Exhibit 99.3

1st Quarter 2009 Results May 5, 2009

Forward-Looking Statements This presentation contains forward-looking statements based on current expectations, and neither Pinnacle West nor APS assumes any obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as "estimate," "predict," "hope," "may," "believe," "anticipate," "plan," "expect," "require," "intend," "assume" and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A of the 2008 Form 10-K, these factors include, but are not limited to: state and federal regulatory and legislative decisions and actions, including the outcome or timing of the pending rate case of APS; increases in our capital expenditures and operating costs and our ability to achieve timely and adequate rate recovery of these increased costs; our ability to reduce capital expenditures and other costs while maintaining reliability and customer service levels, and unexpected developments that would limit us from achieving all or some of our planned capital expenditure reductions; volatile fuel and purchased power costs, including fluctuations in market prices for natural gas, coal, uranium and other fuels used in our generating facilities, availability of supplies of such commodities, and our ability to recover the costs of such commodities; the outcome and resulting costs of regulatory, legislative and judicial proceedings, both current and future, including those related to environmental matters and climate change; the availability of sufficient water supplies to operate our generation facilities, including as the result of drought conditions; the potential for additional restructuring of the electric industry, including decisions impacting wholesale competition and the introduction of retail electric competition in Arizona; regional, national and international economic and market conditions, including the strength of the real estate, credit and financial markets; the potential adverse impact of current economic conditions on our results of operations; the cost of debt and equity capital and access to capital markets; changes in the market price of our common stock; restrictions on dividends or other burdensome provisions in new or existing credit agreements; our ability, or the ability of our subsidiaries, to meet debt service obligations; current credit ratings remaining in effect for any given period of time; the performance of the stock market and the changing interest rate environment, which affect the value of our nuclear decommissioning trust, pension, and other postretirement benefit plan assets, the amount of required contributions to Pinnacle West's pension plan and contributions to APS' nuclear decommissioning trust funds, as well as the reported costs of providing pension and other postretirement benefits and our ability to recover such costs; volatile market liquidity, any deteriorating counterparty credit and the use of derivative contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts); changes in accounting principles generally accepted in the United States of America, the interpretation of those principles and the impact of the adoption of new accounting standards; customer growth and energy usage; weather variations affecting local and regional customer energy usage; power plant performance and outages; transmission outages and constraints; the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies; risks inherent in the operation of nuclear facilities, such as environmental, regulatory, health and financial risks, risk of terrorist attack, planned and unplanned outages, and unfunded decommissioning costs; the ability of our power plant participants to meet contractual or other obligations; technological developments in the electric industry; the results of litigation and other proceedings resulting from the California and Pacific Northwest energy situations; the performance of Pinnacle West's subsidiaries and any resulting effects on its cash flow; the strength of the real estate and credit markets and economic and other conditions affecting the real estate and credit markets in SunCor's market areas, which include Arizona, Idaho, New Mexico and Utah; and other uncertainties, all of which are difficult to predict and many of which are beyond the control of Pinnacle West and APS.

CEO Agenda APS Retail Rate Settlement SunCor Restructuring Plan Palo Verde Return to NRC Column 1 Summary Comments

Proposed APS Retail Rate Settlement Rate and Financial Stability Plan Primary Benefits Strengthens APS' financial condition and supports common dividend Provides greater level of cost recovery and return on investment Provides rate stability for APS customers Allows opportunity to help shape Arizona's energy future outside continual rate cases Continues strong APS commitment to cost control and efficiency Provides for significant increase in energy efficiency programs Expands renewable energy requirements and programs

Proposed APS Retail Rate Settlement Rate and Financial Stability Plan Annualized base rate revenue increase ($ millions): Non-fuel rate increase $ 196 $ 264 Net fuel-related rate increase 11 14 Net base rate increase $ 207 $ 278 Allowed ROE (%) 11 11.5 Base fuel rate (¢ per kWh) 3.76 3.88 Effective date 1/1/2010 10/1/2009 Proposed Settlement APS Request Key Financial Provisions - Base Rates

Proposed APS Retail Rate Settlement Rate and Financial Stability Plan Key Financial Provisions - Other Than Base Rates Line Extension Fees - 2010-2012 payments received to be recorded as revenues instead of contributions in aid of construction (pretax estimates): 2010 $23 million 2011 $25 million 2012 $49 million Pension and OPEB Deferrals - 2011-2012 defer for future rate recovery differences between actual pension and OPEB costs and 2007 test year ($24 million) as follows (pretax): 2011 deferral not to exceed lower of $13.5 million or 50% of cost above 2007 level 2012 deferral not to exceed $29 million (continued)

Proposed APS Retail Rate Settlement Rate and Financial Stability Plan Key Financial Provisions - Other Than Base Rates (continued) Expense Reduction Commitment Beginning in 2010, identify additional $10 million pretax expense reductions above $20 million identified March 2009 $30 million average annual expense reductions to continue through 2014 Equity Infusions APS to obtain at least $700 million of equity infusions in 2010 through 2014 (continued)

Proposed APS Retail Rate Settlement Rate and Financial Stability Plan APS may file general base rate cases on or after June 1, 2011 and June 1, 2013 A base rate increase resulting from APS' next rate case may not become effective before July 1, 2012 Settling parties intend to process future cases within 12 months of sufficiency findings Future General Base Rate Cases

Proposed APS Retail Rate Settlement Rate and Financial Stability Plan Proposed Procedural Schedule Definitive settlement agreement filing June 12, 2009 Supporting parties' testimony due July 1, 2009 Opposing parties' testimony due July 22, 2009 Supporting parties' reply testimony due August 6, 2009 Hearing begins August 17, 2009 Rate increase effective January 1, 2010

CEO Agenda APS Retail Rate Settlement SunCor Restructuring Plan Palo Verde Return to NRC Column 1

CFO Agenda 1st Quarter Results Impacts of SunCor Restructuring Plan Earnings Guidance Liquidity Dividends

Consolidated EPS Summary 1st Quarter 2009 vs. 1st Quarter 2008 Per Share EPS 2009 2008 Reported -1.55 -0.04 Reported Per Share On-Going EPS 2009 2008 On-Going -0.29 -0.04 On-going loss of $(0.29) per share in 1st quarter 2009 compared with $(0.04) per share in 1st quarter 2008.

Non-GAAP EPS Reconciliation 1st Quarter 2009 vs. 1st Quarter 2008 EPS per diluted share as reported: $ (1.55) $ (0.04) $ (1.51) Adjustments: Real estate impairment charge 1.22 - 1.22 Real estate severance and other costs 0.04 - 0.04 On-going earnings per share $ (0.29) $ (0.04) $ (0.25) 1st Qtr 2009 Change 1st Qtr 2008

Reg. Gross margin M&T O&M Infrastructure El Dorado Other Expenses primarily related to capital expenditures $(0.25) Summary of On-Going EPS Variances 1st Quarter 2009 vs. 1st Quarter 2008 Marketing and trading contributions O&M expense Miscellaneous items, net Regulated electricity gross margin Other expense, net of other income, including investment losses

Regulated Electricity Gross Margin Drivers* 1st Quarter 2009 vs. 1st Quarter 2008 Interim rates Transmission Rates MTM weather customer usage Other items, net 0.08 0.04 -0.12 -0.08 -0.02 0.01 Transmission rate increases Lower customer usage Milder weather Lower hedge mark-to-market Regulated electricity gross margin variances decreased earnings $0.09 per share. Interim retail rate increase Other items, net *Excluding effects of Renewable Energy Standard (RES) of $0.10 per share, which is offset by a comparable amount in O&M.

Milder Weather Impacts Quarterly Comparison '74 791 571 '75 1066 571 '76 721 571 '77 776 571 '78 657 571 '79 1037 571 '80 695 571 '81 534 571 '82 756 571 '83 744 571 '84 535 571 '85 814 571 '86 468 571 '87 734 571 '88 620 571 '89 629 571 '90 761 571 '91 601 571 '92 553 571 '93 593 571 '94 617 571 '95 469 571 '96 468 571 '97 541 571 '98 710 571 '99 459 571 '00 459 571 '01 657 571 '02 484 571 '03 349 571 '04 552 571 '05 457 571 '06 464 571 '07 589 571 '08 583 571 '09 383 571 1st Qtr Heating Degree Days (HDDs) 1st quarter 2009 was second mildest on record with 383 HDDs compared with a normal level of 571 HDDs. 10-Year Weather Normal HDDs 571

Regulated Electricity Gross Margin Drivers* 1st Quarter 2009 vs. 1st Quarter 2008 Interim rates Transmission Rates MTM weather customer usage Other items, net 0.08 0.04 -0.12 -0.08 -0.02 0.01 Transmission rate increases Lower customer usage Milder weather Lower hedge mark-to-market Regulated electricity gross margin variances decreased earnings $0.09 per share. Interim retail rate increase Other items, net *Excluding effects of Renewable Energy Standard (RES) of $0.10 per share, which is offset by a comparable amount in O&M.

Financial Impacts of SunCor Restructuring 1st quarter 2009 real estate impairment, severance and related costs $1.26 per share Eliminate SunCor's debt Produce $80 million of cash tax benefits (estimated to be received late 2010) Reduce pretax G&A burn from $44 million in 2008 to negligible amount after restructuring Eliminate future real estate earnings volatility

Guidance Estimates* 2009 2010 APS $ 2.35 $ 3.00 Parent and all other, net (0.05) - Estimated EPS $ 2.30 $ 3.00 Key Assumptions 2009 Full-year interim base rates No additional base rate increases Includes identified cost savings and mild weather impacts 2010 Rate settlement effective entire year Includes identified cost savings 2009 - 2010 Earnings Guidance Affirmed As of May 5, 2009 * Within a reasonable range around specified amount Excluding any SunCor impact Majority of SunCor's operations will be reclassified to discontinued operations during 2009

Adequate Liquidity Resources Capacity Borrower ($ Millions) Matures PNW $ 283 Dec. '10 APS 377 Dec. '10 APS 489 Sep. '11 $1,149 We have sufficient liquidity and access to credit. Credit Facilities Cash Short Term Debt Available Liquidity $760 Available Liquidity March 31, 2009 $ Millions Credit Facilities

Pinnacle West vs. Industry Dividend Yield PNW Electric Industry Average 4/29/2009 0.0765 0.0569 3/31/2009 0.0791 0.0575 2/28/2009 0.08 0.059 1/31/2009 0.0627 0.0507 12/31/2008 0.0654 0.0497 11/30/2008 0.0691 0.0487 10/31/2008 0.0664 0.0495 9/30/2008 0.061 0.0439 8/30/2008 0.0597 0.0409 7/30/2008 0.0626 0.042 6/30/2008 0.0682 0.0414 5/31/2008 0.0622 0.0393 4/30/2008 0.0619 0.0408 3/31/2008 0.0599 0.0426 Mar. 31, 2008 Jun. 30, 2008 Sep. 30, 2008 Dec. 31, 2008 7.7% 5.7% Apr. 30, 2009 Pinnacle West's annual dividend is $2.10 per share.

Going Forward Intense focus on operational excellence and improving earnings and financial metrics Positive movement in Arizona regulatory environment demonstrated by proposed settlement SunCor restructuring plan optimizes assets and financial results Current common dividend supported

Appendix

Comparison of Retail Rate Case Positions Rate base ($ billions) $ 5.4 $ 5.3 $ 4.9 $ 5.4 Common equity 54% Return on common equity 11.5% 11.0% 9.6% 11.5% APS Request ACC Staff RUCO Annual revenue increases ($ millions): Non-fuel rate increase $ 264 $ 155 $ (14) $ 206 Net fuel-related rate increase 14 11 14 10 Net rate increase $ 278 $ 166 $ - $ 216 AECC

Costs Related to SunCor Restructuring 1st Quarter 2009 Real estate impairment charges: Homebuilding and master-planned communities $ 141 Land parcels and commercial assets 53 Golf courses 17 Subtotal in continuing operations 211 Discontinued operations 5 Less non-controlling interests (14) Total impairment charges 202 $ 1.22 Severance and other costs 8 0.04 Total costs related to restructuring $ 210 $ 1.26 $ Millions Pretax EPS After Tax

Reconciliation of Regulated Electricity Segment Gross Margin Operating income (loss) - closest GAAP measure $ (208) $ 36 Plus: Operations and maintenance expense 208 193 Real estate segment operations expense 30 31 Real estate impairment charge 211 - Depreciation and amortization 100 96 Taxes other than income taxes 34 33 Other expenses 6 6 Marketing and trading fuel and purchased power - 24 Less: Real estate segment revenues 18 26 Other revenues 8 9 Marketing and trading revenues - 30 Regulated electricity segment gross margin - pretax $ 355 $ 354 Less: Renewable energy surcharge (RES) - pretax 18 2 Regulated electricity segment gross margin excluding RES - pretax $ 337 $ 352 Three Months Ended March 31, Increase (Decrease) 2009 2008 $ Millions, except per share amounts Earnings per share - diluted (after-tax) Regulated electricity segment gross margin $ 2.14 $ 2.13 $ 0.01 Less: RES 0.11 0.01 0.10 Regulated electricity segment gross margin excluding RES $ 2.03 $ 2.12 $ (0.09) Non-GAAP Measure Reconciliation - Operating Income (Loss) (GAAP Measure) To Regulated Electricity Segment Gross Margin (Non-GAAP Measure)

In this presentation, we present "regulated electricity gross margin" per diluted share of common stock. Regulated electricity gross margin refers to regulated electricity segment revenues less regulated electricity segment fuel and purchased power expenses. Regulated electricity segment gross margin is a "non-GAAP financial measure," as defined in accordance with SEC rules. Slide 26 reconciles this non- GAAP financial measure to operating income (loss), which is the most directly comparable financial measure calculated and presented in accordance with GAAP. We view regulated electricity segment gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is 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. Non-GAAP Measure Reconciliation - Operating Income (Loss) (GAAP Measure) To Regulated Electricity Segment Gross Margin (Non-GAAP Measure)