THIRD QUARTER 2014 RESULTS October 31, 2014

2 Third Quarter 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 and in Part II, Item 1A of the Pinnacle West/APS Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, 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 also provide a reconciliation to show various deferral impacts of our Four Corners transaction and impacts to our noncontrolling interests for the Palo Verde lease extensions. We believe on-going earnings and the information provided in the reconciliation provide investors with useful indicators of our results that are comparable among periods because they exclude 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.

3 Third Quarter 2014 • Regulatory Update • Resource Planning • Operational Excellence CEO AGENDA

4 Third Quarter 2014 • 3rd Quarter 2014 Results • Arizona Economic Outlook • Earnings Guidance and Financial Outlook CFO AGENDA

5 Third Quarter 2014 CONSOLIDATED EPS COMPARISON 2014 VS. 2013 $2.20 $2.04 2014 2013 3rd Quarter GAAP Net Income $2.20 $2.04 3rd Quarter On-Going Earnings $3.53 $3.44 2014 2013 YTD GAAP Net Income $3.53 $3.44 YTD On-Going Earnings

6 Third Quarter 2014 Interest, Net of AFUDC $0.04 Other, Net $0.03 D&A $0.02 Gross Margin(1) $0.01 = Net Increase $0.16 ON-GOING EPS VARIANCES 3RD QUARTER 2014 VS. 3RD QUARTER 2013 (1) Excludes costs, and offsetting operating revenues, associated with renewable energy (excluding AZ Sun), demand side management and similar regulatory programs. Note: Drivers adjusted for the deferral impacts of the Four Corners transaction and impacts to our noncontrolling interests for the Palo Verde lease extensions. See non-GAAP reconciliation in appendix. O&M(1) $0.02 Other Taxes $0.02 Effective Tax Rate $0.02

7 Third Quarter 2014 GROSS MARGIN EPS DRIVERS 3RD QUARTER 2014 VS. 3RD QUARTER 2013 Lost Fixed Cost Recovery Mechanism $0.02 Retail Transmission Revenue $0.01 = Net Increase $0.01 Weather $(0.03) See non-GAAP reconciliation for gross margin in appendix. AZ Sun $0.03 Other, Net $(0.02)

8 Third Quarter 2014 0% 5% 10% 15% 20% 25% '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 Industrial ARIZONA ECONOMIC INDICATORS Nonresidential Building Vacancy – Metro Phoenix Single Family & Multifamily Housing Permits Maricopa County Home Prices – Metro Phoenix Value Relative to Jan ‘05 50 75 100 125 150 175 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 Vacancy Rate Office Retail Job Growth (Total Nonfarm) - Arizona (10.0)% (5.0)% 0.0% 5.0% 10.0% '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 YoY Change E Q3Aug 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 '07 '08 '09 '10 '11 '12 '13 '14 Single Family Multifamily Sep

9 Third Quarter 2014 ON-GOING EPS GUIDANCE AS OF OCTOBER 31, 2014 2014 Guidance 2015 Guidance Note: Earned Return on Equity goal based on average Total Shareholders’ Equity for PNW Consolidated. See key factor and assumptions in appendix. Affirming 2014 Guidance range…introducing 2015 Guidance $3.60 - $3.75 $3.75 - $3.95 Outlook through 2016 • Goal of earning more than 9.5% Return on Equity • Adjustment mechanisms (Lost Fixed Cost Recovery, Transmission Cost Adjustor, AZ Sun, etc.) providing increasing contribution • Modest load growth • Continued focus on sustainable cost management

APPENDIX

11 Third Quarter 2014 2014 KEY DATES Docket # Q1 Q2 Q3 Q4 Key Regulatory Filings Lost Fixed Cost Recovery 11-0224 Jan 15 Transmission Cost Adjustor 11-0224 May 15 Renewable Energy Surcharge 14-0250 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 7Jun 20 Innovations and Technology Development Docket Workshops – Substantive (a), Response (b) 13-0375 Mar 20 (1a) Apr 25 (1b) May 28 (2a) Jun 25 (2b) Jul 28 (3a) Aug 18 (3b) Four Corners Rate Rider 11-0224 Testimony: Jun – Jul; Hearings: Aug ACC Open Meeting 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 (Held Monthly) - (a) ACC voted to remove requirement that APS file its next rate case in June 2015 - Aug 12 (a) Optional Rate Design Process 14-0329 TBD Elections - May 28: Nominations Aug 26: Primary Nov 4: General Arizona State Legislature - In Session Jan 13 – Apr 24 (Adjourned)

12 Third Quarter 2014 KEY RATE DESIGN PRINCIPLES Smarter rates for smarter grid Arizona Public Service, Tucson Electric Power, Residential Utility Consumer Office and Arizona solar developers filed a joint letter with the ACC agreeing on the following rate design principles: Customer-focused • Meaningful options • Meet lifestyle needs • Allow customers to choose among technologies Forward-thinking • Maintain reliable service • Enable technology innovation • Put all technologies on a level playing field Affordable & Fair • For all of our 1.2 million customers • Transparent • Accurately reflect services and products customers use Fixed Costs 69% Variable Costs 31% Costs – APS Residential Classes (2010) Fixed Charge Revenue 10% Variable Charge Revenue 90% Revenue – APS Residential Classes (2010) Rate design changes needed to align fixed costs and revenue

13 Third Quarter 2014 2014 ON-GOING EPS GUIDANCE Key Factors & Assumptions as of October 31, 2014 2014 Electricity gross margin* (operating revenues, net of fuel and purchased power expenses) $2.20 – $2.22 billion • Retail customer growth about 1.5% • Weather-normalized retail electricity sales volume about flat to prior year taking into account effects of customer conservation, energy efficiency and distributed renewable generation initiatives • Actual weather through September - YTD impact $(0.06) per share; normal weather patterns remainder of the year Operating and maintenance* $790 – $800 million Other operating expenses (depreciation and amortization, Four Corners deferrals, and taxes other than income taxes) $595 - $605 million Interest expense, net of allowance for borrowed and equity funds used during construction (Total AFUDC $40 million) ~$160 million Net income attributable to noncontrolling interests ~$25 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 $103 million, and offsetting revenues, associated with renewable energy and demand side management programs.

14 Third Quarter 2014 2015 ON-GOING EPS GUIDANCE Key Factors & Assumptions as of October 31, 2014 2015 Electricity gross margin* (operating revenues, net of fuel and purchased power expenses) $2.30 – $2.35 billion • Retail customer growth about 1.5-2.5% • Weather-normalized retail electricity sales volume about 0-1.0% to prior year taking into account effects of customer conservation, energy efficiency and distributed renewable generation initiatives • Normal weather patterns Operating and maintenance* $795 - $815 million Other operating expenses (depreciation and amortization, and taxes other than income taxes) $650 - $670 million Interest expense, net of allowance for borrowed and equity funds used during construction (Total AFUDC $40 million) $175 - $185 million Net income attributable to noncontrolling interests ~$20 million Effective tax rate 35% Average diluted common shares outstanding ~111.0 million On-Going EPS Guidance $3.75 - $3.95 * Excludes O&M of $106 million, and offsetting revenues, associated with renewable energy and demand side management programs.

15 Third Quarter 2014 2015 – 2017 FINANCIAL OUTLOOK Key Factors & Assumptions as of October 31, 2014 Assumption Impact Retail customer growth • Expected to average about 2-3% annually (2015-2017) • Modestly improving Arizona and U.S. economic conditions Weather-normalized retail electricity sales volume growth • About 0.5-1.5% after customer conservation and energy efficiency and distributed renewable generation initiatives Weather • Normal weather patterns 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

16 Third Quarter 2014 OPERATIONS & MAINTENANCE Our goal is to keep consolidated O&M growth at or below retail sales growth levels $749 $754 $761 $788 $121 $150 $124 $137 $103 $106 2010 2011 2012 2013 2014E 2015E Consolidated RES/DSM* *Renewable energy and demand side management expenses are offset by revenue adjustors. $795 - $815 ($ Millions) $790 - $800

17 Third Quarter 2014 $2.10 $2.18 $2.27 $2.38 2011 2012 2013 2014 2015 2016 Dividend Growth Goal Indicated Annual Dividend Rate at Year-End DIVIDEND GROWTH Pinnacle West’s annual dividend is $2.38 per share; targeting ~5% annual dividend growth Projected Future dividends subject to declaration at Board of Directors’ discretion.

18 Third Quarter 2014 2015 2016 2017 RETAIL SALES GROWTH (WEATHER-NORMALIZED) YoY Retail Sales Before Customer Programs Energy Efficiency & Customer Conservation Distributed Generation • Weather-normalized retail sales growth on average about 0.5-1.5% for 2015-2017 after impacts of energy efficiency, customer conservation and distributed renewable generation initiatives (excluding Lost Fixed Cost Recovery) Distributed Generation (DG) Impact • DG 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)

19 Third Quarter 2014 $390 $292 $365 $526 $20 $25 $37 $159 $166 $73 $60 $1 $132 $170 $216 $144 $234 $223 $328 $335 $44 $81 $85 $83 2013 2014 2015 2016 CAPITAL EXPENDITURES 80% of capital expenditures are recovered through rate adjustors (40%) and depreciation cash flow (40%) ($ Millions) $986 $864 $1,091 2014 – 2016 as disclosed in Third Quarter 2014 Form 10-Q Other Distribution Transmission Renewable Generation Environmental Traditional Generation Projected $1,248

20 Third Quarter 2014 FINANCING $300 $300 $250 $500 $125 $- $100 $200 $300 $400 $500 $600 2014 2015 2016 2017 2018 2019 APS PNW ($Millions) Debt Maturity Schedule 2014 Major Financing Activities • $250 million 30-year 4.70% APS senior unsecured notes issued in January 2014 with proceeds used primarily to fund acquisition of Four Corners • $250 million 10-year 3.35% APS senior unsecured notes issued June 2014 with proceeds used with other funds to pay the $300 million maturity on June 30, 2014 • Currently expect up to $350 million additional long-term debt issuance in Q4 2014 • In addition, there will be tax-exempt series remarketed or refinanced 2015 Major Financing Activities • Currently expect about $400 million of new long-term debt in 2015, in addition to refinancing maturing debt

21 Third Quarter 2014 • Lost Fixed Cost Recovery (LFCR) was implemented as part of the July 2012 settlement – Estimated to offset 30-40% of revenues lost due to ACC- mandated energy efficiency (EE) and distributed renewable generation (DG) initiatives • Annual filing by January 15th each year with new rates in effect March 1st, based on the EE and DG savings from the preceding calendar year – Subject to annual cap of 1% of company’s total revenues • Revenue accrued each month as it is earned, creating a regulatory asset since the rates lag REGULATORY MECHANISMS (LFCR) Lost Fixed Cost Recovery 2013 ACC Order 2014 ACC Order Rates Effective March 1, 2013 March 1, 2014 LFCR Rate 0.2% 0.95% Residential rate per lost kWh $0.031 $0.031 Non-residential rate per lost kWh $0.023 $0.023 LFCR Adjustment (Annualized) $5.1 Million $25.4 Million LFCR Revenue (Accrued in prior year) $7.3 Million (1) $22.6 Million 2012 2013 2014 2015 2015 Revenue 2014 Revenue 2013 Revenue 2012 Revenue Rate Recovery (1) Represents six months in 2012.

22 Third Quarter 2014 • 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 As Filed 2014 2013 2012 Annual Rate Increase Rate Effective Date Annual Rate Increase Rate Effective Date Annual Rate Increase Rate Effective Date Retail Portion (TCA) $5 M 6/1/2014 $21 M 6/1/2013 $18 M 8/1/2012 Wholesale Portion $1 M 6/1/2014 $5 M 6/1/2013 $(2) M 6/1/2012 Total Increase (Decrease) $6 M $26 M $16 M Equity Ratio 58% 57% 55% Rate Base (Year-End) $1.3 B $1.2 B $1.2 B Test Year 2013 2012 2011

23 Third Quarter 2014 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 is in line with 2013 because of the 2012 true-ups in 2013, and the large capex projects (e.g. HANG2) that are in progress, but do not come online until 2015 or later 2013 Revenue 2013 Rates (Including True-Up) 2014 Rates (Including True-Up) 2014 Revenue Quarterly True-Ups Quarterly True-Ups

24 Third Quarter 2014 10 16 (7) (10) (13) 6 (4) $(20) $(10) $0 $10 $20 Q1 Q2 Q3 Q4 Q1 Q2 Q3 GROSS MARGIN EFFECTS OF WEATHER VARIANCES VS. NORMAL Pretax Millions 2013 $9 Million, as previously reported $11 Million, adjusted for current normals 2014 $(11) Million 11 As Previously Reported Adjusted for current 10-year Rolling Average (2003-2012) (4) 12 1 (13) (13) 6

25 Third Quarter 2014 10 12 14 12 10 16 20 14 10 8 15 16 19 24 17 15 20 25 17 16 14 17 $0 $10 $20 $30 $40 $50 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Renewable Energy Demand Side Management 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 2012 $124 Million 2013 $137 Million 2014 $80 Million

26 Third Quarter 2014 NON-GAAP MEASURE RECONCILIATION GROSS MARGIN $ millions pretax, except per share amounts 2014 2013 Operating revenues* 1,173$ 1,152$ Fuel and purchased power expenses* (383) (351) Gross margin 790 801 (0.06) Adjustments: Renewable energy (excluding AZ Sun), demand side management and similar regulatory programs (26) (39) 0.07 Gross margin - adjusted 764$ 762$ 0.01$ * Line items from Consolidated Statements of Income Three Months Ended September 30, EPS Impact

27 Third Quarter 2014 NON-GAAP MEASURE RECONCILIATION OTHER NON-GAAP $ millions pretax, except per share amounts 2014 Four Corners Deferral Palo Verde Lease Extensions 2014 Adjusted 2013** Operations and maintenance* 223$ (6)$ -$ 217$ 233$ Renewable energy (excluding AZ Sun), demand side management and similar regulatory programs 32 - - 32 44 Net O&M 191 (6) - 185 189 0.02$ Depreciation and amortization* 104 7 (5) 106 107 0.02$ Taxes other than income taxes* 41 (1) - 40 43 0.02$ Allowance for equity funds used during construction* (7) - - (7) (6) Interest charges* 47 (2) - 45 51 Allowance for borrowed funds used during construction* (3) - (3) (3) Interest expense, net of AFUDC 37 (2) - 35 42 0.04$ Other expenses (operating)* 1 - - 1 2 Other income* (2) 2 - - - Other expense* 4 - - 4 7 Other 3 2 - 5 9 0.02$ Net income attributable to noncontrolling interests* 4 - 5 9 9 - * Line items from Consolidated Statements of Income ** No impact to 2013 Consolidated Statement of Income related to Four Corners deferral or Palo Verde lease extensions Totals may not sum due to rounding EPS Impact Three Months Ended September 30,