#1Investor Presentation March 2022 PLAINS#2Forward-Looking Statements & Non-GAAP Financial Measures Disclosure ▪ This presentation contains forward-looking statements, including, in particular, statements about the performance, plans, strategies and objectives for future operations of Plains All American Pipeline, L.P. ("PAA") and Plains GP Holdings, L.P. ("PAGP"). These forward-looking statements are based on PAA's current views with respect to future events, based on what we believe to be reasonable assumptions. PAA and PAGP can give no assurance that future results or outcomes will be achieved. Important factors, some of which may be beyond PAA's and PAGP's control, that could cause actual results or outcomes to differ materially from the results or outcomes anticipated in the forward-looking statements are disclosed in PAA's and PAGP's respective filings with the Securities and Exchange Commission. ■This presentation also contains non-GAAP financial measures relating to PAA, such as Adjusted EBITDA attributable to PAA, Implied DCF and Free Cash Flow. A reconciliation of these historical measures to the most directly comparable GAAP measures is available in the Investor Relations section of PAA's and PAGP's website at www.plains.com, select "PAA" or "PAGP," navigate to the "Financial Information" tab, then click on "Non-GAAP Reconciliations." PAA does not provide a reconciliation of non-GAAP financial measures to the equivalent GAAP financial measures on a forward-looking basis as it is impractical to forecast certain items that it has defined as "Selected Items Impacting Comparability" without unreasonable effort. 12#3Plains On a Page Significant multi-year Free Cash Flow (FCF) - Targeting +/- $1.4B in 2022 (+/- $700MM FCFAD(1)) -2022 FCFAD allocation: -75% to debt reduction, -25% to distribution growth / discretionary repurchases - - 2023+: increasing cash returned to equity holders as leverage decreases ■ Critical infrastructure aligned with long-term fundamentals - Tight global energy markets highlighting need for security of global supply; Permian positioned to drive vast majority of U.S. short- cycle production growth in 2022 & beyond; anticipate +/- 600 mb/d of Permian oil production growth for next several years - Highly integrated & flexible system positioned to service volume growth with minimal incremental CAPEX ■ Optimization & emerging energy opportunities - Capital-efficient optimization and/or brownfield asset expansion, strategic JVs, etc. - Formed Plains' Emerging Energy team, advancing multiple opportunities 2022(G): Furnished February 9, 2022. (1) See Definitions. 13#4Plains: Critical Infrastructure, Integrated Model Full-service: supply aggregation, quality segregation, flow assurance, access to multiple markets Crude Oil Activities Producers Pipeline Pipeline Refiners Truck Truck Storage/Terminalling Rall NGL Activities Pipeline SPEC PRODUCTS Natural Gas Ethane (C2) Propane (C3) Butane (C4) Producers Truck Pentane (C5) Rail International Export Bullets Pipeline Spheres Truck Fractionation & Rail Gas Processing Rail Caverns Consumers Diluent for Heavy Crude Chemical Plants International Export Crude Oil (blue) NGL (red) 4#5Overview of Plains' Business Integrated model across crude & NGL business platforms Crude Oil Segment ■ Assets: Pipelines, storage, terminalling & trucks ■ Commercial Profile: long-term minimum volume commitments, acreage dedications, leased capacity & spot utilization ■ Drivers: Demand /production growth, volume throughput ~18k >6 mmb/d Crude Pipeline >1 mmb/d Crude Purchase Volume Crude Pipeline Miles >110 mmbbls Crude Storage Capacity Note: Operating & asset-level data as of 12/31/21. Tariff Volume 4 Crude Oil Marine Facilities NGL Segment ■ Assets: Fractionation, straddle, pipelines, storage, terminalling & rail capacity Commercial Profile: Gathering / fractionation / storage/terminalling services agreements, gas processing / straddle production & merchant activities ■ Drivers: Frac spread, supply volume & regional pricing differentials >130 mb/d -200 mb/d -6 bcf/d NGL NGL Fractionation Straddle Sales Capacity Capacity ~30 mmbbls 3,900 NGL Storage Capacity NGL Rail Cars 15#6Fundamentals: Increasing Demand, Tighter Oil Balance North American hydrocarbons are key to meeting global demand Global Supply & Demand Rebalancing (1) World Production Including Historical OPEC Spare Capacity MMB/d 110 105 100 95 90 85 80 2016-Q1 2016-Q3 2017-Q1 MMB/d 15 10 2017-Q3 2018-Q1 2018-Q3 2019-Q1 World Consumption COVID reset 2019-Q3 2020-Q1 Prolonged Reduction in Upstream Investment (2) ($ Billions invested) $800 $600 $400 $200 2020-Q3 2021-Q1 2021-Q3 2022-Q1 2022-Q3 Multi-Quarter Draw on Global Inventory(1) implied build 0 implied draw -5 2016-Q1 2016-Q3 * 2017-01 2017-Q3 2018-Q1 2018-Q3 1+ B bbls 2019-Q1 2019-Q3 2020-Q1 2020-Q3 2021-Q1 2021-Q3 2022-Q1 2022-Q3 $0 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Commodity Prices Responding ($/bbl) $120 WTI Spot Price, monthly avg. (LHS) $90 myy ($/mmbtu) $7 $6 $5 $60 $30 ཿ €&°$་ྲ $2 Henry Hub Spot Price, monthly avg. (RHS) $0 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 6 (1) EIA February 2022 STEO (includes crude oil (including lease condensates), natural gas plant liquids, biofuels, other liquids, and refinery processing gains). (2) IEA & PAA Internal Estimates#7Levers for Maximizing FCF and Unitholder Returns Permian NGL ■ Capture volume growth with minimal CAPEX ✓ Anticipate +/- 600 mb/d of production growth for next several years ✓ Operating leverage can enable throughput & tariff benefit Optimize NGL facilities, operations & ownership Execute high-return, capital-efficient optimization and/or brownfield expansion projects Optimization ◉ Optimize existing assets (brownfield asset expansion, strategic JVs, etc.) Align leading Canadian cavern storage position with renewable opportunities Evaluate renewable power opportunities to lower emissions / costs ◉ Deliver significant multi-year FCF (maintain capital discipline) Financial ■ Achieve targeted leverage Increase cash returned to equity holders over time (significant coverage / FCFaD) 17#8Permian Key to Meeting Global Energy Demand Expect Permian to Drive Vast Majority of U.S. Short-Cycle Production Growth New Supply Development Breakevens (1) Permian Positioned for Multi-Year Growth (3) Mb/d US Permian $40 8,000 Deepwater GOM/Brazil $44 "Nameplate" Takeaway Capacity 7,000 US Shale, Non-Permian $45 North Sea $51 6,000 "Efficient" Operating Capacity (90% of Nameplate) Oil Sands $52 5,000 Fiscal Breakevens(2) 4,000 2+ MMB/d (>80% of total U.S. growth) Libya $55 3,000 Iraq Kuwait United Arab Emirates $64 $66 2,000 $69 1,000 Saudi Arabia Iran $82 Crude Oil Production (blue) $361 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 (1) S&P Global Platts ($/Bbl, Brent) (2) International Monetary Fund ($/Bbl, Brent) (3) PAA Estimates, Enverus 8#9◉ Committed Permian Acreage & Term Supply Supports Long-Term Volume Security & Operating Leverage on Plains' Systems High-quality, long-term committed acreage dedicated to Permian JV gathering systems - ~4mm acres, ~6.5-yr wtd. avg. term Producer Profile: ~80% Public / -20% Private (acreage weighted) Multi-decade inventory life, vast majority with projected IRR of 25% - 50%+ (~$50 / Bbl WTI) in both Delaware & Midland Basins ■ 1st purchase lease supply: ~1.1 mmb/d, >80% term contracted Note: Plains' gathering business is conducted through our 65% ownership in the Plains Oryx Permian JV. Permian JV Gathering (other Plains assets in grey) 9#10◉ Long-Haul Pipelines Substantially Backed by Long-Term 3rd Party Contractual Commitments Combination of supply-push and demand-pull pipelines Integrated with Plains' hub terminals at Cushing, Midland, Patoka and St. James Key long-haul pipes >70% 3rd party contracted (1) with average remaining term of 5-years: - - Permian Long-Haul: >70% (>90% excl. Basin); ~5 years Rockies to Cushing (2): >60%; >4 years Downstream of Cushing: >70%; ~5 years ■ Further complemented by: Long-term committed acreage dedicated to Permian gathering systems Term-contracted 1st purchased lease supply (1) Based on 90% of nameplate capacity (2) Includes Saddlehorn and White Cliffs Pipeline systems H 10#11Crude Oil Hub Terminals: Leading Demand-Hub Positioning Enables Pipeline & Commercial Opportunities, Strong Connectivity Supports Demand Keystone Saddlehorn PAA MS Lime (2) Stack JV 16" SEMG Whitecliffs Stack JV 10/12" Great Salt Plains Glass Mountain Spearhead Sun Centurion PAA (Basin) Flanagan South Pony Express Centurion Reversal Dakota Access Mustang Patoka West Centurion Midland Iraan P66 Borger Oryx 1 P66 Ponca Oryx II Cimarron Midway Pipeline Beta Crude Connector #1 BP Ozark Cushing Eagle North Pipeline Munger Sun (27MM capacity) Floyd Greenwood Osage Seaway Twin Reliance Rangeland PAA (Diamond) PAA (Red River) Keystone Market Link Seaway Basin | Basin II Medallion Glasscock Energy Transfer Enterprise Terminal Muster SJRT Rail SPR/XOM Sugarland PAA Barge Dock Husky Lima Refinery Marathon Robinson Refinery Marathon Catlettsburg Refinery Ship Shoal Chicap Shell (Houma) Bayou Bridge Basin Energy Transfer Mesa Cactus Cactus II Permian(1) (19MM capacity) Sunrise I Sunrise II Iraan Enterprise Terminall Enterprise Terminal II Wink to Webster XOM North PAA Barge Dock SPR/XOM Sugarland Red Stick / SPR Southern Access Extension Patoka (7MM capacity) Crimson Line CountryMark Mt. Vernon Refinery St. James (15MM capacity) NuStar Capwood Keystone PAA Ship Dock 1 & 2 LOOP/LOCAP WoodPat Inbound Pipelines (includes direct & Outbound Pipelines indirect connections) Capline Mainline Capline Terminal (1) Capacity includes all Permian Area storage; connections only include Midland connectivity. Patoka West Capline LOCAP PAA Ship Dock 1 & 2 Capline Terminal 11#12NGL Segment: Highly Integrated & Strategically Positioned Assets Aggregate, Process, Transport & Sell Directional Illustration 1 Aggregate western Canada field supply & extract/purchase NGL mix at straddles (Empress & Cochrane) 2 Fractionate western supply into component products, sell locally and/or transport raw NGL / mix to downstream markets Grande Prairie Co-Ed Pipeline Ownership: 100% Capacity: 70 mb/d 12 Red Dear Coll Lake Fort Saskatchewan Ownership: 100% PFS, 21% KFS Capacity: 105 mb/d Frac (~85 PFS/ -20 KFS) Prince A PPTC Pipeline North Saskatoon Ownership: 100% Capacity: 16 mb/d Dauphin 1 Calgary 12 Moose Monipeg Brandon ne Hat Enbridge Mainline Cochrane Straddle 3rd party owned, long-term liquids supply agreement Spokane Hema Empress I,II, V & VI Ownership: Various led Lake Frac PAA Capacities ~200 mb/d Straddle ~6 bcf/d Storage -30 mmbbls Pipeline 300 mb/d Sarnia Ownership: 75% Capacity: 90 mb/d Frac Saut Ste Mave nick 3 Fractionate at Sarnia, seasonally store & sell products in peak demand (Winter) months in Ontario / U.S. markets PAA NGL Hubs(1) PAA NGL Pipelines ■■■ Enbridge Mainline Note: Asset-level data as of 12/31/21. (1) Not all PAA NGL assets included within map. Capacity: ~6 bcf/d Straddle; ~20 mb/d Frac Pere Menepols Windsor & St. Clair Ownership: 100% Capacity: 4 mmbbls of storage Moe London 12#13Large Footprint with Strong History of / Opportunities for Accretive Optimization ■ With maturation of the industry, Plains' commercial focus shifted from large capital projects to aligning assets with natural owners, partners & shippers ■ Efforts have lead to multiple opportunities: - - ~$4.5B in cumulative asset sales since 2016 (combination of non-core sales & strategic JVs) 15+ strategic JVs, including multiple large-scale pipeline combinations О W2W, Saddlehorn, White Cliffs, EF JV, Stack JV - Recent creative win-win deals include: 。 Asset swap of crude pipeline for increased interest in Empress O Permian Oryx JV - cashless, debt-free transaction aligning interests of two large-scale Permian footprints, provides increased connectivity, flexibility & access to markets ■ Continue to advance additional optimization opportunities, including high-return, brownfield & emerging energy 13#14Emerging Energy Team ■ Cross-functional team led by Vice President of Emerging Energy & Process Optimization Evaluating wide range of energy evolution opportunities through thoughtful and disciplined approach in and around our assets and core competencies ■ - Includes: hydrogen and carbon-related infrastructure, solar and low-carbon fuels Seeking to align leading Canadian cavern storage position with renewable opportunities Key objectives of Plains' Emerging Energy team: - Optimizing / repurposing assets Reducing GHG emissions Evaluating emerging energy alternatives ■ Committed to maintaining capital discipline and increasing returns to equity holders F 14#152022(G): Financial Metrics (as furnished February 9th 2022) Generating strong FCF, strong coverage & continuing leverage reduction ($ millions, except per-unit metrics) Adjusted EBITDA/DCF Cash Flow 2021 2022(G) (+/-) Segment Adjusted EBITDA Cash Flow from Ops (CFFO)(1) $1,996 $2,100 2021 2022(G) (+/-) Asset Sales $875 $100(5) Crude Oil $1,909 $1,820 FCF(1) $2,369 NGL 285 380 $1,400 FCFAD(¹) $1,654 $700 Other Income 2 Capital Adj. EBITDA attributable to PAA $2,196 $2,200 2021 2022(G) (+/-) Implied DCF to Common $1,475 $1,450 Net to PAA Net to PAA Consolidated Implied DCF/CUE(1) Investment $225 $2.06 $2.08 $275 $330 Permian JV $18 $110 $165 Distribution Coverage (Common) 285%(2) 250%(3) Other $208 $165 $165 Year-End Leverage Ratio (1,4) 4.5x 4.25x Maintenance $168 $210 $220 Total $393 $485 $550 2022(G): Furnished February 9, 2022. (1) See Definitions. (2) Reflects the current annualized distribution rate of $0.72 per common unit. (3) 2022(G) Distribution Coverage reflects cash distribution per common unit paid in February and the proposed increased annualized distribution rate of $0.87 per common unit for the remainder of the year. (4) YE-21 includes pro-forma debt reduction effective 1Q22 requiring -$450MM of cash on balance sheet. (5) Includes $50MM of asset sales originally expected to close in 2021. Note: Please visit https://ir.paalp.com for reconciliation of Non-GAAP financial measures reflected above to most directly comparable GAAP measures. 15#162022(G): Operational Metrics (as furnished February 9th 2022) Continued growth in Permian volumes; shift in mix to fill Wink-to-Webster (W2W) MVCS Operational Guidance ■ Permian assets leveraged to production growth (table data reflects full-year averages) 2021 2022(G) (+/-) Crude Oil Segment Crude Pipeline Volumes (mb/d) 6,205 7.150(1) - Permian 4,412 5,250(1) Other 1,793 1,900 Commercial Storage Capacity (mmbbls/mo) 73 72 NGL Segment NGL Sales (mb/d) 141 140 Fractionation Volumes (mb/d) 129 120 140 4Q21: includes ~650 mb/d from legacy Oryx systems (~160 mb/d of FY-21 avg.) 2022: includes 350 mb/d of total growth, reflecting: Increased throughput on JV systems, partially offset by lower long- haul (certain uncontracted volume on Plains' systems shifting to fill W2W MVCs; lower reported volume due to PAA 16% W2W ownership) ■ "Other" includes Capline MVC contribution ■ NGL operating profile generally consistent Y/Y 2022 EBITDA growth primarily driven by stronger NGL margins 2022(G): Furnished February 9, 2022. (1) 2022 pipeline volumes associated with Permian JV are presented on a consolidated (8/8ths) basis. See Definitions. 16#17Current Financial Profile Moody's: Baa3, Stable Upgraded to IG by Moody's (Nov-21) ■ Reduced total debt $1B since YE-20 (~$450MM of cash for 2022 debt reduction) Retiring $750MM Sr. Notes 3/1/22 Expected YE-22 Leverage Ratio (2): +/- 4.25x S&P/Fitch: BBB-, Stable 12/31/20 12/31/21 A Cash & Equivalents $22 $449 +$425 ◉ Short-Term Debt $831 $822 Long-Term Debt Total Debt $10,213 $9,382 $8,398 $9,220 ($1,000) Adj. EBITDA (LTM)(1) $2,546 $2,196 Credit Stats & Liquidity Leverage Ratio(2) 4.5x 4.5x(3) Targets 3.75x-4.25x LT Debt/Adj. EBITDA (LTM)(1) 3.7x 3.8x 3.00x -3.50x Committed Liquidity ($ bln) $2.2 $3.0 2022(G): Furnished February 9, 2022. (1) Attributable to PAA. (2) See Definitions. (3) Includes pro-forma debt reduction effective in 1Q22 requiring -$450MM of YE-21 cash on balance sheet. Note: Please visit https://ir.paalp.com for reconciliation of Non-GAAP financial measures reflected above to most directly comparable GAAP measures. 17#18Disciplined Capital Investment Multi-Year Buildout Complete, Significant Operating Leverage, Focused on High-Return Projects ($ millions) Investment -$1,380 Feb(G), less: ~$230MM Consolidated Net to PAA +/-$275 +/-$330 $225 Maintenance -$250 $168 $35MM NGL +/-$210 +/-$220 facility 3 Year Avg. (2018-2020) 2021 Actual turnaround 2022 (G) 2022 (G) (Net to PAA) Feb(G): Initial 2021 guidance furnished February 9, 2021. 2022(G) and Run Rate: Furnished February 9, 2022. (1) Average annual estimate: annual amount may be impacted by timing and/or turnaround projects. ■ Consolidated Run Rate Investment: $250MM - $350MM - - ~50% Wellhead & CDP Connections (paced w/ producer activity levels) Expect to capture synergies through Permian JV ■ Consolidated Run Rate Maintenance(1): <$200MM F 18#19Financial Strategy & Capital Allocation Priorities Maximizing FCF & increasing allocation to equity holders as leverage decreases Financial Strategy Maintain ☐ Achieve Investment Grade credit ratings Capital Allocation Priorities Higher Leverage More to Debt Reduction Lower Leverage More to Equity Holders Distribution coverage ≥ 130% long-term goal (1) See Definitions. Self-fund disciplined investments Significant liquidity & financial flexibility Achieve targeted leverage ratio (1): 3.75x-4.25x Achieve Mid-BBB / Baa Credit Ratings Equity Returns Increase Cash Returned to Equity Holders Disciplined Investments High Return, "Must Do, No Regrets" Capital Debt Reduction Achieve Targeted Leverage 19#20Sources & Uses of Cash Continuing debt reduction while increasing returns to equity holders over time 2021 2022 Guidance 2023& Beyond (Directional Allocation) 11% Repurchases $875 Distribution growth/ discretionary repurchases Higher Leverage Asset Sales Debt Reduction 89% (1) $1,654 FCFAD ($779 excl. asset sales) +/- $100 Asset Sales More to Debt Reduction Lower Leverage More to Equity Holders -25% Debt Reduction FCFaD(2) +/- $700 long-term goal -75% Distributions to Non-Controlling $1,996 CFFO Distributions to Non-Controlling Сарех +/-$2,100 CFFO Capex ■ Reduce debt / leverage ■ Increase cash to equity holders over time ☐ Distribution growth / Discretionary repurchases Equity return considerations: - Business outlook Sources Distributions (current level $0.72/unit) Uses Sources Distributions (current level $0.72/unit) Uses 2022(G): Furnished February 9, 2022. (1) Includes pro-forma debt reduction effective 1Q22 utilizing -$450MM of YE-21 cash on balance sheet. (2) See Definitions. Please visit https://ir.paalp.com for reconciliation of Non-GAAP financial measures reflected above to most directly comparable GAAP measures. - Leverage - Valuation/current yield H 20#21Investment Considerations Significant multi-year Free Cash Flow (FCF) - - Targeting +/- $1.4B in 2022 (+/- $700MM FCFAD (¹)) -2022 FCFAD allocation: -75% to debt reduction, -25% to distribution growth / discretionary repurchases - - 2023+: increasing cash returned to equity holders as leverage decreases ■ Critical infrastructure aligned with long-term fundamentals - Tight global energy markets highlighting need for security of global supply; Permian positioned to drive vast majority of U.S. short- cycle production growth in 2022 & beyond; anticipate +/- 600 mb/d of Permian oil production growth for next several years - Highly integrated & flexible system positioned to service volume growth with minimal incremental CAPEX ■ Optimization & emerging energy opportunities - Capital-efficient optimization and/or brownfield asset expansion, strategic JVs, etc. Formed Plains' Emerging Energy team, advancing multiple opportunities 2022(G): Furnished February 9, 2022. (1) See Definitions. 21#22Sustainability For full sustainability report and disclosures, please visit https://www.plains.com/sustainability. PLAINS#23■ Plains 2020 Sustainability Report Highlights Comprehensive description of Sustainability program, strategy and performance, along with 130+ quantitative metrics (expanded from 64 in 2019), highlights include: -20% 3-yr GHG reduction; total emissions compare favorably to peers Formed new HSE & Sustainability Board Committee Continued expansion and refinement of philanthropy and volunteerism efforts ■ Enhanced alignment with Energy Infrastructure Council (EIC), Sustainability Accounting Standards Board (SASB) and Global Reporting Initiative (GRI) frameworks ☐ ■ Welcome your feedback on our Sustainability report and overall program 23#24Scope 1 & 2 Emissions ~20% improvement over last 3 years Total Scope 1+ Scope 2 GHG Emissions (mmt CO2e) ~20% reduction 2020 Scope 1 Emissions 2% Methane 2.4 2.2 1.9 2018 2019 2020 Evaluating an emissions reduction target -- 98% Other Emissions H 24#25Context for Emissions Estimations & Comparisons Emissions estimation methodologies vary across the industry - - - Plains reported comprehensive emissions for the full enterprise Includes all material activities (i.e. pipeline, trucking, storage, fractionation. and processing) Guidance on emissions estimation metrics (e.g. throughput intensity, Scope 3) continues. to evolve 。 Diversity of Plains' activities present unique considerations for these calculations, as a result, Plains is not currently reporting these metrics We continue to actively engage in the development of estimation standards, considering updates to disclosures as guidance evolves 25#26Emissions in Perspective 2019 Total Scope 1 + Scope 2 GHG Emissions Among Peers (1) (mmt CO2e) 18 Average 16 14 12 10 8 6 4 2 0 A B C D E F G Plains H (1) Peers based on Plains' 2020 Total Shareholder Return Proxy Group where data is available; Peer data in certain cases contains emissions from parent company activities which may not be directly comparable to our business. (2) Global Carbon Project, 2019 (3) U.S. EPA, 2019 (4) Includes Scope 1 and 2 emissions. Worldwide Emissions (mmt CO2e)(2) 43.100 Energy & Non-energy Sources 36,800 Energy Sources U.S. Emissions (mmt CO2e)(3) 6,600 Energy & Non-energy Sources 5,400 Energy-related Plains Emissions (mmt CO2e)(4) 2 26#27Plains' Governance Closely Aligned with C-Corps ■ 100% of Directors subject to public election (staggered 3-yr rolling basis) Mandatory Majority-Independence - currently 73% ■ Lead Independent Director, alongside Chairman, responsible for leading one Unified Board of Directors (PAA & PAGP) ☐ Significant Board and Executive Equity Ownership ■ No Incentive Distribution Rights ("IDRs") or "Golden Share" (¹) ■ Significant Variable / At-risk Executive Compensation Structure (88% for CEO, 83% avg. for other Named Executive Officers) 1 for 1 Economic & Voting Rights PAA GP HOLDINGS LLC (PAGP GP) (Unified Board of Directors) PLAINS GP HOLDINGS (Nasdaq: PAGP) 1099 SECURITY (Public Investors) PLAINS AAP, L.P. (AAP) (2) (Private Owners & Management) PLAINS ALL AMERICAN PIPELINE, L.P. (Nasdaq: PAA) K-1 SECURITY Public Investors • Series A & B Preferred • 100% of Plains' assets & operations (1) Incentive Distribution Rights ("IDRS") give a general partner an increasing share of incremental distributable cash flow based upon certain conditions. "Golden Share" refers to a control right granted in certain partnership agreements whereby the holder has the right to direct certain activities of the partnership, including the unilateral right to appoint and replace board members, irrespective of the holder's economic interest. (2) Right to exchange AAP Unit for PAGP Class A Share, or alternatively, right to redeem AAP Unit for PAA Common Unit 27#28Multiple Enhancements to Executive Compensation Aligned with Investor Feedback ■ Have engaged independent compensation consultant and have proactively sought investor feedback Examples of recent enhancements: - 2018: Converted annual bonus program to a more formula-based model (includes target metrics for per-unit financial results and Safety & Environmental improvements) - 2019: Implemented annual compensation benchmark studies via 3rd party compensation consultant 2020: Compensation Committee composed of 100% independent directors 2020: Added TSR Metric to LTI program (considered various returns-based incentive metrics) - 2020: Added S&P 500 to TSR benchmarking group used in LTI program - - 2020: Increased multi-year accountability (3-yr cumulative) to DCF / CUE() metric in LTI program 2020: Added Leverage Modifier to DCF/CUE metric in LTI program - aligns w/ company deleveraging goals - (1) See Definitions. 2020: Adopted Clawback Policy and Equity Ownership Guidelines 28#29Appendix PLAINS#30Hydrocarbons Remain Critical to Supply Global Energy Demand North America key to global supply response ■ Tight global energy markets highlighting need for security of global supply - Global demand approaching pre-COVID levels, against a backdrop of prolonged reduction in upstream investment & continued OPEC discipline Commodity prices responding ■ North American energy supply key to global demand; Permian positioned to drive growth - North America offers most responsibly produced hydrocarbon supply available - U.S. short-cycle shale among most economic and well positioned supply options available Permian positioned to drive vast majority of U.S. short-cycle production growth in 2022 and beyond ■ Plains positioned to generate significant +FCF, reduce debt, increase cash returned to equity holders - Significant operating leverage, positioned to capture Permian growth H 30#31North American Energy: The Responsibly Produced Option TOP 10 LIQUIDS PRODUCING NATIONS MMB/D AT YE2021 UN SDG RANK (LOWER IS FAVORABLE) USA Canada 20.0 SAUDI ARABIA 11.9 RUSSIA 11.2 CANADA 5.8 IRAQ 5.2 CHINA 4.9 UAE 3.5 BRAZIL 3.2 KUWAIT 3.1 IRAN 2.9 0 5 10 15 20 Source: EIA February 2022 STEO. Liquids includes production of crude oil (including lease condensates), natural gas plant liquids, biofuels, other liquids, and refinery processing gains. 25 25 21 USA 32 32 Russia 46 China 57 Brazil 61 UAE 71 Iran 74 Saudi Arabia 98 Iraq Kuwait 0 20 105 113 40 60 50 80 100 120 2021 Country ranking relative to UN Sustainable Development Goals (SDG) 31#324Q & FY 2021 Earnings Call Highlights & Outlook (Feb 9th) Solid execution, reducing debt & returning cash to equity holders Since 3Q21 Call 2022 Outlook ◉ Adj. EBITDA (¹): 4Q $564MM / FY 2021 $2,196MM Equity Repurchases: 4Q $61MM / FY 2021 $175MM Moody's upgrade to Investment Grade (Baa3, Stable) Capline Reversal & Wink-to-Webster placed into service Adj. EBITDA(G)(¹) +/- $2.2B: Growth of ~$200MM YoY normalized for unique 2021 items Forecast +/- $1.4B FCF (+/- $700MM FCFAD(2)) & YE-22 leverage (2) +/- 4.25x ■ Intend to recommend $0.15/unit annualized distribution increase to Board 2022(G): Furnished February 9, 2022. (1) Attributable to PAA. (2) See Definitions. Please visit https://ir.paalp.com for a reconciliation of Non-GAAP financial measures reflected above to most directly comparable GAAP measures. F 32#332021 Execution & Results Reinforces Positioning for 2022+ Maximizing ✓ ~$1.65B of FCFAD (~$600MM increase from Feb(G)) FCF Capital Allocation ✓ Stronger asset sales ~$125MM ($875MM total), ↓ Capex ~$230MM, ↑ Adj. EBITDA ~$65MM ✓ ~$1B debt reduction & ~$450MM cash on balance sheet(1) ✓ $175MM common equity repurchases ($228MM since inception) Optimizing ✓ W2W & Capline in-service Portfolio ✓ Closed Plains Oryx Permian JV - integration / synergy capture on track ✓ Improved transparency w/ 2x ↑ in disclosures ✓ Formed Emerging Energy team Sustainability (ESG) Feb(G): Furnished February 9, 2021. ✓ ~20% GHG emissions reduction in last 3-yrs. ✓ Safety performance improved >50% since 2017 ✓ 100% of directors now subject to election ✓ 2021 safety performance flat to 2020; however, Incident severity reduced 25%+; lost time days reduced 90%+ (1) Majority of cash to be allocated to debt reduction effective 1Q22. 33#34Key Drivers: 2021 vs. 2022(G) 2022 growth offsetting 2021 unique items (Adj. EBITDA attributable to PAA, $ millions) Feb(G): $2,150 2021 Unique Items: (~$200MM) 2022 Growth Items: ~$200MM $2,196* Margin-Based Activities PNG Sale & Winter Storm Contango (-) Uri Benefit ■ Canada crude differentials (-) ■ NGL margins (+) Permian ■ Volume growth Projects ■ W2W Capline Ft. Sask/ Other JV synergies ■ Tariff escalators offsetting inflation Pipeline Loss Allowance (PLA) 2021 2022(G): Full-year 2022 guidance furnished February 9, 2022. *Excludes $17MM Red River Noncontrolling Interest; 2021 pro-forma Adj. EBITDA attributable to PAA of $2,213MM is most comparable to Feb(G) of $2,150MM, furnished February 9, 2021. Note: Please visit https://ir.paalp.com for reconciliation of Non-GAAP financial measures reflected above to most directly comparable GAAP measures. +/- $2,200 2022(G) 34#354Q21 Earnings Call Key Takeaways 2021 2022 2023+ Maximize FCF $1.65B FCFAD (+ $600MM from Feb(G)) $1.4B FCF ($700MM FCFAD(1)) Expecting meaningful FCF Capital Discipline Capex $230MM from Feb(G) Capital Allocation Fundamentals ~$1B debt; $175MM repurchases Permian production: +540 mb/d (YE21 vs. YE20) Optimizing Portfolio $875MM asset sales; Permian Gathering JV Other New segments ↑ ESG Disclosure, 3yr. Emissions ↓ ~20% New Emerging Energy Group. Feb(G): Furnished February 9, 2021. 2022(G): Furnished February 9, 2022. (1) See Definitions. Note: Please visit https://ir.paalp.com for reconciliation of Non-GAAP financial measures reflected above to most directly comparable GAAP measures. Run-Rate (Investment & MCX) <$550MM/yr Increasing % of FCF allocated to equity holders as leverage decreases (intend to recommend distribution increase 1Q22) Expect Permian production +/- 600 mb/d annual growth Significant operating leverage within system Continued optimization / rationalization Emerging Energy opportunities H 35#36Overview of 2022 Goals Run a safe, reliable and responsible operation Generate meaningful Free Cash Flow Strengthen balance sheet/financial flexibility Increase Returns to Equity Holders PLAINS ALL AMERICAN H 36#37Free Cash Flow: Historical Detail GAAP CFFO to Non-GAAP FCF 2016 2017 2018 2019 1Q20 2Q20 3Q20 4Q20 2020 1Q21 2Q21 3Q21 4Q21 2021 (4) (2) $ (544) $ 927 $ 1,795 $ (1,627) (1,391) (1,032) Net Cash Provided by Op. Activities (GAAP) Net Cash (Used in) / Provided by Investing Activities Cash Contributions from Noncontrolling Interests Cash Distributions Paid to Noncontrolling Interests (1) Sale of Noncontrolling Interest in a Sub Free Cash Flow (non-GAAP) Total Distributions (2) $ 733 $ 2,499 $ 2,608 $ 2,504 $ 890 $ (1,273) (1,570) (813) 84 $ 282 $ 258 $1,514 $ 791 $ 235 $ 336 $ 635 $ 1,996 (1,765) (610) 8 (248) 2 (208) 1 (27) (1,093) (108) (175) 761 (92) 386 12 1 - 1 (6) (4) (2) (4) (10) (6) (4) (14) 128 861 $ 288 $ (166) $ 73 $ 228 $ 423 $ 678 $ 60 $1,093 $ 539 $2,369 (1,202) (299) (193) (168) (193) (853) (167) (192) (166) (190) (715) FCF after Distributions (non-GAAP) $ (2,171) $ (464) $ 763 $ (341) $ (11) $ (359) $ (95) $ 35 $ (430) $ 511 $ (132) $ 927 $ 349 $ 1,654 Expect to generate meaningful multi-year Free Cash Flow based on financial performance and continued capital discipline Note: Does not factor in material, unforeseen changes in ST working capital, i.e. hedged inventory storage activities/volume/price / margin (1) Cash distributions paid during the period presented. (2) Cash distributions paid to our preferred and common unitholders during the period presented. The 2016 period also includes distributions paid to our general partner. Management uses the non-GAAP financial measures Free Cash Flow ("FCF") and Free Cash Flow after Distributions ("FCFAD") to assess the amount of cash that is available for distributions, debt repayments, equity repurchases and other general partnership purposes. FCF is defined as net cash provided by operating activities, less net cash used in investing activities, which primarily includes acquisition, expansion and maintenance capital expenditures, investments in unconsolidated entities and the impact from the purchase and sale of linefill and base gas, net of proceeds from the sales of assets and further impacted by distributions to, contributions from and proceeds from the sale of noncontrolling interests. FCF is further reduced by cash distributions paid to preferred and common unitholders to arrive at FCF after Distributions. Our definition and calculation of FCF may not be comparable to similarly-titled measures of other companies. FCF and FCF after Distributions are reconciled to net cash flows from operating activities, the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our Consolidated Financial Statements and accompanying notes. 37#38Permian to USGC: Wink to Webster Wink Wink to Webster Permian JV Gathering (other Plains assets in grey) Midland Houston Area wink to webster Current Status PIPELINE Midland-to-Webster - interim service Jan-2021 MVCs ramping from 1Q22 through 2023 ■ Deferred portion of investment to align w/ MVC ramp Project Overview ■ ~1.5 mmb/d capacity (36" diameter) ■ Highly contracted, long-term MVCS Origins: Wink & Midland ■ Destinations: ECHO, Webster, Baytown, TX City ■ W2W JV ownership: 71% of capacity ■ PAA: 16% of W2W JV ownership ■ Other JV partners: XOM, Lotus, MPLX, DK, RTLR UJI w/ EPD: 29%, Midland-to-Webster segment 38#39Patoka to St. James: Capline Reversal Patoka Current Status In-service as of Jan-2022 ■ Initial throughput ~100mb/d, with additional capacity to meet growth in Canadian production Project Overview Capline System (other Plains assets in grey) ☐ Reversal of 40" pipe to southbound service Capline St. James Origin: Patoka, Illinois ■ Destination: St. James, Louisiana ■ PAA JV ownership: ~54% (non-operated equity interest asset) ■ Other JV partners: MPC & BP H 39#40Crude Segment Detailed Data (2019 - 2021) Crude Oil Segment Considerations / Context: ~$1.4B in non-core / strategic JV asset sales since 2019 Pipeline Tariff Volumes (2) (mb/d) 6,201 6,522 6,807 6,911 6,974 7,202(3) 5,656 5,868 5,835 6,006 6,162 - Outsized margin capture 2019 - 2021; not expected to continue in 2022 COVID-19 production reset - L48 onshore ↓ >2MMB/D from Mar-20 peak 5,430 Other Quarterly (Segment Adj. EBITDA(1), $MM) Annual (Segment Adj. EBITDA(1), $MM) $2,753 $2,216 $1,909 +/- $1,820 Permian 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 Storage Capacity (mmbls/mo) 75 76 77 77 78 79 81 76 73 73 73 72 Other Cushing 2019 2020 2021 2022(G) 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 1st Purchase Volumes (mb/d) $727 $659 $681 $684 $638 $639 $553 $472 $465 $474 $459 $423 1,271 1,318 1,352 1,372 1,419 1,128 1,102 1,146 1,077 1,147 1,155 1,174 Other Permian 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 2022(G): Furnished February 9, 2022. (1) See Definitions. (2) Excludes trucking (3) Includes -650 mb/d of legacy Oryx volume. 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 40#41Plains' Permian Tariff Volumes (tariff volumes in MB/d) 5,297 Winter Storm Impact 4,427 4,394 1,146 Long-Haul 4,189 1,048 3,753 1,110 1,020 835 1,905 Intra-Basin 1,907 1,687 1,762 1,602 Oryx 649 2,246 Gathering 1,472 1,316 1,482 1,522 1,597 FY20 1Q21 2Q21 3Q21 4Q21 (1) Represents full-year averages. 41#42NGL Segment Detailed Data (2019-2021) ■ NGL Segment Considerations / Context: - ~$175MM in non-core asset sales since 2019 Seasonally stronger demand / sales in winter months Frac spread hedging & 3rd party contracts helps improve predictability $467 Fractionation (mb/d) 157 154 137 140 142 144 122 129 129 127 110 119 Quarterly (Segment Adj. EBITDA(1), $MM) Annual (Segment Adj. EBITDA(1), $MM) +/- $380 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 $327 $285 2019 2020 2021 Stronger earnings in winter months (Q1 & Q4) 2022(G) 328 NGL Sales (mb/d) 221 220 $202 $173 158 124 $153 $141 220 178 94 83 148 112 87 $89 $69 $52 $41 $49 $38 $54 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 $21 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 2022(G): Furnished February 9, 2022. (1) See Definitions. 42#43Empress (mb/d) Additional NGL Detail: Fractionation Volumes by Asset Fort Sask 59 51 53 54 49 46 48 45 45 42 42 29 20 20 20 20 17 18 18 18 19 20 20 222 22 23 23 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 (1) 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 Sarnia Other 73 56 51 53 53 50 51 46 45 41 40 62 22 18 16 24 22 14 20 i laut 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 (1) 8 9 13 11 11 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 (1) Throughput volume impacted by Fort Sask Incident. 43#44Crude Oil & NGL Segment Detailed Data (2021 by Quarter) Revenues Purchases and related costs Field operating costs Segment general and administrative expenses Equity earnings in unconsolidated entities Adjustments: Depreciation and amortization of unconsolidated entities (Gains)/losses from derivative activities and inventory valuation adjustments Long-term inventory costing adjustments Deficiencies under minimum volume commitments, net Equity-indexed compensation expense Net (gain)/loss on foreign currency revaluation Line 901 incident Significant transaction-related expenses Adjusted EBITDA attributable to noncontrolling interests Segment Adjusted EBITDA Operational Data Crude Oil Crude Oil Pipeline Tariff Volumes (By Region, mb/d): Permian Basin South Texas / Eagle Ford Mid-Continent Gulf Coast Rocky Mountain Western Three Months Ended Three Months Ended March 31, 2021 June 30, 2021 Three Months Ended September 30, 2021 Three Months Ended December 31, 2021 Twelve Months Ended December 31, 2021 Crude Oil NGL Crude Oil NGL Crude Oil NGL Crude Oil NGL Crude Oil NGL 7,853 $ 639 9,779 $ 230 10,701 $ 166 12,137 $ 934 40.470 $ 1,968 (7,047) (454) (9,127) (229) (9,971) (194) (11,394) (448) (37,540) (1,324) (165) (54) (203) (49) (213) (61) (242) (77) (824) (241) (50) (17) (54) (18) (48) (19) (70) (17) (221) (71) 88 33 70 83 - 274 20 68 21 14 123 (159) (39) 76 87 (158) 171 (9) (239) (252) (19) (35) (6) (27) (3) (10) (2) (11) (67) (27) (32) 6 - 56 - (38) (7) 5 4 - 5 1 5 19 (1) (1) 3 (5) (1) (3) (1) 15 15 3 2 11 16 (3) (4) (6) (82) (94) S 474 S 69 $ 553 $ 21 $ 459 $ 54 423 $ 141 $ 1,909 $ 285 3,753 4,189 4.394 5,297 4,412 320 314 311 358 326 373 467 483 495 455 145 159 176 151 158 287 327 344 367 332 - 237 256 224 228 236 Canada 315 294 230 306 286 Total Crude Oil Pipeline Tariff Volumes 5,430 6,006 6,162 7.202 6,205 Commercial Crude Oil Storage Capacity (mmbbls/mo) Crude Oil Lease Gathering Purchases (mb/d) 73 1,174 73 1,352 73 1,372 72 1,419 73 1,330 NGL (mb/d) NGL Fractionation NGL Pipeline Tariff Volumes NGL Sales 144 183 220 129 181 112 Please visit https://ir.paalp.com for a reconciliation of Non-GAAP financial measures reflected above to most directly comparable GAAP measures. 119 965 165 87 127 189 148 129 179 141 44#45■ Definitions Adjusted EBITDA: adjusted earnings before interest, taxes, depreciation and amortization (Consolidated) - Attributable to PAA where noted; Segment Adjusted EBITDA by definition is attributable to PAA ◉ Implied Distributable Cash Flow (DCF) Per Common Unit & Common Unit Equivalent (CUE): Adjusted EBITDA (Consolidated) less interest expense net of certain non-cash items, maintenance capital, current income tax expense, distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings, distributions to noncontrolling interests and preferred unit distributions paid adjusted for Series A preferred unit cash distributions paid, divided by the weighted average common units and common unit equivalents outstanding for the period ■ Cash Flow from Operations (CFFO): Net Cash Provided by Operating Activities (GAAP) ■ Free Cash Flow (FCF): net cash provided by operating activities (CFFO), less net cash used in investing activities, further impacted by distributions to, contributions from and proceeds from the sale of noncontrolling interests ■ Free Cash Flow after Distributions (FCFAD): FCF further reduced by cash distributions paid to preferred and common unitholders - 2022(G) FCFaD assumes current annualized distribution rate of $0.72 per common unit ■ CFFO, FCF & FCFAD estimates do not factor in material, unforeseen changes in ST working capital (i.e. hedged inventory storage activities/ volume / price / margin) • ■ Leverage Ratio: Total Debt plus 50% of PAA Preferred Securities less cash divided by LTM Adj. EBITDA attributable to PAA Pipeline Volumes: pipeline volumes associated with the Permian JV & Red River JV are presented on a consolidated (8/8ths) basis; all other volumes are presented net to our interest 45 2022(G): Furnished February 9, 2022.#46Investor Presentation March 2022 PLAINS