Exhibit 99.3
| 2nd Quarter 2009 Results August 4, 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); the potential shortfall in insurance coverage for a loss resulting from an insurer failing to meet, or being unwilling to meet, its obligations under our insurance policies, or from our commercially reasonable levels of insurance failing to fully cover the loss incurred; 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. |
| CFO Agenda 2nd Quarter Results Earnings Guidance Liquidity |
| Consolidated EPS Summary 2nd Quarter 2009 vs. 2nd Quarter 2008 Per Share EPS 2009 2008 Reported 0.68 1.33 Reported Per Share On-Going EPS 2009 2008 On-Going 0.77 0.88 |
| Non-GAAP EPS Reconciliation 2nd Quarter 2009 vs. 2nd Quarter 2008 EPS per diluted share as reported: $ 0.68 $ 1.33 $ (0.65) Adjustments: Real estate segment 0.09 (0.15) 0.24 Income tax credits related to prior years - (0.30) 0.30 On-going earnings per share $ 0.77 $ 0.88 $ (0.11) 2nd Qtr 2009 Change 2nd Qtr 2008 |
| 2nd Quarter 2008 Misc. Items net Regulated gross margin weather infrastructure 2nd Quarter 2009 0.88 0.88 0.92 0.84 0.77 0.77000000013148 0.04 0.02 0.1 0.07 2nd Qtr. 2008 2nd Qtr. 2009 Regulated electricity gross margin O&M* Infrastructure- related costs Misc. items, net $0.88 $0.02 $(0.10) $(0.07) $0.04 $0.77 On-going earnings declined $0.11 per share. Summary of On-Going EPS Variances 2nd Quarter 2009 vs. 2nd Quarter 2008 *Excludes renewable energy and demand-side management revenue increases due to offsetting O&M increases. |
| Regulated Electricity Gross Margin Drivers* 2nd Quarter 2009 vs. 2nd Quarter 2008 Interim rates Transmission Rates weather customer usage MTM Other items, net 0.1 0.02 0.07 -0.08 -0.05 -0.04 Transmission rate increases Lower customer usage Weather effects Lower hedge mark-to-market Regulated electricity gross margin variances increased earnings $0.02 per share. Interim retail rate increase Other items, net *Excludes renewable energy and demand-side management revenue increases due to offsetting O&M increases. |
| 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 As of August 4, 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 |
| CEO Agenda Regulatory Update Operations Update SunCor Restructuring Status Looking Ahead |
| Appendix |
| Renewable Energy and Demand-Side Management Surcharges* Q1 2 Q2 2 Q3 4 Q4 3 Q1 2 Q2 7 Q3 9 Q4 7 Q1 18 Q2 23 * These surcharges have no earnings effect because they were offset by comparable amounts of O&M expense. 2007 2008 2009 Pretax $ Millions |
| Q1 7 Q2 -3 Q3 -1 Q4 3 Q1 14 Q2 14 Q3 -29 Q4 -9 Q1 -5 Q2 5 2007 2008 2009 Quarterly Mark-to-Market on Hedge Contracts* Pretax $ Millions * APS 10% share under Power Supply Adjustor (PSA), net of related deferrals. |
| Reconciliation of Regulated Electricity Segment Gross Margin Operating income - closest GAAP measure $ 157 $ 176 Plus: Operations and maintenance expense 226 194 Real estate segment operations expense 24 30 Real estate impairment charge 1 - Depreciation and amortization 100 98 Taxes other than income taxes 33 33 Other expenses 8 7 Marketing and trading fuel and purchased power - 19 Less: Real estate segment revenues 17 23 Other revenues 11 9 Marketing and trading revenues - 23 Regulated electricity segment gross margin - pretax $ 521 $ 502 Less: Renewable energy surcharge (RES) - pretax 23 7 Regulated electricity segment gross margin excluding RES - pretax $ 498 $ 495 Three Months Ended June 30, Increase (Decrease) 2009 2008 $ Millions, except per share amounts Earnings per share - diluted (after-tax) Regulated electricity segment gross margin $ 3.13 $ 3.01 $ 0.12 Less: RES 0.14 0.04 0.10 Regulated electricity segment gross margin excluding RES $ 2.99 $ 2.97 $ 0.02 Non-GAAP Measure Reconciliation - Operating Income (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 13 reconciles this non- GAAP financial measure to operating income, 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 (GAAP Measure) To Regulated Electricity Segment Gross Margin (Non-GAAP Measure) |
| Retail Rate and Financial Stability Plan Proposed Settlement Primary Benefits Strengthens APS' financial condition and supports common dividend Provides greater level of cost recovery and return on investment Demonstrates cooperation among APS, ACC Staff and other intervenors Allows opportunity to help shape Arizona's energy future outside continual rate cases |
| Base Retail Rates - Annualized revenue increases ($ millions): Non-fuel $ 196 Net fuel-related 11 Net increase $ 207 Allowed ROE (%) 11 Equity ratio (%) 54 Rate base ($ billions) $5.6 Base fuel rate (¢ per kWh) 3.76 Effective date 1/1/2010 Line Extension Fees - 2010-2012 payments received to be recorded as revenues instead of contributions in aid of construction (CIAC) (pretax estimates): 2010 $23 million 2011 $25 million 2012 $49 million Proposed Settlement Retail Rate and Financial Stability Plan Proposed Settlement |
| Retail Rate and Financial Stability Plan Proposed Settlement Key Financial Provisions - Other Than Base Rates 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 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) |
| Retail Rate and Financial Stability Plan Proposed Settlement Key Financial Provisions - Other Than Base Rates Palo Verde License Extension Extension of operating licenses to 60 years from 40 years requested December 2008 Process expected to take about two years Effective later of NRC approval, or January 1, 2012: Adjust Palo Verde depreciation rates to reflect life extension Estimated pretax annual depreciation decrease $34 million Reduce retail revenues to reflect any reduction of decommissioning trust funding obligations or spent fuel storage costs related to extension Rate adjustment will be earnings neutral to APS Equity Infusions APS to obtain at least $700 million of equity infusions in 2010 through 2014 (continued) |
| Retail Rate and Financial Stability Plan Proposed Settlement Future rate case process APS to file general base rate cases on or after June 1, 2011 and June 1, 2013 Base rate increase from APS' next rate case to be effective on or after July 1, 2012 Settling parties intend to process future cases within 12 months of sufficiency findings Other key provisions Provides rate stability for APS customers Provides for significant increase in energy efficiency programs Expands renewable energy requirements and programs Future General Base Rate Cases |
| Retail Rate and Financial Stability Plan Proposed Settlement Proposed Procedural Schedule Term sheet filed May 4, 2009 Definitive settlement agreement filed June 12, 2009 Supporting parties' testimony filed July 1, 2009 Opposing parties' testimony filed July 22, 2009 Supporting parties' reply testimony due August 6, 2009 Hearing begins August 19, 2009 Rate increase effective January 1, 2010 |