus pipeline and your ability to expand without laying more pipe? A: Jeremy Goebel, Executive Vice President and Chief Commercial Officer, explained that they are already on track to achieve $50 million in synergies, with half realized through G&A and OpEx reductions. The remaining synergies are expected from filling the pipeline with supply. Expansion can be done in phases, matching capacity to demand without necessarily laying new pipe. Q: Could you discuss the $100 million in cost savings through 2027 and the efficiencies being implemented? A: Chris Chandler, Chief Operating Officer, stated that the sale of the NGL business allows for a restructuring of the company, reducing operational complexity. They aim to achieve $100 million in savings by 2027, with $50 million expected in 2026, by optimizing non-core businesses and improving organizational efficiency. Q: How is the sentiment among your producer customers in the Permian Basin, given the current oil price scenario? A: Jeremy Goebel noted that producers are cautiously optimistic, focusing on efficiency and inventory preservation. Despite a potentially flat 2026, they expect growth to resume in 2027, driven by improved efficiencies and a more constructive market environment. Q: What are your capital allocation priorities, and is there room to further reduce the payout ratio? A: Aloys Swanson, CFO, emphasized that their primary focus is on distribution growth, maintaining a 150% coverage level. They plan to continue with bolt-on acquisitions and opportunistic repurchases, aligning with their capital allocation strategy. Q: Can you explain the rationale behind setting the distribution coverage at 150%? A: Willie Chiang, CEO, explained that the 150% coverage is a conservative approach, allowing for multiyear distribution growth. It reflects a more durable cash flow stream and aligns with industry peers, providing confidence in future growth. Q: What are the details of the $350 million growth CapEx for 2026? A: Chris Chandler outlined that the CapEx includes Permian connection programs, integration of the Cactus III pipeline, and potential investments in the Canadian crude oil business. This aligns with their typical $300-$400 million range for growth investments. Q: How might geopolitical developments in Venezuela impact Plains' operations? A: Jeremy Goebel noted that initial impacts include wider Canadian differentials and opportunities for quality optimization. Long-term, substantial investment and stability in Venezuela would be needed for significant changes, but current developments offer logistical opportunities. Q: What inning are we in for consolidation in the crude oil infrastructure industry? A: Willie Chiang stated that while consolidation is not a smooth trajectory, Plains remains focused on executing recent large transactions. They continue to evaluate opportunities with financial discipline, expecting more consolidation opportunities in the future. Q: What are the growth drivers supporting the multiyear runway for $0.15 distribution increases? A: Willie Chiang highlighted self-help initiatives, Permian growth, and efficiency improvements as key drivers for continued distribution growth beyond 2026, supported by a stable cash flow stream. Q: How do you assess coverage from a free cash flow perspective? A: Aloys Swanson explained that the 150% DCF coverage is designed to fund routine organic capital and small bolt-ons, with larger investments utilizing the balance sheet. This approach supports a sustainable investment profile. For the complete transcript of the earnings call, please refer to the full earnings call transcript.

HOUSTON, Feb. 06, 2026 (GLOBE NEWSWIRE) -- Plains All American Pipeline, L.P. (Nasdaq: PAA) and Plains GP Holdings (Nasdaq: PAGP) today reported fourth-quarter and full-year 2025 results, announced 2026 guidance and provided the following highlights: Fourth Quarter and Full-Year 2025 Results Fourth-quarter and full-year 2025 Net income attributable to PAA of $342 million and $1.435 billion, respectively, and 2025 Net cash provided by operating activities of $785 million and $2.94 billion, respectively Delivered fourth-quarter and full-year 2025 Adjusted EBITDA attributable to PAA of $738 million and $2.833 billion, respectively Pro forma leverage ratio of 3.9x at year-end 2025; expect to return toward the midpoint of the target range of 3.25 to 3.75x following anticipated closing of the NGL divestiture toward the end of the first quarter 2026 In November, Plains successfully raised $750 million in aggregate senior unsecured notes with proceeds allocated toward the reduction of commercial paper and funding the EPIC acquisition (now Cactus III) In November, Plains also paid off a $1.1 billion EPIC term loan assumed as part of the EPIC acquisition by issuing a $1.1 billion senior unsecured term loan at PAA 2026 Outlook and Key Highlights Expect full-year 2026 Adjusted EBITDA attributable to PAA midpoint of $2.75 billion +/- $75 million (assumes one quarter of NGL contribution of $100 million) Capture efficiency initiatives of approximately $100 million of cost savings through 2027 (with approximately half realized in 2026); coupled with $50 million of synergies expected on Cactus III, these initiatives create self-help growth opportunities despite expectation of a relatively flat Permian production profile for 2026 Announced annualized distribution increase of $0.15 per unit payable February 13, 2026, representing a 10% aggregate increase in the annualized distribution rate versus 2025 levels (new annualized distribution rate of $1.67 per unit) Distribution Coverage ratio threshold lowered from 160% to 150% reflecting more predictable cash flow and providing multi-year runway for targeted annual distribution growth of $0.15 per unit Expect strong Adjusted Free Cash flow generation of approximately $1.80 billion (excluding changes in Assets & Liabilities and anticipated cash proceeds from the NGL divestiture) Remain focused on disciplined capital investments, anticipating full-year 2026 Growth Capital of +/- $350 million and Maintenance Capital of +/- $165 million net to Plains “Last year we took significant steps to transition the company toward becoming the premier North American pure play crude oil midstream provider, including the announced sale of our Canadian NGL business and the acquisition of Cactus III. For 2026, the team is focused on closing the pending NGL sale, realizing synergies on the Cactus III acquisition and driving efficiency initiatives throughout the organization. These self-help actions provide levers for efficient growth in an otherwise volatile near-term oil macro environment. We also remain committed to our multi-year capital allocation framework and returning cash to unitholders as evidenced by the recent $0.15 per unit increase in our annualized distribution rate, bringing the distribution yield to ~8.5%. In addition, we have elected to lower our Distribution Coverage ratio threshold from 160% to 150%, thereby paving the way for additional return of capital to unitholders. I’m pleased with the progress being made as we transition into a more focused, streamlined organization that should be well positioned for improving oil market fundamentals into the future,” said Willie Chiang, Chairman, CEO and President. Financial Reporting Considerations for Pending Sale of Canadian NGL Business On June 17, 2025, we entered into a definitive agreement to sell substantially all of our NGL business in Canada (the “Canadian NGL Business”) to Keyera Corp. This transaction is expected to close toward the end of the first quarter of 2026 and is subject to the satisfaction or waiver of customary closing conditions, including receipt of regulatory approvals. While we will divest the Canadian NGL Business as part of the transaction, we will retain substantially all NGL assets in the United States and will also retain all crude oil assets in Canada. We have determined that the operations of the Canadian NGL Business meet the criteria for classification as held for sale and for discontinued operations reporting and have applied these changes retrospectively to all periods presented. Results throughout this release specify if they are presented from continuing operations (which exclude the results of the Canadian NGL Business) and/or discontinued operations. Plains All American Pipeline Summary Financial Information (unaudited) (in millions, except per unit data) ________________________ ** Indicates that variance as a percentage is not meaningful. (1) Includes results from continuing operations and discontinued operations for all periods presented. See the tables attached hereto for additional information. (2) Excludes amounts attributable to noncontrolling interests in the Plains Oryx Permian Basin LLC (the “Permian JV”), Cactus II Pipeline LLC and Red River Pipeline LLC joint ventures. (3) See the section of this release entitled “Non-GAAP Financial Measures and Selected Items Impacting Comparability” and the tables attached hereto for information regarding our Non-GAAP financial measures, including their reconciliation to the most directly comparable measures as reported in accordance with GAAP, and certain selected items that PAA believes impact comparability of financial results between reporting periods. (4) Fourth-quarter and full-year 2025 includes the impact of a net cash outflow of $1.786 billion and $2.651 billion, respectively, for acquisitions, including our Cactus III acquisition completed during the fourth quarter of 2025. Disaggregation of Adjusted EBITDA by Product (1) (2) (unaudited) (in millions) ________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) See the section of this release entitled “Non-GAAP Financial Measures and Selected Items Impacting Comparability” and the tables attached hereto for information regarding our Non-GAAP financial measures, including their reconciliation to the most directly comparable measures as reported in accordance with GAAP, and certain selected items that PAA believes impact comparability of financial results between reporting periods. Fourth-quarter 2025 Adjusted EBITDA from Crude Oil increased 7% versus comparable 2024 results. Favorable results in the 2025 period from (i) contributions from recently completed bolt-on acquisitions, including our Cactus III pipeline acquisition, (ii) higher volumes on our pipelines and (iii) tariff escalations were offset by the impact of (iv) certain Permian long-haul pipeline contract rate resets and (v) lower commodity prices. Fourth-quarter 2025 Adjusted EBITDA from NGL decreased 21% versus comparable 2024 results primarily due to lower sales volumes and lower weighted average frac spreads. Plains GP Holdings PAGP owns an indirect non-economic controlling interest in PAA’s general partner and an indirect limited partner interest in PAA. As the control entity of PAA, PAGP consolidates PAA’s results into its financial statements, which is reflected in the condensed consolidating balance sheet and income statement tables attached hereto. Conference Call and Webcast Instructions PAA and PAGP will hold a joint conference call at 9:00 a.m. CT on Friday, February 6, 2026 to discuss fourth-quarter performance and related items. To access the internet webcast, please go to https://edge.media-server.com/mmc/p/3ksb2gmv/. Alternatively, the webcast can be accessed on our website at https://ir.plains.com/news-events/events-presentations. Following the live webcast, an audio replay will be available on our website and will be accessible for a period of 365 days. Slides will be posted prior to the call at the above referenced website. Non-GAAP Financial Measures and Selected Items Impacting Comparability 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 and to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. The primary additional measures used by management are Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied Distributable Cash Flow (“DCF”), Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions. Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied DCF and certain other non-GAAP financial performance measures are reconciled to Net Income, and Adjusted Free Cash Flow, Adjusted Free Cash Flow after Distributions and certain other non-GAAP financial liquidity measures are reconciled to Net Cash Provided by Operating Activities (the most directly comparable measures as reported in accordance with GAAP) for the historical periods presented in the tables attached to this release, and should be viewed in addition to, and not in lieu of, our Consolidated Financial Statements and accompanying notes. In addition, we encourage you to visit the Investor Relations section of our website at www.plains.com (navigate to the “Financials” tab, then click on “Quarterly Results”), which presents a reconciliation of our commonly used non-GAAP and supplemental financial measures. We do not reconcile non-GAAP financial measures on a forward-looking basis as it is impractical to do so without unreasonable effort. Non-GAAP Financial Performance Measures Adjusted EBITDA is defined as earnings from continuing operations and discontinued operations before (i) interest expense, (ii) income tax (expense)/benefit from continuing operations and discontinued operations, (iii) depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities) from continuing operations and discontinued operations, (iv) gains and losses on asset sales, asset impairments and other, net from continuing operations and discontinued operations, (v) gains on investments in unconsolidated entities, net and (vi) interest income on promissory notes by and among certain Plains entities, and (vii) adjusted for certain selected items impacting comparability. Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests. Adjusted EBITDA disaggregated by product (e.g., Adjusted EBITDA from Crude Oil and Adjusted EBITDA from NGL) excludes amounts related to Other income/(expense). Management believes that the presentation of Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF 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 operating performance and ability to fund distributions to our unitholders through cash generated by our operations and (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions. We also present these and additional non-GAAP financial measures, including adjusted net income attributable to PAA and basic and diluted adjusted net income per common unit, as they are 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 operating results and/or (v) other items that we believe should be excluded in understanding our operating performance. These measures may be further 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. Furthermore, the calculation of these measures contemplates tax effects as a separate reconciling item, where applicable. We have defined all such items as “selected items impacting comparability.” Due to the nature of the selected items, certain selected items impacting comparability may impact certain non-GAAP financial measures, referred to as adjusted results, but not impact other non-GAAP financial measures. 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. These types of variations may not be separately identified in this release, but will be discussed, as applicable, in management’s discussion and analysis of operating results in our Annual Report on Form 10-K. Non-GAAP Financial Liquidity Measures Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Adjusted Free Cash Flow is defined as Net Cash Provided by Operating Activities, less Net Cash Provided by/(Used in) Investing Activities, which primarily includes acquisition, investment and maintenance capital expenditures, investments in unconsolidated entities and related party notes and the impact from the purchase and sale of linefill, net of proceeds from the sales of assets and further impacted by distributions to and contributions from noncontrolling interests and proceeds from the issuance of related party notes. Adjusted Free Cash Flow is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions. We also present these measures and additional non-GAAP financial liquidity measures as they are measures that investors have indicated are useful. We present Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) for use in assessing our underlying business liquidity and cash flow generating capacity excluding fluctuations caused by timing of when amounts earned or incurred were collected, received or paid from period to period. Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) is defined as Adjusted Free Cash Flow excluding the impact of “Changes in assets and liabilities, net of acquisitions” on our Condensed Consolidated Statements of Cash Flows. Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities). Non-GAAP Financial Measures and Discontinued Operations Management believes that the presentation of certain Non-GAAP financial performance measures, such as Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied DCF, Adjusted Net Income attributable to PAA, Adjusted Net Income per Common Unit, Adjusted EBITDA from Crude Oil and Adjusted EBITDA from NGL, and certain Non-GAAP financial liquidity measures, such as Adjusted Free Cash Flow and Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities), on a consolidated basis (e.g., the aggregate of continuing operations and discontinued operations) provides more relevant and useful information regarding our performance and results of operations than presenting such metrics only on a continuing operations or discontinued operations basis. In addition, as the potential sale of the Canadian NGL Business is not anticipated to close until the end of the first quarter of 2026, management continues to view the Canadian NGL Business as a component of our overall company performance and ability to fund distributions to our unitholders in the near term. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (in millions, except per unit data) ________________________ (1) For the three and twelve months ended December 31, 2024, Field operating costs include $225 million and $345 million, respectively, resulting from adjustments related to the Line 901 incident that occurred in May 2015, including the write-off of a receivable for Line 901 insurance proceeds in the fourth quarter of 2024 and settlements in the third quarter of 2024. (2) Certain Plains entities have issued promissory notes by and among such entities to facilitate financing. “Interest expense, net” and “Other income, net” each include $22 million and $87 million for the three and twelve months ended December 31, 2025, respectively, and $17 million and $48 million for the three and twelve months ended December 31, 2024, respectively, related to interest on such related party promissory notes. These amounts offset and do not impact Net Income or Non-GAAP metrics such as Adjusted EBITDA, Implied DCF and Adjusted Free Cash Flow. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATED BALANCE SHEET DATA (in millions) ________________________ (1) Includes current assets of discontinued operations of $479 million and $415 million as of December 31, 2025 and December 31, 2024, respectively. (2) Includes current liabilities of discontinued operations of $382 million and $350 million as of December 31, 2025 and December 31, 2024, respectively. DEBT CAPITALIZATION RATIOS (1) (in millions, except percentages) ________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) COMPUTATION OF BASIC AND DILUTED NET INCOME/(LOSS) PER COMMON UNIT (in millions, except per unit data) ________________________ (1) We repurchased approximately 12.7 million Series A preferred units on January 31, 2025. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet is considered a return to Series A preferred unitholders for the calculation of net income from continuing operations allocated to common unitholders. (2) We calculate net income/(loss) from continuing operations allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. (3) Net income from discontinued operations allocated to common unitholders is Income from discontinued operations, net of tax as presented on our Condensed Consolidated Statements of Operations. (4) The possible conversion of our Series A preferred units was excluded from the calculation of diluted net income/(loss) per common unit from continuing operations for each of the three and twelve months ended December 31, 2025 and 2024 as the effect was antidilutive. (5) Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATED CASH FLOW DATA (in millions) ________________________ (1) Certain Plains entities have issued promissory notes by and among such entities to facilitate financing. For the twelve months ended December 31, 2025 and 2024, “Net cash used in investing activities” includes a cash outflow of approximately $330 million and $629 million, respectively, associated with our investment in related party notes. An equal and offsetting cash inflow associated with our issuance of related party notes is included in “Net cash provided by/(used in) financing activities.” (2) The 2025 period includes a net cash outflow of $2.651 billion for acquisitions, including our Cactus III acquisition completed during the fourth quarter of 2025. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CAPITAL EXPENDITURES (1) (in millions) ________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) Excludes expenditures attributable to noncontrolling interests. (3) See the “Discontinued Operations Detail” section for amounts attributable to discontinued operations. (4) See the “Selected Financial Data by NGL” section for amounts attributable to discontinued operations. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) NON-GAAP RECONCILIATIONS (in millions, except per unit and ratio data) Computation of Basic and Diluted Adjusted Net Income Per Common Unit (1) (2): ________________________ (1) We calculate adjusted net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. (2) Includes results from continuing operations and discontinued operations for all periods presented. (3) See the “Selected Items Impacting Comparability” table for additional information. (4) We repurchased approximately 12.7 million Series A preferred units on January 31, 2025. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet is considered a return to Series A preferred unitholders for the calculation of adjusted net income allocated to common unitholders. (5) The possible conversion of our Series A preferred units was excluded from the calculation of diluted adjusted net income per common unit for each of the three and twelve months ended December 31, 2025 and 2024 as the effect was antidilutive. (6) Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. Net Income/(Loss) Per Common Unit to Adjusted Net Income Per Common Unit Reconciliation (1): ________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) See the “Selected Items Impacting Comparability” and the “Computation of Basic and Diluted Adjusted Net Income/(Loss) Per Common Unit” tables for additional information. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation: ________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) Represents “Interest expense, net” as reported on our Condensed Consolidated Statements of Operations, net of interest income associated with promissory notes by and among certain Plains entities. (3) Adjustment to exclude our proportionate share of depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities. (4) See the “Selected Items Impacting Comparability” table for additional information. (5) Amount excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps and is net of interest income associated with promissory notes by and among certain Plains entities. (6) Investment capital expenditures attributable to noncontrolling interests that reduce Implied DCF available to PAA common unitholders. (7) Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, and selected items impacting comparability of unconsolidated entities) (8) Cash distributions paid during the period presented. (9) Implied DCF Available to Common Unitholders for the period divided by the weighted average common units outstanding for the period. (10) Implied DCF Available to Common Unitholders for the period, adjusted for Series A preferred unit cash distributions paid, divided by the weighted average common units and common unit equivalents outstanding for the period. Our Series A preferred units are convertible into common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, in whole or in part, subject to certain minimum conversion amounts. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) Net Income/(Loss) Per Common Unit to Implied DCF Per Common Unit and Common Unit Equivalent Reconciliation (1): ________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) Represents adjustments to Net Income to calculate Implied DCF Available to Common Unitholders. See the “Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation” table for additional information. (3) Based on weighted average common units outstanding for the periods of 706 million, 704 million, 704 million and 702 million, respectively. (4) Based on weighted average common units outstanding for the periods, as well as weighted average Series A preferred units outstanding of 58 million, 71 million, 59 million and 71 million, for the periods presented, respectively. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) Net Cash Provided by Operating Activities to Non-GAAP Financial Liquidity Measures Reconciliation: ________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) Certain Plains entities have issued promissory notes by and among such entities to facilitate financing. “Proceeds from the issuance of related party notes” has an equal and offsetting cash outflow associated with our investment in related party notes, which is included as a component of “Net cash used in investing activities.” (3) The three and twelve months ended December 31, 2025 includes a net cash outflow of $1.786 billion and $2.651 billion, respectively, for acquisitions, including our Cactus III acquisition completed during the fourth quarter of 2025. (4) Cash distributions paid during the period presented. (5) Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Adjusted Free Cash Flow after Distributions shortages, if any, may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program. (6) Cash distributions paid to preferred and common unitholders during the period. (7) Excess Adjusted Free Cash Flow after Distributions is retained to establish reserves for future distributions, capital expenditures, debt reduction and other partnership purposes. Adjusted Free Cash Flow after Distributions shortages may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program. (8) See the “Condensed Consolidated Cash Flow Data” table. (9) Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) and Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities) to assess the underlying business liquidity and cash flow generating capacity excluding fluctuations caused by timing of when amounts earned or incurred were collected, received or paid from period to period. (10) Fourth-quarter and full-year 2024 Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) includes the negative impact of a $225 million charge resulting from the write-off of a receivable for Line 901 insurance proceeds. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) SELECTED ITEMS IMPACTING COMPARABILITY (in millions) ________________________ (1) Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability. See the “Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation” and “Computation of Basic and Diluted Adjusted Net Income Per Common Unit” tables for additional details on how these selected items impacting comparability affect such measures. (2) Includes results from continuing operations and discontinued operations for all periods presented. (3) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify differences in the timing of earnings from the derivative instruments and the underlying transactions and exclude the related gains and losses in determining adjusted results such that the earnings from the derivative instruments and the underlying transactions impact adjusted results in the same period. In addition, we exclude gains and losses on derivatives that are related to (i) investing activities, such as the purchase of linefill, and (ii) purchases of long-term inventory. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. (4) We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We treat the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and write-downs of such inventory that result from price declines as a selected item impacting comparability. (5) We, and certain of our equity method investees, have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue or equity earnings, as a selected item impacting comparability. We believe the inclusion of the contractually committed revenues associated with that period is meaningful to investors as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. (6) Depreciation and amortization on the long-lived assets of the Canadian NGL Business disposal group ceased upon meeting the criteria to be classified as assets held for sale. Management believes that the presentation of Adjusted EBITDA and Implied DCF on a consolidated basis (e.g., the aggregate of continuing operations and discontinued operations) provides more relevant and useful information regarding our performance and results of operations than presenting such metrics only on a continuing operations or discontinued operations basis. We therefore include an adjustment for the impact of amortization of the rail fleet associated with the Canadian NGL Business. (7) Our total equity-indexed compensation expense includes expense associated with awards that will be settled in units and awards that will be settled in cash. The awards that will be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We consider the compensation expense associated with these awards as a selected item impacting comparability as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will be settled in cash is not considered a selected item impacting comparability. (8) During the periods presented, there were fluctuations in the value of the Canadian dollar to the U.S. dollar, 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. (9) Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. For the 2024 periods, includes the write-off of a receivable for Line 901 insurance proceeds in the fourth quarter of 2024 and the impact of settlements in the third quarter of 2024. (10) Primarily related to deal-specific costs incurred during the period. (11) For the 2024 periods, primarily includes non-cash charges related to the write-down of two U.S. NGL terminals. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) SELECTED FINANCIAL DATA BY CRUDE OIL (in millions) ________________________ (1) Includes intersegment amounts. (2) Field operating costs and Segment general and administrative expenses include equity-indexed compensation expense. (3) Field operating costs for the three and twelve months ended December 31, 2024 include higher expenses related to (i) $225 million resulting from the write-off of a receivable for Line 901 insurance proceeds and (ii) an increase in estimated costs for long-term environmental remediation obligations. The twelve months ended December 31, 2024 also includes the impact of $120 million associated with settlements in the third quarter of 2024 related to the Line 901 incident that occurred in May 2015. (4) 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. (5) Represents adjustments utilized by our CODM in the evaluation of segment results. Many of these adjustments are also considered selected items impacting comparability when calculating consolidated non-GAAP financial measures such as Adjusted EBITDA. See the “Selected Items Impacting Comparability” table for additional discussion. (6) Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II Pipeline LLC and Red River Pipeline LLC. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) SELECTED FINANCIAL DATA BY NGL (in millions) ________________________ (1) Includes intersegment amounts. (2) Field operating costs and Segment general and administrative expenses include certain costs that are part of the overhead of continuing operations, including information technology, insurance and other shared services costs. (3) 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. (4) Includes results from continuing operations and excludes amounts related to discontinued operations for all periods presented. (5) See the “Reconciliation of Adjusted EBITDA from NGL Discontinued Operations” table for a reconciliation to the most directly comparable measure as reported in accordance with GAAP. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) DISCONTINUED OPERATIONS DETAIL (in millions) Components of Income from Discontinued Operations, Net of Tax: Reconciliation of Adjusted EBITDA from NGL Discontinued Operations: ________________________ (1) See the “Selected Items Impacting Comparability” table for additional information. Investment Capital from NGL Discontinued Operations: PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) OPERATING DATA (1) ________________________ (1) Average 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 period divided by the number of days in the period. Volumes associated with assets acquired during the period represent total volumes for the number of days we actually owned the assets divided by the number of days in the period. (2) Includes volumes (attributable to our interest) from assets owned by unconsolidated entities. (3) Includes volumes from assets associated with continuing operations and discontinued operations. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) SUPPLEMENTAL NON-GAAP RECONCILIATIONS (in millions) Supplemental Adjusted EBITDA attributable to PAA Reconciliation: ________________________ (1) See the “Reconciliation of Adjusted EBITDA from NGL Discontinued Operations” table for a reconciliation to the most directly comparable measure as reported in accordance with GAAP. (2) Represents “Other income, net” as reported on our Condensed Consolidated Statements of Operations, excluding interest income on promissory notes by and among certain Plains entities, as well as other income, net attributable to noncontrolling interests, adjusted for selected items impacting comparability. See the “Selected Items Impacting Comparability” table for additional information. (3) See the “Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation” table for reconciliation to Net Income. PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (in millions, except per share data) ________________________ (1) Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP. (2) See the “Computation of Basic and Diluted Net Income/(Loss) Per Class A Share” table for additional information. PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (in millions, except per share data) ________________________ (1) Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP. (2) See the “Computation of Basic and Diluted Net Income/(Loss) Per Class A Share” table for additional information. PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATING BALANCE SHEET DATA (in millions) ________________________ (1) Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP. (2) Includes current assets of discontinued operations of $479 million and $415 million as of December 31, 2025 and December 31, 2024, respectively. (3) Includes current liabilities of discontinued operations of $382 million and $350 million as of December 31, 2025 and December 31, 2024, respectively. PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) COMPUTATION OF BASIC AND DILUTED NET INCOME/(LOSS) PER CLASS A SHARE (in millions, except per share data) Forward-Looking Statements Except for the historical information contained herein, the matters discussed in this release consist of forward-looking statements that involve certain risks and uncertainties that could cause actual results or outcomes to differ materially from results or outcomes anticipated in the forward-looking statements. These risks and uncertainties include, among other things, the following: risks related to the Canadian NGL Business divestiture (as defined herein), including the risk that the Canadian NGL Business divestiture is not consummated on the terms expected or on the anticipated schedule, or at all, and the effect of the announcement or pendency of the Canadian NGL Business divestiture on our business relationships, operating results, employees, stakeholders and business generally; general economic, market or business conditions in the United States and elsewhere (including the potential for a recession or significant slowdown in economic activity levels, the risk of persistently high inflation and supply chain issues, the impact of global public health events, such as pandemics, on demand and growth, and the timing, pace and extent of economic recovery) that impact (i) demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide and (ii) commercial opportunities available to us; declines in global crude oil demand and/or crude oil prices or other factors that correspondingly lead to a significant reduction of North American crude oil and NGL production (whether due to reduced producer cash flow to fund drilling activities or the inability of producers to access capital, or both, the unavailability of pipeline and/or storage capacity, the shutting-in of production by producers, government-mandated pro-ration orders, or other factors), which in turn could result in significant declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets and/or the reduction of the margins we can earn or the commercial opportunities that might otherwise be available to us; fluctuations in refinery capacity and other factors affecting demand for various grades of crude oil and NGL and resulting changes in pricing conditions or transportation throughput requirements; unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof); the effects of competition and capacity overbuild in areas where we operate, including downward pressure on rates, volumes and margins, contract renewal risk and the risk of loss of business to other midstream operators who are willing or under pressure to aggressively reduce transportation rates in order to capture or preserve customers; the availability of, and our ability to consummate, acquisitions, divestitures, joint ventures or other strategic opportunities and realize benefits therefrom, including the Canadian NGL Business divestiture (as defined herein); the successful operation of joint ventures and joint operating arrangements we enter into from time to time, whether relating to assets operated by us or by third parties, and the successful integration and future performance of acquired assets or businesses; environmental liabilities, litigation or other events that are not covered by an indemnity, insurance or existing reserves; negative societal sentiment regarding the hydrocarbon energy industry and the continued development and consumption of hydrocarbons, which could influence consumer preferences and governmental or regulatory actions that adversely impact our business; the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event that materially impacts our operations, including cyber or other attacks on our or our service providers’ electronic and computer systems; weather interference with business operations or project construction, including the impact of extreme weather events or conditions (including hurricanes, floods, wildfires and drought); the impact of current and future laws, rulings, legislation, governmental regulations, executive orders, trade policies, trade tariffs, accounting standards and statements, and related interpretations that (i) prohibit, restrict or regulate the development of oil and gas resources and the related infrastructure on lands dedicated to or served by our pipelines or (ii) negatively impact our ability to develop, operate or repair midstream assets, or (iii) otherwise negatively impact our business or increase our exposure to risk; negative impacts on production levels in the Permian Basin or elsewhere due to issues associated with (or laws, rules or regulations relating to) hydraulic fracturing and related activities (including wastewater injection or disposal), including earthquakes, subsidence, expansion or other issues; the pace of development of natural gas or other infrastructure and its impact on expected crude oil production growth in the Permian Basin; the refusal or inability of our customers or counterparties to perform their obligations under their contracts with us (including commercial contracts, asset sale agreements and other agreements), whether justified or not and whether due to financial constraints (such as reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors; loss of key personnel and inability to attract and retain new talent; disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair our ability to execute our commercial or hedging strategies; the effectiveness of our risk management activities; shortages or cost increases of supplies, materials or labor; maintenance of our credit ratings and ability to receive open credit from our suppliers and trade counterparties; our inability to perform our obligations under our contracts, whether due to non-performance by third parties, including our customers or counterparties, market constraints, third-party constraints, supply chain issues, legal constraints (including governmental orders or guidance), or other factors or events; the incurrence of costs and expenses related to unexpected or unplanned capital or maintenance expenditures, third-party claims or other factors; failure to implement or capitalize, or delays in implementing or capitalizing, on investment capital projects, whether due to permitting delays, permitting withdrawals or other factors; tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, investment capital projects, working capital requirements and the repayment or refinancing of indebtedness; the amplification of other risks caused by volatile or closed financial markets, capital constraints, liquidity concerns and inflation; the use or availability of third-party assets upon which our operations depend and over which we have little or no control; the currency exchange rate of the Canadian dollar to the United States dollar; the deferral of current revenue recognition attributable to deficiency payments received from customers who fail to ship or move their minimum contracted volumes; significant under-utilization of our assets and facilities; increased costs, or lack of availability, of insurance; fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans; risks related to the development and operation of our assets; and other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the processing, transportation, fractionation, storage and marketing of NGL as discussed in the Partnerships’ filings with the Securities and Exchange Commission. About Plains: PAA is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil and natural gas liquids (“NGL”). PAA owns an extensive network of pipeline gathering and transportation systems, in addition to terminalling, storage, processing, fractionation and other infrastructure assets serving key producing basins, transportation corridors and major market hubs and export outlets in the United States and Canada. On average, PAA handles over 9 million barrels per day of crude oil and NGL. PAGP is a publicly traded entity that owns an indirect, non-economic controlling general partner interest in PAA and an indirect limited partner interest in PAA, one of the largest energy infrastructure and logistics companies in North America. PAA and PAGP are headquartered in Houston, Texas. For more information, please visit www.plains.com. Contacts: Blake Fernandez Vice President, Investor Relations (866) 809-1291 Ross Hovde Director, Investor Relations (866) 809-1291