EX-99.1 2 investorconferencestoron.htm EXHIBIT 99.1
Powering Growth, Delivering Value Investor Meetings – Toronto and Montreal | March 31 – April 1, 2015 POWERING GROWTH DELIVERING VALUE

Powering Growth, Delivering Value2 FORWARD LOOKING STATEMENTS 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 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; 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; 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, 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.

Powering Growth, Delivering Value3 PINNACLE WEST: WHO WE ARE We are a vertically integrated, regulated electric utility in the growing southwest U.S. Principal subsidiary: - Arizona Public Service Company, Arizona’s largest and longest-serving electric utility - Regulated utility provides stable, regulated earnings and cash flow base for Pinnacle West Customers: 1.2 million (89% residential) Service Territory: - 34,646 square miles - 11 of the 15 Arizona counties 2014 Peak Demand: 7,007 MW - All time high of 7,236 in July 2006 Generation Capacity: Over 6,400 MW of owned or leased capacity (~9,400 MW with long-term contracts) - Including 29.1% interest in Palo Verde Nuclear Generating Station, the largest in the U.S. Transmission & Distribution: 34,937 miles - Transmission: 5,958 miles - Distribution: 28,979 miles

Powering Growth, Delivering Value4 PINNACLE WEST: KEY METRICS NYSE Ticker: PNW Market Capitalization*: $7.1 billion Enterprise Value*: $10.8 billion Consolidated Assets: $14.3 billion Indicated Annual Dividend*: $2.38 Dividend Yield*: $3.6% APS Credit Ratings (Moody’s/S&P): A3/A- APS Credit Ratings Outlook (Moody’s/S&P): Positive/Stable * As of March 16, 2015 52% 42%6% 1% Operating Revenues (2014): $3.5 Billion Residential Commercial Industrial Other

Powering Growth, Delivering Value5 VALUE PROPOSITION • Top decile ratings in Customer Satisfaction, top quartile in Reliability and Safety • Palo Verde continues record levels of electricity production • Disciplined cost management Operational Excellence • Arizona’s long-term growth fundamentals remain largely intact Leverage to Economic Recovery • Creating a sustainable energy future for Arizona • Working with Arizona Corporation Commission and key stakeholders to modernize rates Proactively Addressing Rate Design • Rate base growth of 6-7% through 2018 • Focus on core electric utility business • Investing in a portfolio that is flexible, responsive, reliable and cost-effective Executing on Long-Term Investment Plan • Consolidated earned ROE more than 9.5% through 2016, weather-normalized • Dividend growth target of 5% • Strong credit ratings Financial Strength Driving Competitive Returns

Powering Growth, Delivering Value6 30.2 30.4 30.4 30.8 30.6 31.2 31.3 31.9 31.4 20 22 24 26 28 30 32 1998 2002 2006 2010 2014 OPERATIONAL EXCELLENCE 108 97 65 58 47 35 43 0 30 60 90 120 2008 2009 2010 2011 2012 2013 2014 Palo Verde Palo Verde has exceeded its own record for generation–32.3 million megawatt-hours annual production in 2014. Palo Verde is the only plant in the U.S. to exceed 30M MW annual production. Safety APS achieved another safe year in 2014. APS ranks in the Top Quartile of electric utility companies. 0 20 40 60 80 100 2008 2009 2010 2011 2012 2013 2014 APS Industry Top Quartile Customer Satisfaction Ranked 5th highest nationally among 54 large investor-owned electric utilities in 2014 J.D. Power residential customer survey. Lowering Outage Time Per Customer Top quartile in industry over past several years. A v e r a g e O u t a g e M i n u t e s / Y e a r M i l l i o n M e g a w a t t H o u r s 500 550 600 650 700 R a t i n g Industry Average APS 32.3

Powering Growth, Delivering Value7 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 '15 YoY Change E Q4Dec 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 '15 Single Family Multifamily Jan

Powering Growth, Delivering Value8 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)

Powering Growth, Delivering Value9 • Cumulative savings from energy efficiency programs must be equivalent to 22% of annual retail sales by 2020 • Annual milestones in place to measure progress toward cumulative 2020 goal – 9.5% by 2015 – 22% by 2020 ARIZONA’S RENEWABLE RESOURCE AND ENERGY EFFICIENCY STANDARDS • Portion of retail sales to be supplied by renewable resources – 5% by 2015* – 15% by 2025 • Distributed energy component – 30% of total requirement Energy Efficiency RequirementsRenewable Energy (RES) Requirements APS on track to double 2015 requirement* APS on track to meet target * In APS’s 2009 retail rate case settlement agreement, APS committed to have 1,700 GWh of new renewable resources in service by year-end 2015 in addition to its 2008 renewable resource commitments.

Powering Growth, Delivering Value10 KEY DATES FOR RATE DESIGN 2012 2013 2014 2015+ • APS proposed stakeholder conference to explore net metering • Spring: Conducted series of Technical Workshops on Net Metering • July: 2014 RES filing • November: ACC decision on net metering; recognized cost shift and implemented $0.70 per watt charge effective January 1, 2014 • Mar–Aug: Innovations and Tech Development Workshop Series • April 15: Initial quarterly filing on rooftop solar installations • May/June: Value and Cost of Dist. Gen. Workshop Series • Aug. 12: ACC voted to lift decision to require a rate case filing in 2015 • Fall: Ongoing discussions on rate design process • Time of Use rates initiated - Nearly half of our residential customers are on TOU rates • Residential demand rates started due to central air conditioning load (currently about 10% of customers have a rate with a demand charge) Early 1980’s • TBD: Rate design and revenue requirement filings

Powering Growth, Delivering Value11 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

Powering Growth, Delivering Value12 ARIZONA CORPORATION COMMISSION * Term limited - elected to four-year terms (limited to two consecutive) Bob Stump (R)* Tom Forese (R) Doug Little (R) Terms to January 2019Terms to January 2017 Susan Bitter Smith (R) Chairman Bob Burns (R)

Powering Growth, Delivering Value13 RESOURCE PLANNING* 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 2014 2017 2020 2023 2026 2029 Existing Owned Resources Existing Contracts Resource Planning Requirement Load Requirement Including Reserves MW 20.1% 35.3% 27.7% 9.5% 7.5% 17.0% 2014 Gas Coal Nuclear RE + DE EE Composition of Energy Mix by Resource* Note: RE = Renewable Energy; DE = Distributed Energy; EE = Energy Efficiency 35.0% 16.9% 18.1% 14.7% 15.3% *Data shown is based on the Integrated Resource Plan Supplement filed September 17, 2014. 2029

Powering Growth, Delivering Value14 $289 $354 $526 $467 $24 $36 $162 $161 $63 $86 $1 $2 $192 $203 $133 $180 $242 $329 $362 $385 $73 $83 $81 $98 2014 2015 2016 2017 CAPITAL EXPENDITURES 70% of capital expenditures are recovered through rate adjustors (30%) and depreciation (40%) on average for 2014-2017 ($ Millions) $883 $1,091 $1,265 Other Distribution Transmission Renewable Generation Environmental Traditional Generation Projected $1,293 • The table does not include capital expenditures related to El Paso's 7% interest in Four Corners Units 4 and 5 of $24 million in 2016 and $23 million in 2017. The consummation of the purchase of El Paso's interest in Four Corners is not expected to take place until 2016, thus, there are no related capital expenditures in 2015. • Capital Expenditures do not include cost of Plant Decommissioning. • 2015 – 2017 as disclosed in 2014 Form 10-K.

Powering Growth, Delivering Value15 Regional Haze / BART (SCR) Mercury and Other Hazardous Air Pollutants (ACI + Baghouse) Coal Combustion Residuals Cooling Water Intake – 316(b) EPA Ruling Announced in 1999, with site-specific requirements announced more recently MATS compliance by April 2015, with potential for one-year extension Announced on December 19, 2014 (Subtitle D) Announced in May 2014 Four Corners 4-5 At least $350M for SCRs in 2015-2017 (does not include CAPEX related to El Paso’s 7% interest) $0 APS estimates that is share of incremental costs to comply with the CCR rule for Four Corners is approximately $15 million, and its share of incremental costs for Cholla is approximately $85 million. APS expects to incur certain of these costs during 2015-2017 timeframe. $20M or less Cholla 2-3 On September 11, 2014, APS announced a proposal to close Unit 2 by April 2016 and stop burning coal at the other APS-owned units (1 and 3) by the mid-2020’s if the EPA approves the proposed plan. The proposal would save more than $350 million in emission control upgrades. $0 Navajo 1-3 Up to ~$200M for SCRs and baghouses, expected to occur after 2015 On July 28, 2014, EPA issued the final BART rule incorporating the better-than-BART alternative proposed by SRP and others, which would defer spend until 2021 or later SRP, the operating agent, is evaluating compliance options To be determined To be determined ENVIRONMENTAL Regional Haze compliance is the biggest driver of environmental spend over the next 3-4 years Note: On June 2, 2014, EPA proposed the Clean Power Plan to achieve state-specific goals to achieve carbon dioxide emission reductions measured from a 2012 baseline. States would be required to submit their plan by June 2016. States may be eligible for one or two year extensions (for sources on Native American land, including Four Corners and Navajo, EPA is expected to issue a final plan by June 2015). Impact to APS is under review. Note: Dollars shown at ownership. Estimates as of December 31, 2014. • Cholla Unit 1 is not BART-eligible. Cholla Unit 4 is owned by PacifiCorp. • SO2 NAAQS and greenhouse gas-related costs will be determined based upon EPA rule makings, with no spend occurring before 2016. • ACI = Activated Carbon Injection; NAAQS = National Ambient Air Quality Standard; SCR = Selective catalytic reduction control technology

Powering Growth, Delivering Value16 BRIGHT CANYON ENERGY – TRANSMISSION GROWTH DELANEY COLORADO RIVER TRANSMISSION LINE New 500kV line between the planned Delaney substation near Palo Verde Nuclear Generating Station in Arizona and the Colorado River substation, located just west of Blythe, California In July 2014, California ISO Board approved DCR and is working through selection process; decision expected summer 2015 TRANSCANYON A 50/50 Joint Venture formed with MidAmerican Transmission, subsidiary of Berkshire Hathaway Energy, to pursue transmission opportunities in the western United States BRIGHT CANYON ENERGY Pinnacle West subsidiary formed to pursue new growth opportunities DCR Transmission Line WECC

Powering Growth, Delivering Value17 DELANEY COLORADO RIVER TRANSMISSION LINE – KEY DATES CAISO Transmission Planning Process Bid Submitted November 19, 2014 Post List of Sufficient Applications (i.e. list of bidders) April 16, 2015 Post List of Qualified Sponsors May 7, 2015 Post Approved Sponsor & Report (i.e. winning bid) August 31, 2015 Permitting, construction, etc. 2015 - 2020 In Service May 2020 Source: CAISO as of February 27, 2014 Note: TransCanyon collaborated with Southern California Edison to submit a joint proposal, replacing the original bids by TransCanyon and SCE. No other parties collaborated; there are a total of five bids.

Powering Growth, Delivering Value18 Benchmark peers and determine gaps Develop Long- term business plan and annual targets Quarterly measurement and discussion to drive accountability SUSTAINABLE COST MANAGEMENT INGRAINED IN BUSINESS PLANNING FRAMEWORK Results to Date: • Reduction of 300+ positions • Palo Verde Unit Production Cost reduced from 2.2¢ to 2.0¢ per kWh • Fossil Generation shifted to fleetwide model in 2010 to streamline costs • Annual Supply savings of $30 million • Realigned corporate resource model • Documented nearly 1,000 policies, processes and procedures documented and completed over 150 process improvements Linked through Tiered Metrics Enterprise Process Improvement is current phase of Sustainable Cost Management -- a standardized, systematic approach to determining how to do our work better including documentation, driven by retiring workforce and need to control costs

Powering Growth, Delivering Value19 0% 1% 2% 3% 4% 5% 6% 30% 50% 70% 90% $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 Yield as of March 16, 2015 Payout 12 Months Ended December 31, 2014 Dividend Yield Dividend Payout PNW Industry Averages Future dividends subject to declaration at Board of Directors’ discretion

Powering Growth, Delivering Value20 2015 KEY DATES ACC Key Dates Docket # Q1 Q2 Q3 Q4 Key Regulatory Filings Lost Fixed Cost Recovery 11-0224 Jan 15 Net Metering – Quarterly Installation Filings 13-0248 Jan 15 Apr 15 Jul 15 Oct 15 Transmission Cost Adjustor 11-0224 May 15 Renewable Energy Surcharge TBD Jul 1 2014 Integrated Resource Plan (Biennial) and Cholla Unit 2 Retirement Proposal 13-0070 April: ACC Review of 2014 RFP Energy Efficiency 13-0214 TBD Ocotillo Modernization Project 14-0292 Jan – Q2: RFP Rate Design Process 14-0329 TBD Inquiry into Solar DG business models and practices (Generic Docket)* 14-0415 ACC to outline next steps ACC Open Meetings - ACC Open Meetings Held Monthly Other Key Dates Docket # Q1 Q2 Q3 Q4 Arizona State Legislature n/a In Session Jan 12 – End of Q2 Delaney Colorado River Transmission Line (California ISO) n/a Jan: Bidders posted Aug: Cal ISO selects winning bid * Members of Congress have also sent letters to the Consumer Financial Protection Bureau and US FTC, requesting responses, which may occur in 2015.

Powering Growth, Delivering Value APPENDIX

Powering Growth, Delivering Value22 LEADERSHIP TEAM Our top executives have more than 100 combined years of creating shareholder value in the energy industry Don Brandt Chairman & Chief Executive Officer Mark Schiavoni EVP & Chief Operating Officer Jeff Guldner SVP Customers & Regulation Randy Edington EVP & Chief Nuclear Officer Jim Hatfield EVP & Chief Financial Officer

Powering Growth, Delivering Value23 PALO VERDE NUCLEAR GENERATING STATION Largest generating nuclear plant in the United States • Total Capacity: 4,000 MW (3 units) o APS share: 1,146 MW; APS operated o Output: 32.3 million MWh in 2014 o Approximately 2,800 employees • Fukushima-related impacts o Total Fukushima-related costs are approximately $120 million (APS share is 29.1%), through 2016 o National Strategic Alliance for FLEX Emergency Response (SAFER) Centers are located in Phoenix and Memphis, opened in 2014 Palo Verde Phoenix Low risk of natural events at Palo Verde In Service License* Unit 1 1985 2045 Unit 2 1986 2046 Unit 3 1987 2047 * NRC approved 20-year license extensions in April 2011. Note: Each of the pressurized water reactor units has a planned refueling outage every 18 months (i.e. two total outages per year).

Powering Growth, Delivering Value24 $19.93 $23.26 $21.13 2007 2008 2009 2010 2011 2012 2013 2014 D o l l a r s p e r M e g a w a t t - H o u r PALO VERDE OPERATING COSTS ARE BELOW INDUSTRY AVERAGES AND IMPROVING Industry Average Industry Median Source: Electric Utility Cost Group (EUCG)

Powering Growth, Delivering Value25 • Benefits: – 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 (2015 – 2018) • Expected timeline: – Early 2014: Stakeholder engagement and initiate permitting activities – November 5, 2014: ACC approved Certificate of Environmental Compatibility – 2015: Conduct RFP for approximately 300 MW capacity – Late 2015 / Early 2016: Planned start of construction (pending outcome of RFP) – Q2 2018: Project completion – increase OCOTILLO POWER PLANT (TEMPE, AZ) Ocotillo modernization project will maintain valley grid reliability and increase APS’s generating capacity by 290 MW 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 (2) GE 102 MW combustion turbines 0 204 Install 3 combustion turbines (subject to RFP) 0 306 Total 330 620 Net site capacity increased by 290 MW

Powering Growth, Delivering Value26 • 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 – APS will continue to operate Four Corners and now has total interest of about 970 MW – Four Corners-specific revenue requirement ($57.1 million) rates effective January 1, 2015 (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 Selective Catalytic Reduction (“SCR”) control technology on Units 4-5 by July 31, 2018 FOUR CORNERS POWER PLANT – EPA permitting process is in underway; construction expected to begin by early 2016 after approval of final EPA permit – Estimated environmental compliance: At least $350 million, primarily in 2016-2017 – In February 2015, APS and El Paso Electric entered into an asset purchase agreement for the purchase of El Paso’s 7% interest in each of Units 4 and 5

Powering Growth, Delivering Value27 • 10-Year Transmission Plan filed January 2015 (115 kV and above) – 275 miles of new lines – Includes Hassayampa-North Gila (HANG2) • ~110 miles; 500kV • Construction started March 2013 • Estimated in-service mid 2015 • Also includes other planned lines – Palm Valley-TS2-Trilby Wash 230kV (2015) – Delaney-Palo Verde 500kV (2016) – Delaney-Sun Valley 500kV (2016) – Sun Valley-Trilby Wash 230kV (2016) – Morgan-Sun Valley 500kV (2018) • Projects to deliver renewable energy approved by ACC • Transmission investment diversifies regulatory risk – Constructive regulatory treatment – FERC formula rates and retail adjustor APS TRANSMISSION Strategic transmission investment is essential to maintain reliability and deliver diversified resources to customers Legend Planned lines Existing lines Solar potential area Wind potential area Phoenix Flagstaff Tucson

Powering Growth, Delivering Value28 • Community-scale photovoltaic solar plants to be owned by APS • Constructive rate recovery through RES until included in base rates • Commitments to date: 170 MW, $674 million capital investment (average of $3,965/kw) • APS-owned rooftop solar (10 MW) not included in totals 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* Cost Paloma Gila Bend, AZ 17 MW First Solar September 2011 ~$4,500/kw 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 June 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 October 2014 ~$3,500/kw City of Phoenix Buckeye, AZ 10 MW McCarthy Mid 2015 TBD Luke Air Force Base Glendale, AZ 10 MW McCarthy Mid 2015 TBD Total 170 MW As of December 31, 2014 * In-Service or Commercial Operation Date

Powering Growth, Delivering Value29 APS SOLAR PARTNERS PROGRAM • APS to implement 10 MW of APS-owned residential rooftop solar − On December 19, 2014, ACC voted that it had no objection to APS implementing the program − Equates to approximately 1,500 customers − Will be filed for recovery in next general rate case − 2 MW (of the 10 MW) will only de deployed if coupled with distributed storage • Benefits: − Provides an alternative for those who cannot afford solar or do not want a lease − Study system benefits (i.e. west or SW oriented panels, advanced inverters, etc.) − Participating customers receive monthly credit on their bill through the 20-year life − Support and partner with Arizona solar installers • APS has track record through the Flagstaff Community Power Project − Launched in 2010 − 1.5 MW of distributed energy from solar panels owned by APS, spread across: • 125 residential rooftops • Schools • Neighborhood-scale solar power plant • TBD

Powering Growth, Delivering Value30 As of February 28, 2015, about 31,000 residential grid-tied solar photovoltaic (PV) systems have been installed in APS’s service territory, equivalent to over 200 MW. *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 above chart. 881 980 549 898 250 600 364 780 346 453 642 731 658 810 60 83 30 34 28 28 33 22 83 38 40 59 60 77 0 200 400 600 800 1,000 1,200 14-Jan 15-Jan2 14-Feb 15-Feb 14-Mar2 15-Mar 14-Apr3 15-Apr 14-May3 15-May Column2 14-Jun3 15-Jun 14-Jul3 15-Jul 14-Aug3 15-Aug Column3 14-Sep3 15-Sep Column4 14-Oct3 15-Oct Column5 14-Nov3 15-Nov Column6 14-Dec3 15-Dec RESIDENTIAL PV APPLICATIONS 2014 Applications* 2014 Canceled Apps Jan Feb Mar A r M y Jun Jul Aug Sep Oct Nov D c 2015 Applications* 2015 Canceled Apps

Powering Growth, Delivering Value31 • Customers with rooftop solar systems do not pay for all of the electric services they use (i.e. rooftop customers still need support from the grid 24 hours a day) • These unpaid costs are then paid, through higher rates, by non-rooftop solar customers • The issue will get bigger over time as applications and installs continue to increase NET METERING Rooftop solar customers still use the grid 24 hours a day TYPICAL GRID INTERACTION FOR ROOFTOP SOLAR

Powering Growth, Delivering Value32 OPERATIONAL CONSIDERATIONS WITH INCREASED VARIABLE GENERATION The grid provides real-time voltage and power needed to start air conditioners and other motors loads (for typical AC unit) • Steep ramp rate of backup generation • Instant variability • Voltage control at distribution level

Powering Growth, Delivering Value33 EMERGING TECHNOLOGIES RELY ON THE GRID All of these technologies are part of an integrated grid Electric Vehicles Battery Storage Fuel Cells Home Energy Management Microgrids Rooftop Solar Electrical System

Powering Growth, Delivering Value34 RELIABILITY SERVICES REQUIRE TECHNOLOGY ADVANCEMENTS ON THE UTILITY SIDE Substation Health Monitoring Integrated Volt/VAR Control (IVVC) Communicating Fault Indicators (CFI) Synchrophasors (WISP) Supervisory Controlled Switches Advanced Distribution Management System Smart Meters Energy Management System (EMS) Upgrades Strategic Fiber Over 2.6 Million Customer Outage Minutes Avoided

Powering Growth, Delivering Value35 • APS has reached full AMI (Advanced Metering Infrastructure) deployment, a project lasting eight years – 1,250,000 Elster meters deployed – Includes nearly 30,000 solar production meters • Benefits to customers: – Aid customers in choosing the optimal rate plan to reduce energy costs – Provides more granular data so customers can change behavior to conserve use • Benefits to APS: – More than 1.7 million AMI avoided field orders since 2011 (70% of total field orders); resulting in $19 million in savings – Ability to leverage business intelligence applications to manage our operations and improve load forecasting – Improved safety resulting from avoided field orders AMI INSTALLATION COMPLETE

Powering Growth, Delivering Value36 CREDIT RATINGS APS Parent Corporate Credit Ratings Moody’s A3 Baa1 S&P A- A- Fitch BBB+ BBB+ Senior Unsecured Moody’s A3 - S&P A- - Fitch A- - Outlook Moody’s Positive Positive S&P Stable Stable Fitch Positive Positive We are disclosing credit ratings to enhance understanding of our sources of liquidity and the effects of our ratings on our costs of funds. Investment Grade Credit Ratings

Powering Growth, Delivering Value37 2010 2011 2012 2013 2014 APS FFO / Debt 23.7% 23.6% 27.7% 31.5% 26.6% FFO / Interest 3.3x 4.2x 4.8x 5.6X 5.8x Debt / Capitalization 52.6% 52.9% 50.7% 47.7% 46.3% Pinnacle West FFO / Debt 22.3% 23.0% 26.7% 29.8% 23.6% FFO / Interest 3.1x 3.8x 4.4x 4.9X 5.6x Debt / Capitalization 54.6% 54.4% 52.1% 49.1% 47.7% S&P CREDIT METRICS Key credit metrics have been improving Source: Standard & Poor’s

Powering Growth, Delivering Value38 FINANCING $300 $250 $500 $250 $125 $- $100 $200 $300 $400 $500 $600 2015 2016 2017 2018 2019 2020 APS PNW ($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 • Refinanced $125 million PNW term loan 2015 Major Financing Activities • $250 million 5-year 2.20% APS senior unsecured notes issued in January 2015 • Currently expect up to an additional $275 million of new long-term debt, in addition to refinancing maturing debt – $300 million (4.65%) APS long-term debt due May 15, 2015 • In addition, there will be tax-exempt series remarketed or refinanced

Powering Growth, Delivering Value39 2015 – 2017 FINANCIAL OUTLOOK Key Factors & Assumptions as of February 20, 2015 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 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 Gross Margin – Related to 2012 Retail Rate Settlement

Powering Growth, Delivering Value40 OPERATIONS & MAINTENANCE OUTLOOK Targeting to be top quartile in peer benchmarking for staffing $749 $754 $761 $788 $805 $121 $150 $124 $137 $103 $113 2010 2011 2012 2013 2014 2015E PNW Consolidated RES/DSM* *Renewable energy and demand side management expenses are offset by revenue adjustors. $795 - $815 ($ Millions) 2015+ Outlook • Goal is to keep O&M per kWh flat • Complete documentation of over 1,800 policies, processes and procedures, including more than 275 process improvements to drive additional efficiencies • Execute targeted initiatives to address specific gaps and inefficiencies

Powering Growth, Delivering Value41 • Funded status of the pension plan maintained at 90% YE2014, due in large part to the continued implementation of the liability driven investment strategy. • In October 2014, the Society of Actuaries issued its final report on mortality tables. The data shown incorporates the updated mortality assumptions using a modification of these tables, which better reflect our employee’s demographics. PENSION & OTHER POST RETIREMENT BENEFITS (“OPEB”) 77% 90% 90% YE 2012 YE 2013 YE 2014 Pension Funded Status(1) Expense(2) 2014A 2015E 2016E Pension(1) $14 $14 $7 OPEB $6 ($9) ($8) Contributions 2014A 2015E 2016E 2017E Pension $175 $100 Up to $100 Up to $100 OPEB $1 $1 $1 $1 Assumptions 12/31/2013 12/31/2014 Discount Rate: Pension 4.88% 4.02% Expected Long-Term Return on Plan Assets: Pension 6.90% 6.90% (1) Excludes supplemental excess benefit retirement plan. (2) Excludes approximately 50% of total estimated expense which is attributable to amounts capitalized or billed to electric plant participants. Data as of February 20, 2015 ($ in millions)

Powering Growth, Delivering Value42 Mechanism Adopted / Last Adjusted Description Power Supply Adjustor (“PSA”) April 2005 / February 2015 • Recovers variance between actual fuel and purchased power costs and base fuel rate • Includes forward-looking, historical and transition components Renewable Energy Surcharge (“RES”) May 2008 / January 2015 • Recovers costs related to renewable initiatives • Collects projected dollars to meet RES targets • Provides incentives to customers to install distributed renewable energy Demand-Side Management Adjustment Clause (“DSMAC”) April 2005 / March 2015 • Recovers costs related to energy efficiency and DSM programs above $10 million in base rates • Provides performance incentive to APS for net benefits achieved • Provides conservation education, rebates and other incentives to participating customers Environmental Improvement Surcharge (“EIS”) July 2007 / April 2014 • Allows recovery of certain carrying costs for government-mandated environmental capital projects • Capped at $5 million annually Transmission Cost Adjustor (“TCA”) April 2005 / June 2014 • Recovers FERC-approved transmission costs related to retail customers • Resets annually as result of FERC Formula Rate process (see below) FERC Formula Rates 2008 / June 2014 • Recovers transmission costs based on historical costs per FERC Form 1 and certain projected data Lost Fixed Cost Recovery (“LFCR”) July 2012 / March 2015 • Mitigates loss of portion of fixed costs related to ACC-approved energy efficiency and distributed renewable generation programs REGULATORY MECHANISMS We have achieved a more supportive regulatory structure and improvements in cost recovery timing

Powering Growth, Delivering Value43 • 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

Powering Growth, Delivering Value44 • 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 upon ACC approval (typically March 1 or April), based on the EE and DG savings from the preceding calendar year – Subject to year-over-year 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 2014 ACC Order 2015 ACC Order Rates Effective March 1, 2014 March 5, 2015 LFCR Rate 0.95% 1.4592% Residential rate per lost kWh $0.031 $0.031 Non-residential rate per lost kWh $0.023 $0.023 LFCR Adjustment (Annualized) $25.4 Million $38.5 Million LFCR Revenue (Accrued in prior year) $22.6 Million $34.5 Million Incremental Revenue $15.3 Million $11.9 Million 2012 2013 2014 2015 2015 Revenue 2014 Revenue 2013 Revenue 2012 Revenue Rate Recovery

Powering Growth, Delivering Value45 GENERATION PORTFOLIO* Fuel/Plant Location Units Dispatch COD Ownership Interest1 Net Capacity (MW) NUCLEAR 1,146 MW Palo Verde Wintersburg, AZ 1-3 Base 1986-1989 29.1% 1,146 COAL 1,932 MW Cholla Joseph City, AZ 1-3 Base 1962-1980 100 647 Four Corners Farmington, NM 4, 5 Base 1969-1970 63 970 Navajo Page, AZ 1-3 Base 1974-1976 14 315 GAS/OIL COMBINED CYCLE 1,871 MW Redhawk Arlington, AZ 1, 2 Intermediate 2002 100 984 West Phoenix Phoenix, AZ 1-5 Intermediate 1976-2003 100 887 GAS/OIL STEAM TURBINES 220 MW Ocotillo Tempe, AZ 1, 2 Peaking 1960 100 220 GAS/OIL COMBUSTION TURBINES 1,088 MW Sundance Casa Grande, AZ 1-10 Peaking 2002 100 420 Yucca Yuma, AZ 1-6 Peaking 1971-2008 100 243 Saguaro Red Rock, AZ 1-3 Peaking 1972-2002 100 189 West Phoenix Phoenix, AZ 1, 2 Peaking 1972-1973 100 110 Ocotillo Tempe, AZ 1, 2 Peaking 1972-1973 100 110 Douglas Douglas, AZ 1 Peaking 1972 100 16 SOLAR 169 MW Hyder Hyder, AZ - As Available 2011-2012 100 16 Hyder II Hyder, AZ - As Available 2013 100 14 Paloma Gila Bend, AZ - As Available 2011 100 17 Cotton Center Gila Bend, AZ - As Available 2011 100 17 Chino Valley Chino Valley, AZ - As Available 2012 100 19 Yuma Foothills Yuma, AZ - As Available 2013 100 35 Distributed Energy Multiple AZ Facilities - As Available Various 100 15 Gila Bend Gila Bend, AZ - As Available 2015 100 32 Various Multiple AZ Facilities - As Available 1996-2006 100 4 Total Generation Capacity 6,426 MW 1 Includes leased generation plants * As disclosed in 2014 Form 10-K

Powering Growth, Delivering Value46 PURCHASED POWER CONTRACTS* Fuel/Contract Location Owner/Developer Status1 PPA Signed COD Term (Years) Net Capacity (MW) SOLAR 310 MW Solana Gila Bend, AZ Abengoa IO Feb-2008 2013 30 250 RE Ajo Ajo, AZ Duke Energy Gen Svcs IO Jan-2010 2011 25 5 Sun E AZ 1 Prescott, AZ SunEdison IO Feb-2010 2011 30 10 Saddle Mountain Tonopah, AZ SunEdison IO Jan - 2011 2012 30 15 Badger Tonopah, AZ PSEG IO Jan-2012 2013 30 15 Gillespie Maricopa County, AZ Recurrent Energy IO Jan-2012 2013 30 15 WIND 289 MW Aragonne Mesa Santa Rosa, NM Ingifen Asset Mgmt IO Dec-2005 2006 20 90 High Lonesome Mountainair, NM Foresight / EME IO Feb-2008 2009 30 100 Perrin Ranch Wind Williams, AZ NextEra Energy IO Jul-2010 2012 25 99 GEOTHERMAL 10 MW Salton Sea Imperial County, CA Cal Energy IO Jan-2006 2006 23 10 BIOMASS 14 MW Snowflake Snowflake, AZ Novo Power IO Sep-2005 2008 15 14 BIOGAS 6 MW Glendale Landfill Glendale, AZ Glendale Energy LLC IO Jul-2008 2010 20 3 NW Regional Landfill Surprise, AZ Waste Management IO Dec-2010 2012 20 3 INTER-UTILITY 540 MW PacifiCorp Seasonal Power Exchange - PacifiCorp IO Sep-1990 1991 30 480 Not Disclosed Not Disclosed Not Disclosed IO May-2009 2010 10 60 HEAT RATE OPTIONS 650 MW Call Option - Not Disclosed IO Nov-2005 2007 8-9 500 Call Option - Not Disclosed IO Oct-2005 2007 10 150 CONVENTIONAL TOLLING 1,074 MW CC Tolling Not Disclosed Not Disclosed IO Mar-2006 2007 10 514 CC Tolling Not Disclosed Not Disclosed IO Aug-2007 2010 10 560 DEMAND RESPONSE 25 MW Demand Response Not Disclosed Not Disclosed IO Sep-2008 2010 15 25 Total Contracted Capacity 2,918 MW 1 UD = Under Development; UC = Under Construction; IO = In Operation * As disclosed in 2014 Form 10-K

Powering Growth, Delivering Value47 INVESTOR RELATIONS CONTACTS Paul J. Mountain, CFA Director, Investor Relations Telephone: (602) 250-4952 E-mail: paul.mountain@pinnaclewest.com Chalese Haraldsen Telephone: (602) 250-5643 E-mail: chalese.haraldsen@pinnaclewest.com Pinnacle West Capital Corporation P.O. Box 53999, Mail Station 9998 Phoenix, Arizona 85072-3999 Fax: (602) 250-2601 Visit us online at: www.pinnaclewest.com