EX-99.1 2 augustinvestordeck.htm EX-99.1
Powering Arizona’s Future August Investor Meetings

2 This presentation contains forward-looking statements based on current expectations, including statements regarding our earnings guidance and financial outlook and goals. These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume,” “project,” "anticipate," "goal," "seek," "strategy," "likely," "should," "will," "could," and similar words. Because actual results may differ materially from expectations, we caution you not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS. These factors include, but are not limited to: our ability to achieve timely and adequate rate recovery of our costs through our regulated rates and adjustor recovery mechanisms, including returns on and of debt and equity capital investment; the impacts of federal, state, and local laws, judicial decisions, statutes, regulations, and FERC, NRC, EPA, ACC, and other agency requirements, including as they are changed by legislative and regulatory action as well as executive orders, such as those relating to tax, environment, energy, nuclear plants, and deregulation of the retail electric market; our operation of Palo Verde is subject to substantial regulatory oversight and potentially significant liabilities and capital expenditures; we are subject to numerous environmental laws and changes to existing laws, or new laws, may increase our costs and impact our business; the potential effects of climate change on our electric system, including as a result of weather extremes, such as prolonged drought and high temperature variations in the area where APS conducts its business, as well as the impacts of policy and regulatory changes introduced to address climate change; co-owners of our jointly owned generation and transmission facilities may have unaligned goals; the willingness or ability of counterparties, participants, and landowners to meet contractual or other obligations or extend the rights for continued generation and transmission operations; deregulation of the electric industry and other factors, such as large customers developing large, utility scale generation to serve their energy needs, may result in increased competition; variations in demand for electricity, including those due to weather, seasonality (including large increases in ambient temperatures), the general economy or social conditions, customer and sales growth (or decline), data center growth (or lack thereof), including to support the AI industry, the effects of energy conservation measures and DG, and technological advancements; wildfires, including those arising as a result of climate change, extreme weather events, or the expansion of the wildland urban interface; generation, transmission, and distribution facilities and system operating costs, conditions, performance, and outages; our ability and efforts to meet current and anticipated future needs for generation and transmission and distribution facilities in our region at reliable levels, including factors affecting our ability to acquire and develop new resources to serve this load as well as difficulties in accurately forecasting load growth, particularly from high load energy users; availability of fuel and water supplies as well as the volatility and costs of fuel and purchased power; the direct or indirect effect on our facilities or business from cybersecurity threats or intrusions, data security breaches, terrorist attack, physical attack, severe storms, or other catastrophic events, such as fires, explosions, pandemic health events, or similar occurrences; risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty; the development of new technologies and the impact they have on the retail and wholesale electricity market and the impacts of our adoption or failure to adopt such technologies; the availability and retention of qualified personnel and the need to negotiate collective bargaining agreements with union employees; the cost of debt, including increased cost as a result of rising interest rates, and equity capital and our ability to access capital markets when required as well as the impacts a credit rating downgrade would have on us; the investment performance of the assets of our nuclear decommissioning trust, captive insurance cell, coal mine reclamation escrow, pension, and other postretirement benefit plans, and the resulting impact on future funding requirements; Pinnacle West’s cash flow depends on the performance of APS and its ability to make dividends and distributions; potential shortfalls in insurance coverage; Pinnacle West’s ability to meet its debt service obligation could be adversely affected because its debt securities are structurally subordinated to the debt securities and obligations of its subsidiaries; the liquidity of wholesale power markets and the use of derivative contracts in our business; policy changes in Arizona or other states through ballot initiatives or referenda may increase our cost or operations or affect our business plans; general economic conditions, such as tariffs, inflation, and other supply chain constraints, as well as uncertainties associated with the current and future economic environment and conditions in Arizona; and disruptions in financial markets could adversely affect our cost of and access to credit and capital markets. These and other factors are discussed in the most recent Pinnacle West/APS Form 10-K and Form 10Q along with other public filings with the Securities and Exchange Commission, which you should review carefully before placing any reliance on our financial statements, disclosures or earnings outlook. Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law. In this presentation, references to net income and earnings per share (EPS) refer to amounts attributable to common shareholders. Forward Looking Statements

1. Company Profile 2. Growth Outlook & Energy Future 3. Financial Outlook 4. 2025 Rate Case Table of Contents

Company Profile

Key facts as of Dec. 31, 2025 Consolidated assets $30B Market cap $10.62B Generating capacity owned or leased (year end) 6.3GW Customers 1.4M Current % from clean energy 58% Retail sales mix (Residential/Non-Residential) 50%/50% Service Territory 5 Arizona’s largest electric company As of December 31, 2025.

Growth Outlook & Energy Future

2.4% 2.2% 2.1% 2.3% 2.5% 1.5%-2.5% 0% 1% 2% 3% 2021 2022 2023 2024 2025 2026E Residential Customer Growth1 APS Residential Growth Natn'l Avg.-Residential 7 • Phoenix housing is affordable compared to major cities in the region • Maricopa County ranked top county for economic development in 2025 by Site Selection Magazine • Ranked #1 in the nation for semiconductor manufacturing by Business Facilities Magazine – TSMC has committed $265B • Phoenix is ranked #1 out of 15 top growth markets for manufacturing by Newmark Group, a global real estate firm • Arizona State University ranked #1 in Innovation for 11th straight year by U.S. News and World Report • Phoenix ranks #1 in Western industrial markets by sales and industrial development (3rd nationally) by Commercial Café Report Arizona economy continues to be robust and attractive 1 National average from 2025 Itron Annual Energy Survey Report. Arizona continues to be an attractive service territory with strong customer growth - 10,000 20,000 30,000 40,000 2013 2017 2021 2025 New APS Customer Meter Sets

• Infrastructure ─ close proximity to major markets in the West with accessibility by rail or truck • Weather predictability ─ low propensity for natural disasters and greatest solar irradiance in America • Workforce availability ─ three major universities graduating a skilled labor force • Affordability ─ business friendly policies and regulation • Accounts for 4%-6% of the 5%-7% long-term weather normalized sales growth1 guidance • Amplifier effect for jobs and surrounding communities leading to residential growth • Proposed rate design modifications including direct assignment of generation costs to ensure growth pays for growth Large C&I customers as a growth driver Arizona is an attractive location for business growth Best-in-class service territory supports high tech growth and economic development 8 1 Forecasted guidance range through 2030.

Source: Arizona Commerce Authority 9 Arizona’s commercial and industrial growth is diverse

5.9% 5.5% 5.9% 5.5% 4.0%* 5.2% 5.4% 6.8% 7.4%* 9.6% 0% 1% 2% 3% 4% 5% 6% 7% 8% 9% 10% Q1 2024Q2 2024Q3 2024Q4 2024Q1 2025Q2 2025Q3 2025Q4 2025Q1 2026Q2 2026 Weather-Normalized Retail Sales Growth 10 Strong track record of consistently robust sales growth * Excludes $11M reduction to unbilled revenues in January 2025 • 10 consecutive quarters of growth within or exceeding the original long-term guidance range of 4%-6% • Strong C&I sales growth as extra high load factor customers continue to ramp • 2026 YTD C&I growth of 13.6% • 2026 sales growth guidance of 4%-6% • Long term sales growth increased to 5%-7% and extended through 2030 Continued trend of robust sales growth

• Balanced, constructive and more consistent outcomes, including improved ROE to APS • Approval of Formula Rate Policy Statement • Reaffirmation of Rate Case Settlement Policy • Continued support of adjustor mechanisms to improve cost recovery 11 Commitments by the Company • Sustain investment in customer experience improvements • Continue to find alignment with regulators and work with stakeholders on common issues • Advocate for reduced regulatory lag • Focus on customer affordability Improvements at the Arizona Corporation Commission We have an improved regulatory environment

12 Significant investment opportunity to serve increased demand Which is requiring us to invest There is significant additional load we need to be ready to serve New gas generation: • Announced new gas generation of up to 2 GWs • Announced incremental investment of up to $440M for conversion of retired Cholla power plant to 380MWs of natural gas generation • Anchor shipper on new gas pipeline, expected to be in service by late 2029 Palo Verde generating station: • Approximately $200 million investment made on buyout option for nearly 100 MW of nuclear capacity previously under sale-leaseback • Increased investment in Palo Verde capital program of approximately $500M over the next 10 years Strategic transmission: • Several major transmission investments to support new resources and overall system buildout • Additional investment in large transmission projects to enable access to out of state generation and additional markets 8.6GW 2025 System Peak 4.5GW Committed Load ~20GW Uncommitted Load Opportunity

13 Transmission expansion could drive significant capital investment $6 billion + of investmentCumulative Transmission CapEx 2026 2028 2035 Source: APS 2026-2035 Ten Year Transmission System Plan • Investments in Extra High Voltage (EHV) transmission to support reliability, resiliency, and integration of new resources – Over 600 miles of 345kV and above and over 300 miles of 230kV lines in planning period • Investments in large transmission projects to enable access to out of state generation and additional markets • Constructive and timely recovery through annual FERC Formula rate with wheeling revenue benefiting retail customers $0.6B $2.1B Major Transmission Projects in Development Project Miles/kV Est. in-service Helios to Milligan ~23 mi/230kV 2027 Pinnacle Peak to Ocotillo ~50 mi/230kV 2030 Cotton Transmission Corridor: Panda to Freedom Lines #2 & #1 Jojoba to Rudd ~80 mi/230kV ~29 mi/500kV 2030/2031 2031 Proposed Transmission for New Gas TBD 2030 Transmission Investment Strategy

Maintaining Affordability • Disciplined cost management: Process improvements and preventative maintenance to reduce operating costs • Customer growth: Long-term goal of declining O&M per MWh as service territory grows • Customer Programs: Innovative customer programs to help customers save energy and money • Balanced long-term capital plan: Infrastructure investments designed to maintain reliability yet minimize annual customer impact • Stakeholder engagement: Working with partners to ensure reliability, affordability, and recovery through appropriate rate design 14 3.62% 4.24% 2.67% 2018 2019 2020 2021 2022 2023 2024 2025 Average annual % change 2018-2025 CPI CPI (PHX) APS Rates APS rates have remained well below the rate of inflation We are focused on maintaining customer affordability

Future Financial Outlook

1. Long-term EPS growth of 5%-7% off original 2024 midpoint, supporting competitive total shareholder return 2. Optimized capital plan to reliably serve growing service territory, driving strong rate base growth 3. Managing a healthy capital structure with accretive equity to support investment 4. Declining O&M per MWh with focus on customer affordability 5. Competitive shareholder dividend 6. Solid balance sheet and credit ratings 16 Our investor goals going forward

Potential drivers for more consistent and timely cost recovery EPS Growth off original 2024 midpoint1 5%-7% CAGR • Reduction of regulatory lag including formula rates • Rate case cadence and potential settlement of future rate cases • Continued support of adjustor mechanisms • Continued economic development driving sales and customer growth • Continued cost management 17 Long-term outlook potential remains solid 1 Long-term EPS growth target based on the Company’s current weather normalized compound annual growth rate projections from 2024-2028.

$335 $460 $420 $380 $710 $765 $795 $750 $465 $550 $695 $860 $890 $825 $740 $710 2025A 2026E 2027E 2028E APS Total 2025-2028 $10.35B1 Generation Transmission Distribution Other $2.40B $2.60B $2.65B $2.70B Source: 2026-2028 as disclosed in the Second Quarter 2026 Form 10-Q 1. The estimated capital expenditures presented above do not include amounts related to Cholla gas conversion project, which is currently expected to cost up to approximately $440 million. In addition, project capital expenditures for entities other than APS are not included, as such amounts are expected to be immaterial. 18 Capital plan to support reliability and continued growth within our service territory

Current Approved Rate Base and Test Year Detail End-of-Year Rate Base and Growth Guidance1 ACC FERC Rate Effective Date 03/08/2024 06/01/2026 Test Year Ended 6/30/20221 12/31/2025 Equity Layer 51.93% 51.99% Allowed ROE 9.55% 10.75% Rate Base $10.36B2 $2.81B $12.23 $13.33 $15.7 $2.52 $2.82 $4.0 2024 2025 2026 2027 2028 ACC FERC 19 Rate base $ in billions, rounded Projected 1 Guidance excludes CWIP amounts of $1.6B in 2024 and $2.7B-$3.2B in 2028. 2 Derived from APS annual update of formula transmission service rates. 3 Represents unadjusted ACC jurisdictional rate base consistent with regulatory filings. 1 Adjusted to include post-test year plant in service through 06/30/2023. 2 Rate Base excludes $215M approved through Joint Resolution in Case No. E-01345A-19-0236. Increased rate base growth within our service territory

Approx. $3.8B Cash from Operations1 Total Capital Investment $2.6B-$2.9B APS Debt2 $300M-$350M PNW Debt2 1 Cash from operations is net of shareholder dividends. 2 APS and PNW debt issuance is net of maturities. 3 PNW equity is net of $485M already priced through January 2026. 2026 Financing Plan Execution 2026-2028 Financing Plan Approx. $8.0B $1.0B-$1.2B PNW Equity3 20 Optimized financing plan to support balanced capital structure 4 Includes maturities. DEBT Estimated Amount4 Maturities Completed APS $1.2B $250M $600M PNW $550M $350M $500M EQUITY Estimated Amount Priced Settled PNW $650M $650M $0 Funding Strategy • External equity to support balanced APS capital structure and expanded, accretive capital investment • Of the $1.0B-$1.2B total incremental need, $685M is priced under equity forwards through July 2026 • Utilized all remaining capacity in $900M ATM program • Established new $500M ATM program to continue progress toward future equity needs • Maintain strong balance sheet and current credit ratings

21 Operations & Maintenance Guidance • Core O&M remains flat with rapidly growing customer base • Lean culture and declining O&M per MWh goal • Reduction of year-over-year O&M including planned outages We are focused on cost control and customer affordability $955 $978 $970-$980 $141 $143 $80-$90 $70 $64 $45-$55 2024A 2025A 2026E O&M Guidance (millions) Planned Outages RES/DSM Core O&M Numbers may not foot due to rounding.

$2.62 $3.64 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Annualized Dividends per Share ~3.7% DPS CAGR Dividend Targets • Long-term dividend growth • Attractive dividend yield • Managing long-term dividend payout ratio into sustained 65-75% 22 1 Future dividends are subject to declaration at Board of Directors’ discretion. We have a proven dividend growth track record 1

Corporate Ratings1 Senior Unsecured Ratings Short-Term Ratings Outlook APS Moody’s Baa1 Baa1 P-2 Stable S&P BBB+ BBB+ A-2 Stable Fitch BBB+ A- F2 Stable Pinnacle West Moody’s Baa2 Baa2 P-2 Stable S&P BBB+ BBB A-2 Stable Fitch BBB BBB F3 Stable 23 1 Ratings as of July 31, 2026. Outlooks were reaffirmed by all agencies in April 2026. We are focused on maintaining healthy credit ratings to support affordable growth Credit Objectives • Maintain current investment-grade ratings at both PNW and APS • Target PNW FFO/Debt range of 14%-16% over the long-term o Midpoint represents >100bps cushion above Moody’s threshold • Target HoldCo debt to total Company debt % in the mid-teens • Maintain APS capital structure at >50% equity

$0 $200 $400 $600 $800 $1,000 $1,200 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 2048 2050 2052 2054 APS Fixed APS Floating PNW Fixed($millions) As of June 30, 2026 24 Debt maturity profile shows well managed and stable financing plan

25 • Service territory is one of the fastest growing in the nation with a diverse customer base • Improved regulatory environment with focus on reducing regulatory lag • Strong customer centric strategy focused on reliability and customer experience • Proven track record of efficient O&M practices and focus on customer affordability • Solid balance sheet and well managed financing plan • Attractive financial growth profile building off original 2024 midpoint We have a stable foundation with solid execution going forward

2025 Rate Case

27 2025 APS Rate Case – Updated Positions Overview of rate request ($ in millions) key components Rate Base Growth $206 12 months Post-test Year Plant $162 Fair Value Increment $89 WACC (7.63%) $129 Other (Base fuel, depreciation study, etc.) $107 Total Revenue Requirement $692 Adjustor Transfers $(83) Net Revenue Increase $609 Customer Net Revenue Impact on Day 1 14.69% Additional details • APS has requested rates become effective in the second half of 2026 • Docket number: E-01345A-25-0105 • Additional details, including filing, can be found at http://www.pinnaclewest.com/investors Numbers may not foot due to rounding.

28 2025 APS Rate Case – Updated Positions Overview of rate request ($ in millions) key components Test Year Ended December 31, 2024 Total Rate Base - Adjusted $15.8B ACC Rate Base - Adjusted $13.1B Embedded Long-Term Cost of Debt 4.26% Allowed Return on Equity 10.70% ROE Band for Formula Rate +/- 40bps Capital Structure Long-Term Debt 47.65% Common Equity 52.35% Base Fuel Rate (¢/kWh) 4.3881¢/kWh Post-Test Year Plant period 12 months Proposed rate design modifications • Direct assignment of generation costs to ensure extra high load factor customers pay for the resources they require • Align rates with costs to move classes closer to their cost of service which supports small and medium sized businesses • Ensure growth pays for growth and offers significant customer protections

29 2025 APS Rate Case – Updated Positions Formula Rate Adjustment Mechanism (FRAM) proposal • Historic test year, with authorized ROE and capital structure approved in most recent rate case • Inclusion of 6 months post-test year plant • Removal of System Reliability Benefit and the Tax Expense Adjustor Mechanism if FRAM is approved • No rate adjustment if actual ROE falls within +/- 40 bps of authorized ROE • Revenue surplus/deficiency allocated based on ACC jurisdictional cost of service results FRAM proposed schedule ACC filing of Annual Update May 1 Last day for data requests for informal information exchange and to submit informal challenge(s). June 30 Informal challenge(s) resolution deadline July 30 Adjusted annual update posted August 25 Last day for data requests and to submit formal challenge(s) September 4 Last day for Staff challenges and responses to formal challenges September 28 Staff Report (if no hearing) October 31 Commission Decision (if necessary) Before December 1 Rate Effective Date First billing cycle in December

30 2025 APS Rate Case - Testimony Summaries 1. Eliminate if FRAM approved 2. If the FRAM is adopted, the Commission should consider an ROE at the lower end of Staff's recommended range (9.55% - 9.80%) 3. Eliminate if FRAM approved and maintains 120-day schedule 4. Staff is currently evaluating the potential use of the TEAM mechanism to pass on the Nuclear PTC benefits to customers. APS Direct Testimony ACC Direct Testimony APS Rebuttal Testimony ACC Surrebuttal Testimony APS Rejoinder Testimony Return on Equity 10.70% 9.55% - 9.80%2 10.70% 9.55% - 9.80%2 10.70% Fair Value Increment 1.00% 0.20% 0.90% 0.20% 0.90% Capital Tracking Mechanism & Existing Adjustors Maintain SRB, TCA, PSA, DSMAC, REAC and TEAM Eliminate SRB, LFCR & TEAM Eliminate SRB, LFCR & TEAM if FRAM Approved3 Eliminate SRB, LFCR, and TEAM4 if FRAM Approved Eliminate SRB, LFCR & TEAM if FRAM Approved3 Eliminate LFCR1 Phase out DSMAC & REAC Optionally Eliminated Maintain TCA, PSA, DSMAC, and REAC Maintain TCA, PSA, DSMAC, and REAC Maintain TCA, PSA, DSMAC, and REAC Maintain TCA & PSA Formula Rate Adjustment Mechanism (FRAM) TY Eligible 12/31/2026 TY Eligible 12/31/2027 TY Eligible 12/31/2026 TY Eligible 12/31/2026 TY Eligible 12/31/2026 10.70% ROE 9.55% ROE 10.70% ROE 9.55% ROE 10.70% ROE +/- 20pbs Deadband +/- 50pbs Deadband +/- 40pbs Deadband +/- 50pbs Deadband +/- 40pbs Deadband Projected Plant 12 Months Post Test-Year Plant 6 Months Post Test-Year Plant 6 Months Post Test-Year Plant 6 Months Post Test-Year Plant 6 Months Additional items 100% D&O 50% D&O 50% D&O 50% D&O 50% D&O 100% Incentive Comp 50% Incentive Comp 50% Incentive Comp 50% Incentive Comp 50% Incentive Comp 100% BOD Expense 50% BOD Expense 50% BOD Expense 50% BOD Expense 50% BOD Expense Total Revenue Requirement Increase $662.44M $525.19M $694.23M $506.46M $691.61M Bill Impact 13.99% 10.68% 14.75% 10.22% 14.69%

Appendix

Case/Docket # Q1 Q2 Q3 Q4 2025 Rate Case E-01345A-25-0105: Staff and Intervenor Direct Testimony filed March 2 and March 18 • APS Rebuttal Testimony filed April 3 • Staff and Intervenor Surrebuttal Testimony filed May 1 • APS Rejoinder Testimony filed May 11 • Rate Case hearing began May 18 • Initial briefs due August 27 • Reply briefs due September 11 Final Decision estimated December 2026 Power Supply Adjustor (PSA) E-01345A-22-0144: 2026 PSA rate reset effective Feb. 4 PSA reset to be filed Nov. 30 Transmission Cost Adjustor E-01345A-22-0144: Filed May 15 for a June 1 effective date Lost Fixed Cost Recovery E-01345A-26-0337: 2026 LFCR filed July 31 2026 LFCR effective Nov. 1 (if approved) Resource Comparison Proxy E-01345A-26-0171: Updated RCP calculation filed May 1 RCP update effective Sep. 1 2027-2031 RES Implementation Plan E-01345A-26-0264: 2026 RES Plan approved Feb. 4 2027-2031 RES Plan filed July 1 2026 DSM/TE Implementation Plan E-01345A-25-0106: 2026 DSM/TE Plan filed April 7 ACC Inquiry into Nuclear Issues E-00000A-25-0026: ACC Nuclear Workshop #2 held Feb. 24 ACC Nuclear Workshop #2B held June 25 Final Workshop to be held November 19 ACC Inquiry into Data Center Rate Classifications E-00000A-25-0069 ACC Large Load Users Development Workshop held April 16 2026 Integrated Resource Plan: E-99999A-25-0058 2026 IRP to be filed October 30 14th Biennial Transmission Assessment: E-99999A-25-0006 APS Ten-Year Transmission System Plan filed Jan. 30 ACC 14th BTA 1st Workshop held July 16 32 2026 Key Regulatory Dates Dates are tentative and subject to change.

$18 $16 $19 $19 $17 $9 $15 $18 $24 $14 $6 $7 $0 $5 $10 $15 $20 $25 $30 $35 $40 $45 $50 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Renewable Energy Demand Side Management 2025 $143 Million 2026 $40 Million 1 Renewable Energy and Demand Side Management expenses are substantially offset by adjustment mechanisms. Numbers may not foot due to rounding. ($ in millions pretax) 33 Renewable Energy & Demand Side Management expenses1

$17 $28 Q1 Q2 Q3 Q4 Variances vs. Normal All periods recalculated to current 10-year rolling average (2015 – 2024). Numbers may not foot due to rounding. ($ in millions pretax) 2026 Total Weather Impact: $45 Million 34 2026 gross margin effects of weather

35 Wildfire Mitigation Vegetation Management Asset Inspection Monitoring and Awareness Operational Mitigations • Comprehensive right- of-way clearance on maintained cycles • Defensible space around poles (DSAP) • Hazard tree program • Enhanced line patrols • Technology deployments • Drone use • Infra-red scans • Non-reclosing strategy • Public outreach program • Red Flag Alert protocols • Enhanced Powerline Safety Settings (EPSS) • Public Safety Power Shutoff (PSPS) • Dedicated team of meteorologists • Advanced fire modeling software • Cameras and weather stations • Federal & state agency partnerships Grid Hardening Investments • Ongoing distribution system upgrades • Mesh pole wrapping • Expulsion limiting fuses • Steel poles (if truck accessible) Internal: 21-person fire mitigation department engages across entire APS organization to plan and implement initiatives External: Member of 10 fire mitigation industry associations Comprehensive Wildfire Mitigation Plan (CWMP) approved by AZ DFFM as required by AZ Revised Statutes Our current practices are comprehensive and multi-faceted:

Generation Planned Outages 36 2026 Planned Outage Schedule Q2 Plant Unit Duration in Days Palo Verde1 2 45 Q4 Plant Unit Estimated Duration in Days Palo Verde 1 46 1 Outage began at end of Q1