FIRST QUARTER 2014 RESULTS May 2, 2014

FORWARD LOOKING STATEMENTS AND NON-GAAP FINANCIAL MEASURES 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” 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 manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels; variations in demand for electricity, including those due to weather, the general economy, customer and sales growth (or decline), and the effects of energy conservation measures and distributed generation; power plant and transmission system performance and outages; competition in retail and wholesale power markets; regulatory and judicial decisions, developments and proceedings; new legislation or regulation, including those relating to environmental requirements, nuclear plant operations and potential deregulation of retail electric markets; fuel and water supply availability; our ability to achieve timely and adequate rate recovery of our costs, including returns on debt and equity capital; our ability to meet renewable energy and energy efficiency mandates and recover related costs; risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty; current and future economic conditions in Arizona, particularly in real estate markets; the cost of debt and equity capital and the ability to access capital markets when required; environmental and other concerns surrounding coal-fired generation; volatile fuel and purchased power costs; the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements; the liquidity of wholesale power markets and the use of derivative contracts in our business; potential shortfalls in insurance coverage; new accounting requirements or new interpretations of existing requirements; generation, transmission and distribution facility and system conditions and operating costs; the ability to meet the anticipated future need for additional baseload generation and associated transmission facilities in our region; the willingness or ability of our counterparties, power plant participants and power plant land owners to meet contractual or other obligations or extend the rights for continued power plant operations; technological developments affecting the electric industry; and restrictions on dividends or other provisions in our credit agreements and ACC orders. These and other factors are discussed in Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2013, 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. We present “gross margin” per diluted share of common stock. Gross margin refers to operating revenues less fuel and purchased power expenses. Gross margin is a “non-GAAP financial measure,” as defined in accordance with SEC rules. The appendix contains a reconciliation of this non-GAAP financial measure to the referenced revenue and expense line items on our Consolidated Statements of Income, which are the most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles in the United States of America (GAAP). We view gross margin as an important performance measure of the core profitability of our operations. We refer to “on-going earnings” in this presentation, which is also a non-GAAP financial measure. We believe on-going earnings provide investors with a useful indicator of our results that is comparable among periods because it excludes the effects of unusual items that may occur on an irregular basis. Investors should note that these non-GAAP financial measures may involve judgments by management, including whether an item is classified as an unusual item. These measures are key components of our internal financial reporting and are used by our management in analyzing the operations of our business. We believe that investors benefit from having access to the same financial measures that management uses.

Resource Planning Operational Excellence Regulatory Update CEO AGENDA

1st Quarter 2014 Results Arizona Economic Outlook Financial Outlook CFO AGENDA

CONSOLIDATED EPS COMPARISON 2014 VS. 2013 1st Quarter GAAP Net Income $0.14 $0.22 1st Quarter On-Going Earnings Excluding Weather

Higher D&A(2) $(0.03) Lower Gross Margin(4) $(0.09) = Net Decrease $(0.08) ON-GOING EPS VARIANCES 1ST QUARTER 2014 VS. 1ST QUARTER 2013 Excludes $5.6M of O&M associated with Four Corners transaction deferred for regulatory recovery in D&A. Excludes deferrals of $7.3M in D&A associated with Four Corners transaction. Excludes $1.7M of other taxes associated with Four Corners transaction deferred for regulatory recovery in D&A. Excludes costs, and offsetting operating revenues, associated with renewable energy (excluding AZ Sun), demand side management and similar regulatory programs. See non-GAAP reconciliation for gross margin in appendix. Lower O&M(1)(4) $0.09 Higher Other Taxes(3) $(0.02) Other, Net $(0.03)

GROSS MARGIN EPS DRIVERS 1ST QUARTER 2014 VS. 1ST QUARTER 2013 Lost Fixed Cost Recovery Mechanism $0.02 Other, Net (including AZ Sun) $0.04 Higher Retail kWh Sales $0.01 Retail Transmission Revenue $(0.03) = Net Decrease $(0.09) Weather $(0.13) See non-GAAP reconciliation for gross margin in appendix.

ARIZONA ECONOMIC INDICATORS Nonresidential Building Vacancy – Metro Phoenix New Home Sales & Single Family Permits Home Prices – Metro Phoenix Value Relative to Jan ‘05 Vacancy Rate Office Retail Job Growth (Total Nonfarm) - Arizona YoY Change Forecast Q1 Q1 Jan

CUSTOMER GROWTH Annual Growth Customer growth drives 85% of retail sales (excluding impacts of customer conservation, energy efficiency and distributed renewable generation initiatives) Retail customer growth to average about 2.5% annually 2014-2016

ECONOMIC OUTLOOK “Arizona, Texas Head List of Best States for Expected Job Growth. Forbes/Moody’s Analytics, September 25, 2013. “America’s 20 Fastest Growing-Cities.” Forbes, February 14, 2014. Arizona is the #1 state for projected job growth by Forbes (1) #1 Phoenix ranked 3rd on Forbes’ 2014 list of America’s Fastest-Growing Cities (2) 3rd

RETAIL SALES GROWTH (WEATHER-NORMALIZED) YoY Retail Sales Before Customer Programs Energy Efficiency & Customer Conservation Distributed Energy Weather-normalized retail sales growth about 1% for 2014-2016 after impacts of energy efficiency, customer conservation and distributed renewable generation initiatives (excluding Lost Fixed Cost Recovery) Distributed Energy (DE) Impact DE makes up 0.5% (or less) of the negative impact to retail sales growth as shown in the chart; equates to approximately 60 GWh out of our total retail sales of over 28,000 GWh Average residential rooftop solar system produces 10,000 – 12,000 KWh per year (average metro-Phoenix customer’s usage is nearly 15,000 KWh)

FINANCING ($Millions) Debt Maturity Schedule 2014 Major Financing Activities $250 million 30-year 4.70% APS senior unsecured notes issued in January 2014 Currently expect about $550 million additional long-term debt issuance in 2014, including issuance to refinance $300 million of maturing debt In addition, there will be several tax-exempt series subject to remarketing 2015 Major Financing Activities Currently expect about $300 million of new long-term debt in 2015, in addition to refinancing maturing debt

2014 ON-GOING EPS GUIDANCE Key Factors & Assumptions as of May 2, 2014 2014 Electricity gross margin* (operating revenues, net of fuel and purchased power expenses) $2.22 – $2.27 billion Retail customer growth about 2% Weather-normalized retail electricity sales volume about +0.5% to prior year taking into account effects of customer conservation, energy efficiency and distributed renewable generation initiatives Actual weather through March; normal weather patterns remainder of the year Operating and maintenance* $790 – $810 million Other operating expenses (depreciation and amortization, Four Corners deferrals, and taxes other than income taxes) $595 - $615 million Interest expense, net of allowance for borrowed and equity funds used during construction $170 - $180 million Net income attributable to non-controlling interests ~$35 million Effective tax rate 34% Average diluted common shares outstanding ~111.0 million On-Going EPS Guidance $3.60 - $3.75 * Excludes O&M of $94 million, and offsetting revenues, associated with renewable energy and demand side management programs.

APPENDIX

RESOURCE PLANNING* Existing Owned Resources Existing Contracts Resource Planning Requirement Load Requirement Including Reserves MW Coal Nuclear RE + DE EE Composition of Energy Mix by Resource Note: RE = Renewable Energy; DE = Distributed Energy; EE = Energy Efficiency *Data shown is based on 2014 Integrated Resource Plan filed April 1, 2014.

Utility-scale photovoltaic solar plants to be owned by APS Constructive rate recovery through RES until included in base rates 118 MW in commercial operation to date; 150 MW by end of 2014 Commitments to date: 170 MW; $695 million estimated capital investment AZ SUN PROGRAM Owning solar resources makes sense for our customers and the environment and provides earnings growth potential Name Location Capacity Developer Actual or Target COD* Paloma Gila Bend, AZ 17 MW First Solar September 2011 Cotton Center Gila Bend, AZ 17 MW Solon October 2011 Hyder Phase 1 Hyder, AZ 11 MW SunEdison October 2011 Hyder Phase 2 Hyder, AZ 5 MW SunEdison February 2012 Chino Valley Chino Valley, AZ 19 MW SunEdison November 2012 Yuma Foothills Phase 1 Yuma, AZ 17 MW AMEC March 2013 Yuma Foothills Phase 2 Yuma, AZ 18 MW AMEC December 2013 Hyder II Hyder, AZ 14 MW McCarthy December 2013 Gila Bend Gila Bend, AZ 32 MW Black & Veatch 2Q 2014 City of Phoenix Buckeye, AZ 10 MW TBD 2015 Luke Air Force Base Glendale, AZ 10 MW TBD 2015 Total 170 MW As of March 31, 2014 * In-Service or Commercial Operation Date

2014 KEY DATES Docket # Q1 Q2 Q3 Q4 Key Regulatory Filings Lost Fixed Cost Recovery 11-0224 Jan 15 Transmission Cost Adjustor May 15 Renewable Energy Surcharge Jul 1 10-Year Transmission Plan (Annual) 13-0002 Jan 31 2014 Integrated Resource Plan (Biennial) 13-0070 Apr 1 Net Metering (Decision No. 74202) 13-0248 Quarterly Installation Filings 13-0248 Apr 15 Jul 15 Oct 15 Value and Cost of Distributed Generation 14-0023 May 7 Jun 20 TBD Innovations and Technology Development Docket Workshops – Substantive (a), Response (b) 13-0375 Mar 20 (1a) Apr 25 (1b) May 28 (2a) Jun TBD (2b) Jul 28 (3a) Aug 18 (3b) Four Corners Rate Rider 11-0224 Testimony Jun – Jul; Hearings being Aug ACC Open Meeting TBD Energy Efficiency workshops – (a) Cost effectiveness, (b) Cost recovery and (c) EE standards/rulemaking 13-0214 Mar 18 (a) Mar 31 (b) Apr 17 (c) ACC Open Meetings - ACC Open Meetings Held Monthly Elections - May 28: Nominations Aug 26: Primary Nov 4: General Arizona State Legislature - In Session Jan 13 – Apr 24 (Adjourned) Annual Shareholder Meeting - May 21

FERC Formula Rates adopted in 2008 Adjusted annually with 10.75% allowed ROE Based on FERC Form 1 and projected closings Update filed each April Annual rate true-up compares projected revenue requirement to actual, with variance incorporated into next annual update Retail portion flows through ACC Transmission Cost Adjustor (TCA) REGULATORY MECHANISMS (TCA) We have achieved constructive transmission rate treatment with annual adjustments 2013 2012 Annual Rate Increase Rate Effective Date Annual Rate Increase Rate Effective Date Retail Portion (TCA) $21 M 6/1/2013 $18 M 8/1/2012 Wholesale Portion $5 M 6/1/2013 $(2) M 6/1/2012 Total Increase (Decrease) $26 M $16 M Equity Ratio 57% 55% Rate Base (Year-End) $1.2 B $1.2 B Test Year 2012 2011

6/1 Rate Goes Into Effect REGULATORY MECHANISMS (TCA) We have achieved constructive transmission rate treatment with annual adjustments 2013 2014 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC 6/1 Rate Goes Into Effect ~5/15 File/Post FERC Rate ~4/15 File FERC Form 1 ~5/15 File/Post FERC Rate ~4/15 File FERC Form 1 New accounting treatment began July 1, 2012, effective with 2012 Settlement Agreement Quarterly true-ups can occur throughout the year (2013 included adjustments of 2012 revenue) Although transmission rate base is growing, 2014 transmission revenue in line with 2013 in part because of the 2012 true-ups in 2013, and higher CWIP in 2014 due to large projects (i.e. HANG2) that come online beginning in 2015 2013 Revenue 2013 Rates (Including True-Up) 2014 Rates (Including True-Up) 2014 Revenue Quarterly True-Ups Quarterly True-Ups

On December 30, 2013, APS and Southern California Edison (“SCE”) completed previously announced transaction whereby APS agreed to purchase SCE’s 48% interest in Units 4 and 5 of Four Corners Final purchase price: $182 million Estimated environmental compliance: $350 million, primarily in 2016-2017 APS will continue to operate Four Corners and now has total interest of about 970 MW APS filed Four Corners-specific revenue requirement on docket 11-0224 APS notified EPA that the Four Corners participants selected the BART alternative requiring APS to retire Units 1-3 by January 1, 2014 and install and operate SCR control technology on Units 4-5 by July 31, 2018 Construction expected to begin by early 2016 after approval of final EPA permit Next Steps: ACC decision on revenue requirement (rates in effect immediately following decision) EPA permitting process FOUR CORNERS POWER PLANT ALJ Procedural Schedule Staff/Intervenor Direct Testimony June 19, 2014 APS Rebuttal Testimony July 3, 2014 Staff/Intervenor Surrebuttal Testimony July 21, 2014 APS Rejoinder Testimony July 28, 2014 Prehearing Conference July 30, 2014 Hearing Begins August 4, 2014

OCOTILLO POWER PLANT (TEMPE, AZ) Ocotillo modernization project will maintain valley grid reliability and increase APS’s generating capacity by 290 MW Maintains system reliability through retirement of aging steam units Replacement units meet need for increased portfolio responsiveness Aids integration of renewables Estimated project cost of $600M - $700M Expected timeline: Early 2014: Stakeholder engagement and initiate permitting activities Q3 2014: ACC Certificate of Environmental Compatibility application filing Late 2014: ACC Siting Committee hearings 2016: Expect to begin construction Q2 2018: Expected project completion Site Capacity (MW) Current Future (2) Westinghouse 110 MW steam units - constructed 1960 220 Retire (2) Westinghouse 55 MW combustion turbines - constructed 1972/73 110 110 Install (5) GE 102 MW combustion turbines 0 510 Total 330 620 Net site capacity increased by 290 MW

CAPITAL EXPENDITURES 80% of capital expenditures are recovered through rate adjustors (40%) and depreciation cash flow (40%) ($ Millions) $973 $1,026 2014 – 2016 as disclosed in First Quarter 2014 Form 10-Q Distribution Transmission Renewable Generation Environmental Traditional Generation Projected $1,263

OPERATIONS & MAINTENANCE Our goal is to keep consolidated O&M growth at or below retail sales growth levels Note: Pinnacle West O&M for 2009-2014E: $10M, $9M, $8M, $11M, $27M and $10M, respectively. * 2013 includes $9M related to the closure of Four Corners Units 1, 2 and 3 deferred for regulatory recovery in depreciation. **Renewable energy and demand side management expenses are offset by revenue adjustors. $790 - $810 ($ Millions) $788*

2014 – 2016 FINANCIAL OUTLOOK Key Factors & Assumptions as of May 2, 2014 Assumption Impact Retail customer growth Expected to average about 2.5% annually (2014-2016) Modestly improving Arizona and U.S. economic conditions Weather-normalized retail electricity sales volume growth About 1% after customer conservation and energy efficiency and distributed renewable generation initiatives Weather Actual weather through March 2014; normal weather patterns thereafter Assumption Impact AZ Sun Program Additions to flow through RES until next base rate case First 50 MW of AZ Sun is recovered through base rates Lost Fixed Cost Recovery (LFCR) Offsets 30-40% of revenues lost due to ACC-mandated energy efficiency and distributed renewable generation initiatives Environmental Improvement Surcharge (EIS) Assumed to recover up to $5 million annually of carrying costs for government-mandated environmental capital expenditures Power Supply Adjustor (PSA) 100% recovery as of July 1, 2012 Transmission Cost Adjustor (TCA) TCA is filed each May and automatically goes into rates effective June 1 Beginning July 1, 2012 following conclusion of the regulatory settlement, transmission revenue is accrued each month as it is earned. Four Corners Acquisition Pending final ACC approval Potential Property Tax Deferrals (2012 retail rate settlement) – Assume 60% of property tax increases relate to tax rates, therefore, will be eligible for deferrals (Deferral rates: 50% in 2013; 75% in 2014 and thereafter) Gross Margin – Customer Growth and Weather Gross Margin – Related to 2012 Retail Rate Settlement

PNW Consolidated At least 9.5% Annually CONSOLIDATED FINANCIAL OUTLOOK Earned ROE * Continuing operations Projected Future dividends subject to declaration at Board of Director’s discretion Annual Dividend Growth Approx. 4% Goal

GROSS MARGIN EFFECTS OF WEATHER VARIANCES VS. NORMAL Pretax Millions All periods recalculated to confirm to current 10-year rolling average (2003 – 2012). $9 Million 2014 $(13) Million

RENEWABLE ENERGY AND DEMAND SIDE MANAGEMENT EXPENSES* * O&M expenses related to renewable energy, demand side management and similar regulatory programs are offset by comparable revenue amounts. Pretax Millions $124 Million 2014 $26 Million $137 Million

NON-GAAP MEASURE RECONCILIATION GROSS MARGIN $ millions pretax, except per share amounts 2014 2013 Operating revenues* 686 $ 687 $ Fuel and purchased power expenses* (250) (231) Gross margin 436 456 (0.11) $ Adjustments: Renewable energy (excluding AZ Sun), demand side management and similar regulatory programs (21) (24) 0.02 Gross margin - adjusted 415 $ 432 $ (0.09) $ * Line items from Consolidated Statements of Income Three Months Ended March 31, EPS Impact