EX-99.3 4 exhibit993for63016.htm EXHIBIT 99.3
Second Quarter 2016 SECOND QUARTER 2016 RESULTS August 2, 2016

Second Quarter 20162 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 high reliability and customer service levels; variations in demand for electricity, including those due to weather seasonality, 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, ballet initiatives and regulation, including those relating to environmental requirements, regulatory policy, 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 and of debt and equity capital investments; 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, including in real estate markets; the development of new technologies which may affect electric sales or delivery; the cost of debt and equity capital and the ability to access capital markets when required; environmental and other concerns surrounding coal-fired generation, including regulation of greenhouse gas emissions; 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 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; 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, 2015, 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 the impacts associated with certain regulatory adjustments. We believe on-going earnings and these adjustments included in the reconciliation 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.

Second Quarter 20163 CONSOLIDATED EPS COMPARISON 2016 VS. 2015 $1.08 $1.10 2016 2015 2nd Quarter GAAP Net Income $1.08 $1.10 2nd Quarter On-Going Earnings $1.12 $1.25 2016 2015 Year-to-Date GAAP Net Income $1.12 $1.25 Year-to-Date On-Going Earnings

Second Quarter 20164 Gross Margin(1),(2) $0.21 ON-GOING EPS VARIANCES 2ND QUARTER 2016 VS. 2ND QUARTER 2015 Other, net $(0.01) Interest, net of AFUDC $(0.01) (1) Excludes costs and offsetting operating revenues, associated with renewable energy (excluding AZ Sun) and demand side management programs. (2) Adjusted to exclude Palo Verde system benefits charge. See non-GAAP reconciliation. O&M(1) $(0.19) 2Q 2015 2Q 2016 Gross Margin Weather $0.09 Sales $0.04 Transmission Line Sale $0.03 Transmission $0.02 LFCR $0.01 AZ Sun $0.01 Other, net $0.01 $1.10 $1.08 D&A(2) $(0.02)

Second Quarter 20165 ECONOMIC INDICATORS Arizona and Metro Phoenix remain attractive places to live and do business Single Family & Multifamily Housing Permits Maricopa County Job Growth (Total Nonfarm) – Metro Phoenix 0.0% 2.5% 5.0% '11 '12 '13 '14 '15 '16 Metro Phoenix U.S. YoY Change Construction, business services, financial services and healthcare adding jobs at a rate above 4% Phoenix ranked 1st in tech industry job growth over last 2 years (tied with San Francisco) - CBRE September 2015 Arizona ranked 1st for projected job growth - Forbes September 2015 E 0 10,000 20,000 30,000 40,000 '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 Single Family Multifamily May Metro Phoenix growth rate 3rd fastest among top 15 metro areas - U.S. Census Bureau March 2016 Housing construction on pace to have its best year since 2007

Second Quarter 20166 2016 ON-GOING EPS GUIDANCE Key Factors & Assumptions as of August 2, 2016 2016 Electricity gross margin* (operating revenues, net of fuel and purchased power expenses) $2.34 – $2.39 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 • Assumes normal weather Operating and maintenance* $825 - $845 million Other operating expenses (depreciation and amortization including impacts related to Palo Verde sale leaseback, and taxes other than income taxes) $645 - $665 million Interest expense, net of allowance for borrowed and equity funds used during construction (Total AFUDC $50 million) $155 - $165 million Net income attributable to noncontrolling interests ~$20 million Effective tax rate 34-35% Average diluted common shares outstanding ~112.0 million On-Going EPS Guidance $3.90 - $4.10 * Excludes O&M of $82 million, and offsetting revenues, associated with renewable energy and demand side management programs.

Second Quarter 2016 APPENDIX

Second Quarter 20168 2016 KEY DATES ACC Key Dates Docket # Q1 Q2 Q3 Q4 Key Recurring Regulatory Filings Lost Fixed Cost Recovery E-01345A-11-0224 Jan 15 Transmission Cost Adjustor E-01345A-11-0224 May 15 Renewable Energy Adjustor E-01345A-16-0238 Jul 1 APS Rate Case E-01345A-16-0036 Jan 29: Notice of Intent Filing Jun 1: Initial filing Dec 21: Direct testimony Resource Planning and Procurement E-00000V-15-0094 Feb 9: Stakeholder meeting Mar 1: Preliminary IRP filed Jul 18: Prelim IRP workshop Oct 1: File updates to preliminary IRP* Reducing System Peak Demand Costs E-00000J-16-0257 Aug 4: Initial workshop Value and Cost of Distributed Generation E-00000J- 14-0023 Feb 25: DG Methodologies & supporting testimony filed Apr 7: Rebuttal testimony and alternate proposals due Apr 15: Pre-hearing Apr 18: Hearing; Jun 8-9 Hearing Jun 13: Responses Due Jul 11: Initial briefs Aug 5: Reply briefs TBD: ALJ Order ACC Open Meetings - ACC Open Meetings Held Monthly * April 2017: Final IRP due Other Key Dates Docket # Q1 Q2 Q3 Q4 Arizona State Legislature n/a In session Jan 11- May 7 (Adjourned) Elections n/a Aug 30: Primary Nov 8: General All Source Request for Proposal (RFP) n/a Mar 11: RFP Issued Jun 9: Responses Due TBD

Second Quarter 20169 ARIZONA ELECTRIC UTILITIES GENERAL RATE CASES UNS Electric (93,000 customers) Docket # E-04204A-15-0142 Application filed May 5, 2015 Direct testimony - ex rate design, cost of service (Nov 6, 2015) Direct testimony - rate design, cost of service (Dec 9, 2015) Rebuttal testimony (Jan 19, 2016) Surrebuttal testimony (Feb 23, 2016) Rejoinder testimony (Feb 29, 2016) Prehearing (Feb 26, 2016) Hearing (Mar 1, 2016) Post hearing initial briefs (April 25, 2016) Reply briefs (May 11, 2016) ALJ recommended order and opinion (ROO) filed Jul 20, 2016 Exceptions to ROO due Jul 29, 2016 Tucson Electric Power Company (415,000 customers) Docket # E-01933A-15-0322 Application filed Nov 5, 2015 Direct testimony – ex rate design and cost of service (Jun 3, 2016) Direct testimony – rate design and cost of service (Jun 24, 2016) Rebuttal testimony (Jul 25, 2016) Surrebuttal testimony (Aug 18, 2016) Rejoinder testimony (Aug 25, 2016) Prehearing (Aug 25, 2016) Hearing (Aug 31, 2016) Sulphur Springs Valley Electric Cooperative (58,000 customers) Docket # E-01575A-15-0312 Application filed Aug 31, 2015 Direct testimony - ex rate design, cost of service (Mar 18, 2016) Direct testimony - rate design, cost of service (Apr 1, 2016) Rebuttal testimony (Apr 15, 2016) Surrebuttal testimony (May 4, 2016) Rejoinder (May 11, 2016) Prehearing (May 13, 2016) Hearing (May 17, 2016) – Concluded May 27 Trico Electric Cooperative (38,000 customers) Docket # E-01461A-15-0363 Application filed Oct 23, 2015 Direct testimony - ex rate design, cost of service (May 4, 2016) Direct testimony - rate design, cost of service (May 25, 2016) Rebuttal testimony (Jun 22, 2016) Surrebuttal testimony (Jul 8, 2016) Rejoinder (Jul 15, 2016) Prehearing (Jul 18, 2016) Direct settlement testimony (Jul 29, 2016) Reply settlement testimony (Aug 12, 2016) Hearing (Aug 17, 2016)

Second Quarter 201610 2016 APS RATE CASE APPLICATION • Filed June 1, 2016 • Propose new rates go into effect on July 1, 2017 • Docket Number: E-01345A-16-0036 • Additional details, including filing, can be found at http://www.azenergyfuture.com/rate-review/ Procedural Schedule Staff and Intervenor Direct Testimony (ex rate design) Staff and Intervenor Direct Testimony (rate design) APS Rebuttal Testimony Staff and Intervenor Surrebuttal Testimony APS Rejoinder Testimony Prehearing Conference Proposed Hearing Commencement Date December 21, 2016 January 27, 2017 February 17, 2017 March 10, 2017 March 17, 2017 March 20, 2017 March 22, 2017

Second Quarter 201611 2016 RATE CASE KEY FINANCIALS APS has requested a rate increase to become effective July 1, 2017 Test year ended December 31, 2015 Total Rate Base - Adjusted $8.01 Billion ACC Rate Base - Adjusted $6.77 Billion Allowed Return on Equity 10.5% Capital Structure Long-term debt 44.2% Common equity 55.8% Base Fuel Rate (¢/kWh) 2.9882 Post-test year plant period 18 months Overview of Rate Increase ($ in Millions) Total stated base rate increase (inclusive of existing adjustor transfers) $ 433.4 15.00% Less: Transfer to base rates of various adjustors already in effect (267.5) (9.26) Net Customer Bill Impact $ 165.9 5.74%

Second Quarter 201612 2016 RATE CASE KEY FINANCIALS APS has requested a rate increase to become effective July 1, 2017 Overview of Rate Increase ($ in Millions) – Key Components Post-Test Year Plant Additions $ 98.1 Fair Value Increment 51.9 ROE Increase from 10.0% to 10.5% 29.3 Increase due to Changes in Depreciation Schedules 81.4 Decrease Fuel and Purchased Power over Base Rates (61.7) Decrease in Other Costs (33.1) Total Base Rate Increase $ 165.9

Second Quarter 201613 Focus Area Current State Rate Case Objective Time-of-Use Rates (TOU) • > 50% of residential customers are on a TOU rate • On-peak hours from 12-7 PM (M-F) • TOU difference in on-peak prices that are 4 times the off-peak prices • Most residential customers on a TOU rate • On-peak hours from 3-8 PM (M-F) to better align with system peak • TOU difference in on-peak prices that are 2 times the off-peak prices Demand Rates • 11% of residential customers are on demand rates, more than any other electric utility • Most residential customers on demand rates • Calculated on the highest demand averaged over a one-hour period during the on-peak period each month Basic Service (Fixed) Charge • Customers pay basic service charge ranging from $8.67 - $16.91 per month • Set basic service charge for all rate classes ranging from $14 - $24 per month Net Metering • Excess power compensated at full retail price • Excess power compensated at export price aligned with avoided cost • Recovery of cost to purchase through existing PSA mechanism • Grandfather qualified rooftop solar customers Lost Fixed Cost Recovery (LFCR) • 1% year-over-year adjustment cap based on total revenues • Recovers portion of costs reduced by energy efficiency (EE) and distributed generation (DG) programs • Similar construct, but increase year-over-year adjustment cap to 2% based on total revenues • Increased portion of lost fixed costs eligible for recovery RATE DESIGN MODERNIZATION Rate design that better aligns pricing with cost to serve and leverages existing platform

Second Quarter 201614 RATE DESIGN MODERNIZATION Key residential rate proposals designed to reduce cost shift among customers • Streamlined rate choices for residential customers including combinations of the following: – Reduced kWh charges for variable portion (energy rate) – Increased fixed charge component (basic service charge) – Variations of new demand (kW) charge applied to on-peak hours • Measured using a customer’s peak demand during on-peak hours (3-8 pm, Monday-Friday) • Peak demand then multiplied by a demand rate • Example: – 5kW demand during on-peak* – $6.60/kW demand rate (R-1 rate plan) – 5kW x $6.60 = $33.00 demand charge Variable Variable (energy rate per kWh) Fixed Fixed (basic service charge) Demand (demand rate per kW) Current Customer Bill Proposed Customer Bill * Peak demand is calculated on the highest demand averaged over a one-hour period during the on-peak period each month.

Second Quarter 201615 OCOTILLO MODERNIZATION PROJECT AND FOUR CORNERS SCRs Ocotillo Modernization Project Four Corners SCRs In-Service Dates Units 6, 7 – Fall 2018 Units 3, 4 and 5 – Spring 2019 Unit 5 – Late 2017 Unit 4 – Spring 2018 Total Cost (APS) $500 million $400 million Estimated Cost Deferral $45 million (through 2019) $30 million (through 2018) Rate Request Requesting cost deferral from date of commercial operation to the effective date of rates in next rate case Requesting cost deferral order from time of installation to incorporation of the SCR costs in rates using a step increase beginning in 2019 • Included in the 2016 rate case application, APS is requesting Accounting Deferral Orders for two large generation-related capital investments – Ocotillo Modernization Project: Retiring two aging, steam-based, natural gas units, and replacing with 5 new, fast-ramping, combustion turbine units – Four Corners Power Plant: Installing Selective Catalytic Reduction (SCR) equipment to comply with Federal environmental standards

Second Quarter 201616 FINANCIAL OUTLOOK Key Factors & Assumptions as of August 2, 2016 Assumption Impact Retail customer growth • Expected to average about 2-3% annually • 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 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 • Four Corners rate increase effective January 1, 2015 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 (2016-2018) Gross Margin – Related to 2012 Retail Rate Settlement Outlook Through 2016: Goal of earning more than 9.5% Return on Equity (earned Return on Equity based on average Total Shareholder’s Equity for PNW consolidated, weather-normalized)

Second Quarter 201617 Credit Ratings • A- rating or better at S&P, Moody’s and Fitch 2016 Major Financing Activities • Repaid, at maturity, $250 million of 6.25% senior unsecured notes due August 1 • $350 million 30-year 3.75% APS senior unsecured notes issued May 2016 • $100 million term loan closed April 2016 • Currently expect up to an additional $350 million of long-term debt We are disclosing credit ratings to enhance understanding of our sources of liquidity and the effects of our ratings on our costs of funds. BALANCE SHEET STRENGTH $50 $600 $250 $125 $- $100 $200 $300 $400 $500 $600 2017 2018 2019 2020 APS PNW ($Millions) Debt Maturity Schedule

Second Quarter 201618 OPERATIONS & MAINTENANCE OUTLOOK Goal is to keep O&M per kWh flat, adjusted for planned outages $754 $761 $788 $805 $772 $150 $124 $137 $103 $96 $82 2011 2012 2013 2014 2015 2016E PNW Consolidated RES/DSM* *Renewable energy and demand side management expenses are offset by adjustment mechanisms. ($ Millions) $825 - $845

Second Quarter 201619 $263 $220 $224 $288 $66 $77 $235 $114 $44 $227 $201 $103 $58 $107 $1 $1 $201 $122 $217 $139 $340 $359 $346 $398 $85 $93 $83 $81 2015 2016 2017 2018 CAPITAL EXPENDITURES Capital expenditures are funded primarily through internally generated cash flow ($ Millions) $1,205 $1,307 Other Distribution Transmission Renewable Generation Environmental(1) Traditional Generation Projected $1,124 New Gas Generation(2) $1,057 • The table does not include capital expenditures related to 4CA’s 7% interest in Four Corners Units 4 and 5 of $3 million in 2015, $30 million in 2016 and $25 million in 2017. • 2016 – 2018 as disclosed in Second Quarter 2016 Form 10-Q. (1) Includes Selective Catalytic Reduction controls at Four Corners with in-service dates of Q4 2017 (Unit 5) and Q1 2018 (Unit 4) (2) Ocotillo Modernization Project: 2 units scheduled for completion in Q4 2018, 3 units schedule for completion in Q1 2019

Second Quarter 201620 249 357 339 442 610 710 641 785 871 939 523 837 489 688 835 721 1163 1163 1358 1150 1011 1201 1093 11841187 782 1315 1055 1460 1680 0 250 500 750 1000 1250 1500 1750 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2014 Applications 2015 Applications 2016 Applications * As of June 30, 2016, over 45,000 residential grid-tied solar photovoltaic (PV) systems have been installed in APS’s service territory. Excludes APS Solar Partner Program residential PV systems. Note: www.arizonagoessolar.org logs total residential application volume, including cancellations. Solar water heaters can also be found on the site, but are not included in the chart above. RESIDENTIAL PV APPLICATIONS* 15 19 23 44 51 57 74 2009 2011 2013 2015 Residential DG (MW) Annual Additions

Second Quarter 201621 (8) (4) 2 5 (5) 13 $(10) $(5) $0 $5 $10 $15 Q1 Q2 Q3 Q4 Q1 Q2 GROSS MARGIN EFFECTS OF WEATHER VARIANCES VS. NORMAL Pretax Millions All periods recalculated to current 10-year rolling average (2005-2014) 2015 $(5) Million 2016 $8 Million

Second Quarter 201622 12 7 11 11 8 4 11 14 18 12 12 15 $0 $10 $20 $30 $40 Q1 Q2 Q3 Q4 Q1 Q2 Renewable Energy Demand Side Management RENEWABLE ENERGY AND DEMAND SIDE MANAGEMENT EXPENSES* * O&M expenses related to renewable energy and demand side management programs are partially offset by comparable revenue amounts Pretax Millions 2015 $96 Million 2016 $39 Million

Second Quarter 201623 NON-GAAP MEASURE RECONCILIATION $ millions pretax, except per share amounts 2016 2015 Operating revenues* 915$ 891$ Fuel and purchased power expenses* (275) (282) Gross margin 640 609 0.17$ Adjustments: Renewable energy (excluding AZ Sun) and demand side management programs (13) (17) 0.02 Palo Verde system benefits charge 4 - 0.02 Adjusted gross margin 631$ 592$ 0.21$ Depreciation and amortization* (123)$ (123)$ -$ Adjustments: Palo Verde system benefits charge (4) - (0.02) Adjusted depreciation and amortization (127)$ (123)$ (0.02)$ * Line items from Consolidated Statements of Income Three Months Ended June 30, EPS Impact