8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): November 7, 2008

	Exact Name of Registrant as Specified in
	Charter; State of Incorporation;	IRS Employer
Commission File Number	Address and Telephone Number	Identification Number
1-8962	Pinnacle West Capital Corporation	86-0512431
	(an Arizona corporation)
	400 North Fifth Street, P.O. Box 53999
	Phoenix, AZ 85072-3999
	(602) 250-1000
1-4473	Arizona Public Service Company	86-0011170
	(an Arizona corporation)
	400 North Fifth Street, P.O. Box 53999
	Phoenix, AZ 85072-3999
	(602) 250-1000

     Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

     This combined Form 8-K is separately filed by Pinnacle West Capital Corporation and Arizona Public Service Company. Each registrant is filing on its own behalf all of the information contained in this Form 8-K that relates to such registrant and, where required, its subsidiaries. Except as stated in the preceding sentence, neither registrant is filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

TABLE OF CONTENTS

EX-99.1

EX-99.2

EX-99.3

EX-99.4

Item 7.01 Regulation FD Disclosure

Investor and Analyst Meeting

     Pinnacle West Capital Corporation (“Pinnacle West” or the “Company”) is making a presentation to investors and analysts in Scottsdale, Arizona on November 7, 2008. Copies of the slides to be presented are attached hereto as Exhibits 99.1, 99.2, 99.3 and 99.4.

Forward-Looking Statements

     The presentations attached as Exhibits 99.1, 99.2, 99.3 and 99.4 contain forward-looking statements based on current expectations. Neither Pinnacle West nor Arizona Public Service Company (“APS”) assumes any obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. 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 Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2007, these factors include, but are not limited to, state and federal regulatory and legislative decisions and actions, including the outcome or timing of any pending APS rate cases; 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, and availability of supplies of such commodities; the outcome of regulatory, legislative and judicial proceedings, both current and future, including those related to environmental matters and climate change; 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 housing, 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; entering into credit agreements that restrict dividends or contain other burdensome provisions; our ability 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 trusts, 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; 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 and the interpretation of those principles; 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; 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 our subsidiaries and any resulting effects on our cash flows; the strength of the real estate market and

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economic and other conditions affecting the real estate market in SunCor Development Company’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.

Item 9.01 Financial Statements and Exhibits

     (d) Exhibits

Exhibit
No.	Registrant(s)	Description
99.1	Pinnacle West APS	Pinnacle West slide presentation by Donald E. Brandt to investors and analysts in Scottsdale, Arizona on November 7, 2008.
99.2	Pinnacle West APS	Pinnacle West slide presentation by Randall K. Edington to investors and analysts in Scottsdale, Arizona on November 7, 2008.
99.3	Pinnacle West APS	Pinnacle West slide presentation by Steven M. Wheeler to investors and analysts in Scottsdale, Arizona on November 7, 2008.
99.4	Pinnacle West APS	Pinnacle West slide presentation by James R. Hatfield to investors and analysts in Scottsdale, Arizona on November 7, 2008.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	PINNACLE WEST CAPITAL CORPORATION (Registrant)
Dated: November 7, 2008	By:	/s/ James R. Hatfield
		James R. Hatfield
		Senior Vice President and Chief Financial Officer
	ARIZONA PUBLIC SERVICE COMPANY (Registrant)
Dated: November 7, 2008	By:	/s/ James R. Hatfield
		James R. Hatfield
		Senior Vice President and Chief Financial Officer

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EX-99.1

Exhibit 99.1

Operations Overview Don Brandt Analyst Conference November 7, 2008

Manage intrinsic growth in our markets Prudently increase our resource portfolio Maintain top-quartile operational performance and reliability Achieve constructive regulatory outcomes Manage costs aggressively Improve financial strength and shareholder value Strategic Objectives

Today's Agenda Four-part plan to improve APS' financial strength Growth update Resource planning and management Operations overview Fossil generation Customer service EEI Award and other recognition SunCor

Plan to Improve APS' Financial Strength Cost reductions announced January 2008 $200 million capital expenditures 2008 - 2012 $14 million annual O&M Additional $700 million capital expenditure reductions 2009 - 2011 announced October 2008 Interim rate request General retail rate case

Growth and Resource Management

Attractive Intrinsic Growth Characteristics Population Growth - Arizona vs. U.S. APS Customer Growth Arizona Population Growth U.S Population Growth '87 0.044 0.051 0.009 '88 0.032 0.023 0.009 '89 0.025 0.022 0.009 '90 0.021 0.018 0.011 '91 0.021 0.03 0.013 '92 0.025 0.032 0.014 '93 0.028 0.032 0.013 '94 0.036 0.035 0.012 '95 0.039 0.033 0.012 '96 0.041 0.037 0.012 '97 0.042 0.038 0.012 '98 0.04 0.037 0.012 '99 0.042 0.039 0.012 '00 0.041 0.034 0.011 '01 0.037 0.026 0.01 '02 0.031 0.027 0.01 '03 0.033 0.025 0.009 '04 0.037 0.03 0.009 '05 0.043 0.036 0.009 '06 0.044 0.036 0.01 '07 0.033 0.028 0.01 '08 0.016 0.015 0.009 Projected

Arizona Population Growth APS Customer Growth APS Retail Sales Growth* '87 0.051 0.044 0.045 '88 0.023 0.032 0.046 '89 0.022 0.025 0.053 '90 0.018 0.021 0.033 '91 0.03 0.021 0.034 '92 0.032 0.025 0.015 '93 0.032 0.028 0.039 '94 0.035 0.036 0.035 '95 0.033 0.039 0.042 '96 0.037 0.041 0.048 '97 0.038 0.042 0.036 '98 0.037 0.04 0.05 '99 0.039 0.042 0.03 '00 0.034 0.041 0.048 '01 0.026 0.037 0.013 '02 0.027 0.031 0.034 '03 0.025 0.033 0.038 '04 0.03 0.037 0.052 '05 0.036 0.043 0.038 '06 0.036 0.044 0.053 '07 0.028 0.033 0.021 '08 0.015 0.016 0.012 Population Growth Underpins APS Business Growth * Weather-normalized Projected

Arizona Population Growth APS Customer Growth APS Retail Sales Growth* '87 0.051 0.044 0.045 '88 0.023 0.032 0.046 '89 0.022 0.025 0.053 '90 0.018 0.021 0.033 '91 0.03 0.021 0.034 '92 0.032 0.025 0.015 '93 0.032 0.028 0.039 '94 0.035 0.036 0.035 '95 0.033 0.039 0.042 '96 0.037 0.041 0.048 '97 0.038 0.042 0.036 '98 0.037 0.04 0.05 '99 0.039 0.042 0.03 '00 0.034 0.041 0.048 '01 0.026 0.037 0.013 '02 0.027 0.031 0.034 '03 0.025 0.033 0.038 '04 0.03 0.037 0.052 '05 0.036 0.043 0.038 '06 0.036 0.044 0.053 '07 0.028 0.033 0.021 '08 0.015 0.016 0.012 APS Growth Historically Rebounds After Recessions * Weather-normalized Projected

APS Resource Management Initiatives Maintaining diversified energy mix Balancing needs and resources Addressing renewables, energy efficiency and climate change Hedging purchased power and gas prices

Diversified Energy Fuel Mix Energy Fuel Mix Nuclear 8057939 0.25 Coal 12685068 0.39 Gas 6194661 0.19 Purchased Power 5303197 0.17 Total 32240865 1 Native Load Twelve months ended September 30, 2008

2008 2009 2010 2011 Status 9/30/08 0.85 0.809 0.547 0.373 Targets (not on chart) 0.85 0.85 0.55 0.35 As of September 30, 2008 Purchased Power and Gas Hedging Program Percent of Requirements Hedged

'07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19 '20 Native Load Peak & Reserves 8100 8180 8246 8286 8370 8496 8600 8903 9237 9584 9933 10266 10592 10906 Long-Term Resources 7929 8470 8640 8795 8520 8790 8786 8786 8786 8286 7785 7785 7785 7225 MW Meeting Challenges of Peak Load Growth 2007 - 2020 Average Annual Load Growth 2.3% Projected

Arizona Renewable Energy Standard (RES) Sets minimum renewable energy amounts 1.5% of energy for retail sales in 2007 5% of energy for retail sales by 2015 15% of energy for retail sales by 2025 Includes distributed energy component 5% of total in 2007 30% of total by 2012 Arizona Renewable Resource Requirements

APS Major New Solar Resource Solana Generating Station 280 MW concentrating solar plant 70 miles southwest of Phoenix Larger than any existing solar facility in the world APS 30-year purchase power agreement for all output (900 GWh/year) Thermal storage capability will allow summer on-peak capacity factor over 90% To be built, owned and operated by Abengoa Solar Planned to be operational in late 2011

APS participation approved by ACC September 2008 Status of Certificate of Environmental Compatibility (CEC) Siting committee approval October 2008 ACC ruling expected December 2008 Renewables tax credit extension approved by Congress September 2008 Solana Generating Station Recent Milestones

Stakeholders actively involved Resource needs and options evaluated Peaking capacity through next decade Baseload capacity thereafter APS resource plan to be filed with ACC year-end 2008 ACC integrated resource planning rules being developed Resource Planning for the Future

Operational Excellence

Top-Tier Coal Generation Performance '03 '04 '05 '06 '07 APS Capacity Factors 0.75800000013148 0.842 0.871 0.869 0.875 0.856 Industry Average 0.685 0.706 0.719 0.736 Capacity Factors APS Industry Average 2007 Highlights Record fleet capacity factors for fourth straight year Cholla Set new production record 5.1 million MWh Capacity factor 90% Four Corners Capacity factor 86% 14.6 million MWh generated 12 Months Ended Sept '08

Fossil Generation Environmental Targets Fossil Generation Environmental Targets Zero non-air related reportable environmental incidents Self assessments at each plant annually Environmental Management Systems (EMIS) to promote compliance at all levels

Company Score Portland General Electric 670 Arizona Public Service 652 Pacific Gas and Electric 633 Southern California Edison 631 Pacific Power 631 Rocky Mountain Power 626 San Diego Gas & Electric 622 Xcel Energy-West 606 Nevada Power 595 Puget Sound Energy 589 Industry Average 626 Company Score Pacific Gas and Electric 721 Portland General Electric 717 Southern California Edison 701 Arizona Public Service 700 PNM Resources 695 Puget Sound Energy 682 PacifiCorp 681 Sierra Pacific Resources 679 Xcel Energy-West 672 San Diego Gas & Electric 662 Industry Average 693 APS Customer Satisfaction High Among Western Electric IOU's APS APS Rating Rating Residential Customers Commercial Customers J.D. Power 2008 Surveys

Top-Quartile Reliability Reducing Average Customer Outage Time 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Actuals 105 96 104 115 79 98 81 97 93 89 Trend Line Actuals Trend Line Minutes Average annual outage time per customer System Average Interruption Duration Index (SAIDI) Top-Quartile Performance

Labor Day Storm Response Exemplified Excellence August 28 - Thursday 10:00 p.m.- First Storm - 80,000 customers out August 29 - Friday 6:30 a.m. - 32,000 out 8:00 p.m. - 3,400 out 11:00 p.m.- Second Storm - 9,000 more off August 30 - Saturday 7:30 a.m. - 4,000 out 9:00 p.m. - 1,500 out August 31 - Sunday Customers out reduced to 400 September 1 - Monday All restored by 3:00 p.m. Timeline

Labor Day Storm Response Statistics 51 distribution feeders - 80,000 customers impacted Call Center handled 47,609 customer calls on August 29 (single-day record) Over 2,600 trouble orders Vegetation management crews cleared lines at 250 locations 147 poles and over 100 transformers replaced 500 employees and 200+ contractors involved in restoration efforts

APS Receives Electric Industry's Most Prestigious Honor "APS' new system for monitoring transformer performance is a remarkable achievement and could potentially benefit electric utilities everywhere.... This system represents a significant step forward in managing and monitoring the electric grid." Thomas Kuhn Edison Electric Institute President June 2008

Other Recognition Environmental, Sustainability and Technology Innovest's highest rating (AAA) and ranked #2 electric utility Dow Jones Sustainability Index Global 100 Most Sustainable Corporations in World by Corporate Knights Storebrand's Social Responsibility Index "best in class" distinction EPA Climate Protection Award SEPA Top 10 Utility Solar Ranking Top 10 in U.S. in Technology Innovation and #1 utility

SunCor

SunCor Overview IDAHO UTAH NEW MEXICO ARIZONA Boise St. George Santa Fe Sedona Prescott Phoenix As of September 30, 2008 Commercial and residential real estate developer in Western U.S. Total assets = $578 million Equity = $297 million Diverse geographic and business mix 6 master-planned communities 2 major commercial projects

SunCor Near-Term Tactics Manage land, residential and commercial inventory Reduce costs / improve efficiency Workforce reduced 50% from peak Capital expenditure reduction/delay General and administrative expenses being reduced more than 20% from peak

Strategic Summary Manage intrinsic growth in our markets Prudently increase our resource portfolio Maintain top-quartile operational performance and reliability Achieve constructive regulatory outcomes Manage costs aggressively Improve financial strength and shareholder value

EX-99.2

Exhibit 99.2

Palo Verde Overview Randy Edington Analyst Conference November 7, 2008

We SAFELY and efficiently generate electricity for the long term Palo Verde's Business Plan

Improving Nuclear Generation Performance '03 '04 '05 '06 '07 APS Capacity Factors 0.874 0.837 0.774 0.707 0.79 0.894 Industry Average 0.852 0.885 0.873 0.885 Capacity Factors APS Industry Average 12 Months Ended Sept '08 Top U.S. power producer past 15 years Goal to achieve consistent site capacity factor greater than 88% Performance improvement plan underway Strengthening regulatory relationships

Net Generation 2003 2004 2005 2006 2007 2008 Net Generation 28.6 28.1 25.8 24 26.8 30 Million MW Projected

O&M Cost Trends 2003 2013 O&M Costs - APS Share 70.2 81 86.3 101.3 119.3 133.1 136.2 131.6 125.7 120.5 116.8 Expected to peak in 2008 - 2009

2003 2004 2005 2006 2007 2008 79.2 37.7 76.1 45.3 39 39 32.9 66.1 48.9 41.7 110.9 68.7 Total 112.1 103.8 125 87 149.9 107.7 Refueling and Steam Generator Replacement Outages Outage Days Projected Unit 1 Unit 2 Unit 3

Regulatory Activities Site Integrated Business Plan (SIBP) Site Integrated Improvement Plan (SIIP) Confirmatory Action Letter (CAL) Expected to be cleared by end of 2009 NRC Reactor Oversight Action Matrix Unit 3 expected to be out of Column 4 by end of 2009 License Renewal Request

License Renewal Plan to file application by end of 2008 Request to extend operating licenses by 20 years License extension process expected to take about two years

Major Capital Improvements Completed projects Steam generators Low-pressure turbines Future projects Reactor vessel heads Rapid refueling packages Cooling towers All projects in capital expenditure forecasts

Steam Generators and Low-Pressure Turbines Completed at all units in 2003 - 2007 Increased production capability 210 MW total site 61 MW APS share

Reactor Vessel Head Replacements Planned timing (during normal refueling outages): Unit 2 - Fall 2009 Unit 1 - Spring 2010 Unit 3 - Fall 2010 Estimated outage duration About 60 days/unit Projected site costs (all units) $90-100 million total project APS share 29.1% APS share 29.1% APS share 29.1% APS share 29.1% APS share 29.1% APS share 29.1% APS share 29.1% APS share 29.1% APS share 29.1% APS share 29.1% APS share 29.1% APS share 29.1%

Rapid Refueling Packages Planned timing Concurrent with reactor vessel head replacements Projected site costs (all units) $100-110 million total project APS share 29.1%

Cooling Tower Replacements Currently in design stage Projected completion: 2015 Preliminary site project cost estimate (all units) $400 million total project APS share 29.1%

The Road to Excellence - 2013 Goals Capacity factor greater than 88% Outages less than or equal to 30 days per unit Production cost less than or equal to $20 per megawatt-hour (2 cents per kWh) ISAR top quartile No NRC Findings greater than GREEN INPO 1

EX-99.3

Exhibit 99.3

Regulatory Overview Steve Wheeler Analyst Conference November 7, 2008

Today's Agenda Regulatory goals Significant developments in recent years Retail rate cases pending Interim base rate request General rate case Transmission rate settlement ACC election results Focusing on regulatory improvements

APS' Primary Regulatory Goals Timely cost recovery and return on investment Financial strength and stability APS integrated resource plan approval Improved regulatory processes Establishment of prudent, comprehensive state energy policy Support for beneficial customer programs

Significant Developments Since 2005 Unification of PWEC assets Retail cost recovery mechanisms Fuel and purchased power adjustor (PSA) Transmission cost adjustor (TCA) Renewables surcharge (RES) Demand-side management adjustor (DSM) Environmental improvement surcharge (EIS) Retail line extension fees FERC "formula" transmission rates

APS Interim Base Rate Request Details Application filed with ACC June 6, 2008 Base rate surcharge to be effective until general rate case decision $0.004 per kWh (approximately 4%) $115 million annual pretax retail revenues Subject to refund pending outcome of general rate case Hearings September 15-19, 2008 Requested effective date November 2008

Interim Rate Request Themes Address APS' financial condition pending general rate case proceedings Preserve investment-grade credit ratings Provide cash flow Strengthen credit metrics and earnings Protect customers against higher future costs Reduce rate volatility for customers Recognize cost management essential, but not enough Implement as part of broader four-part plan to restore APS' financial strength

Summary of Staff and Intervenor Positions on Interim Relief Request ACC Staff Does not support interim increase If Commission grants request $65 million annual revenue increase recommended No equity infusion pre-condition Residential Utility Consumer Office (RUCO) Does not support interim increase Arizonans for Electric Choice and Competition (AECC) Supports $42.4 million annual revenue increase effective January 1, 2009 Equal percentage increase Arizona Investment Council (AIC) Supports APS request Mesquite Group (merchant generators) Supports APS request

APS Retail Rate Case Elements Adjusted 2007 test year Recognize $1.7 billion of capital expenditures since last rate case Address earnings attrition Implement new growth impact fee Encourage energy efficiency programs New conservation rates

Composition of $278 Million APS Rate Increase Post-test year large projects 0.09 25 Post-test year CWIP 0.12 34 Attrition adjustment 0.29 79 Other items - net 0.02 6 Fuel-related increase 0.05 14 Cost of capital update 0.17 48 Traditional rate base 0.26 72 Traditional rate base Cost of capital Net fuel increase Other-net $72M $48M $14M $6M

Composition of $278 Million APS Rate Increase Post-test year large projects 0.09 25 Post-test year CWIP 0.12 34 Attrition adjustment 0.29 79 Other items - net 0.02 6 Fuel-related increase 0.05 14 Cost of capital update 0.17 48 Traditional rate base 0.26 72 Attrition adjustment Other post test-year plant in-service Post test-year large projects in-service $25M $34M $79M

Proposals to Mitigate Earnings Attrition Post test-year plant additions Consistent with ACC historic test-year methodology $174 million large projects in service by mid-2008 $245 million other plant in service by time rates go into effect $79 million attrition adjustment to capture revenue shortfall of projected 2010 cost levels Removal of disincentives to DSM programs

Growth Impact Fee Proposal Helps "growth pay for itself" Reduces increase for existing customers Supplements line extension payments approved in early 2008 Captures additional growth-related costs Carrying costs of tax asset related to line extension payments Incremental operating costs Net base rate increase $ 278 million 10.5 % Proposed growth impact fee (53) million (2.0)% Increase for existing customers $ 225 million 8.5 %

Staff & Intervenor Testimony Part 1 * Staff & Intervenor Testimony Part 2 ** APS Rebuttal Testimony Staff & Intervenor Surrebuttal Testimony APS Rejoinder Testimony Hearing Begins Apr. 2, 2009 Dec. 19, 2008 Jan. 9, 2009 Feb. 6, 2009 Mar. 6, 2009 Mar. 20, 2009 APS Retail Rate Case Schedule * All issues except rate design and cost of service ** Rate design and cost of service issues APS Initial Rate Filing Mar. 24, 2008 APS Updated Rate Filing Jun. 2, 2008

Timely Transmission Rate Updates Annual formula-based rate adjustments (based on prior-year FERC Form 1 data) Retail transmission cost adjustor Key implementation dates APS FERC request filing July 10, 2007 Initial increases (wholesale and retail adjustor) March 1, 2008 Second increase Wholesale June 1, 2008 Retail adjustor July 3, 2008 FERC settlement approval July 25, 2008 Next adjustment June 1, 2009

Transmission Revenue Increases 1st Increase 1st Increase 1st Increase 2nd Increase 2nd Increase Annual Revenue Annual Revenue Request Settlement Effective Date Annual Revenue Effective Date Retail Portion (TCA) $30M $27M 3/1/2008 $13M 7/3/2008 Wholesale Portion $ 7M $ 1M 3/1/2008 $ 2M 6/1/2008 Total Increase $37M $28M $15M

Arizona Corporation Commissioners Mike Gleason Republican Jeff Hatch-Miller Republican William Mundell Republican Kristin Mayes Republican Gary Pierce Republican Terms Expire January 2009 Terms Expire January 2011

Focusing on Regulatory Improvements Substantial APS capital expenditures driven by growth and reliability APS commodity prices increases Historic test year Significant regulatory lag Inadequate earnings Weak credit metrics No comprehensive state energy policy Partner with ACC and stakeholders to: Assure financial strength Address regulatory lag Improve alignment of goals Implement integrated resource planning Increase efficiency through new technology Enhance customer service Promote sustainable energy resources

EX-99.4

Exhibit 99.4

Financial Overview Jim Hatfield Analyst Conference November 7, 2008

Today's Agenda Financial objectives Third quarter earnings Capital expenditures Liquidity and debt profile O&M cost management initiatives Credit ratings and financial metrics Value proposition

Long-Term Financial Objectives Retain APS investment-grade credit ratings Improve financial strength and agility Emphasize capital and O&M budgeting disciplines Maintain ample liquidity and access to capital Constructively address earnings attrition Improve total return to above industry average

APS $ 160 $ 204 $ (44) SunCor (6) 6 (12) Other (2) (1) (1) Net income $ 152 $ 209 $ (57) Earnings per share $ 1.50 $ 2.07 $ (0.57) 2008 2007 Change 3rd Quarter September Earnings Summary $ Millions, Except EPS

2007 Rates Growth O&M MTM Weather SunCor Tax 2007 2.07 2.07 2.14 2.03 1.86 1.72 1.6 1.5 1.5 2008 0.07 0.06 0.17 0.17 0.14 0.12 0.1 2007 $2.07 Rate increases $0.07 Growth $0.06 O&M* $(0.17) SunCor $(0.12) Weather $(0.14) Hedge mark-to- market $(0.17) 2008 $1.50 3rd Quarter September 2008 vs 3rd Quarter September 2007 Major EPS Variances * Excludes $0.03 for regulatory-related programs offset in revenues 3Q07 prior- year tax benefits $(0.10)

Consolidated on-going earnings expected to be within reasonable range around $2.50 per share Excludes $0.30 per share of prior-year tax credits recorded second quarter 2008 APS will contribute substantially all of the earnings SunCor's contribution will be minimal 2008 Earnings Guidance As of November 4, 2008

Primary Future Earnings Drivers Customer growth Rate increases - Transmission - Interim - Base O&M Capital expenditures - Depreciation - Property taxes - Interest Inflation Economy Weather

($ Millions) 2005 2006 2007 2008 2009 2010 2011 APS Distribution 325 357 372 370 270 260 350 APS Transmission 92 113 138 180 260 100 180 APS Generation 356 176 353 370 330 310 340 Other 36 16 37 40 40 40 50 Total before deferrals & cancellations 809 662 900 960 1190 990 970 Deferrals & Cancellations 190 280 50 Total with deferrals & cancellations 809 662 900 960 900 710 920 $ Millions Projected APS Distribution APS Generation APS Transmission Significant APS Capital Expenditures to Support Long-Term Growth Other Deferrals & Cancellations Excluding SunCor

APS Capital Expenditure Reduction Details Announced October 2008 Transmission $ 60 $ 190 $ 180 $ 430 Distribution 100 80 30 210 Generation 60 60 (40) 80 Total 220 330 170 720 Line extension effects (30) (50) (120) (200) Net reductions $ 190 $ 280 $ 50 $ 520 2009 2010 2011 Total ($ Millions)

Slower customer growth 130 0.62 Improved planning, logistics & other 60 0.29 Deferral of upgrades & projects 20 0.09 Total 210 1 Continued customer growth slowing 0.8 Deferral of upgrades & projects 0.2 APS Capital Expenditure Reductions Announced January 2008 More than $200 million in 2008 - 2012 Announced October 2008 More than $700 million in 2009 - 2011

Ample Liquidity Resources Revolving Credit Facilities Short-term Borrowings As of September 30, 2008 PNW (parent) $300 million revolver expires December 2010 APS $400 million revolver expires December 2010 APS $500 million revolver expires September 2011 $51 million capacity loss from Lehman commitments No MAC clauses or "clean down" provisions $1.15 Billion $442 Million Cash & Investments $105 Million

Solid Revolver Bank Groups ($ Millions) APS PNW Total % of Total BNY Mellon $ 80 $ 30 $ 110 9.2 Bank of America 93 17 110 9.2 Citigroup 77 29 106 8.8 JPMorgan Chase 77 29 106 8.8 Keybank 68 29 97 8.1 Credit Suisse 61 17 78 6.5 Barclays 53 17 70 5.8 Wells Fargo 53 17 70 5.8 UBS Warburg 53 17 70 5.8 Union Bank 39 29 68 5.7 Mizuho 28 21 49 4.1 Continued

APS PNW Total % of Total Sun Trust $ 36 $ - $ 36 3.0 Wachovia 36 - 36 3.0 US Bank 17 13 30 2.5 KBC Bank 24 - 24 2.0 Dresdner 24 - 24 2.0 Bank of Tokyo - Mitsubishi 11 9 20 1.7 Northern Trust 11 9 20 1.7 Chang Hwa 15 - 15 1.3 Bank Hapoalim 10 - 10 0.8 Sub-Total 866 283 1,149 95.8 Lehman Brothers 34 17 51 4.2 Total $ 900 $ 300 $1,200 100.0 Solid Revolver Bank Groups - Continued ($ Millions)

Debt and Cash Balances September 30, 2008 APS* Parent SunCor Total Long-term debt including current maturities $ 2,851 $ 175 $ 177 $ 3,203 Short-term debt 270 167 5 442 Total debt $ 3,121 $ 342 $ 182 $ 3,645 Cash and investments $ 76 $ 19 $ 10 $ 105 * Excluding sale leaseback obligation bonds (approximately $188 million) $ Millions

Auction Rate - Ambac 343 Variable Rate - LOC 196 Fixed rate 90 Variable Rate - Unenhanced 27 Tax-Exempt Debt Profile September 30, 2008 $656 Million

Manageable Long-Term Debt Maturity Profile 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 SunCor 126 46 2 2 2 PNW 175 APS 400 379 301.3 488 250 $ Millions APS PNW SunCor

O&M Cost Management Initiatives Control costs to manage increases and related risks

Pension Update 2006 2007 Projected 2008 Required cash contributions 33 22 2 Optional cash contributions 14 30 33 Income statement expense 31 28 25 2006 2007 2008 Projected $ Millions Prudent funding of pension obligation 94% cash funded at 2007 plan year-end Annual actuarial valuations based on year-end status

Long-Term Focus on Improving APS Credit Metrics '04 '05 '06 '07 '08 0.162 0.164 0.183 0.186 0.202 Funds From Operations / Debt '04 '05 '06 '07 '08 0.58 0.493 0.499 0.503 0.504 Adjusted Debt / Total Capitalization* Based on 2008 earnings guidance * Adjusted for Palo Verde Unit 2 sale leaseback Projected Projected

APS Net Cash Flow as Percent of Capital Expenditures 2004 2005 2006 2007 2008 0.452 0.369 0.81 0.662 0.75 Projected Based on 2008 earnings guidance

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Value Proposition Integrated, regulated electric utility Attractive long-term economic fundamentals Operational excellence Experienced management and workforce Focus on regulatory improvements Financial performance focus Valuation $2.10 per share annual dividend Investment-grade credit quality Opportunities for valuation expansion