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):  March 18, 2014

Commission File Number	 	Exact Name of Registrant as Specified in
Charter; State of Incorporation;
Address and Telephone Number	 	IRS Employer
Identification Number	
 	 	 	 	 	
1-8962	 	Pinnacle West Capital Corporation
(an Arizona corporation)
400 North Fifth Street, P.O. Box 53999
Phoenix, AZ 85072-3999
(602) 250-1000	 	86-0512431	
 	 	 	 	 	
1-4473	 	Arizona Public Service Company
(an Arizona corporation)
400 North Fifth Street, P.O. Box 53999
Phoenix, AZ 85072-3999
(602) 250-1000	 	86-0011170	
 
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 (17 CFR 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 or furnished by Pinnacle West Capital Corporation and Arizona Public Service Company.  Each registrant is filing or furnishing 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 or furnishing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

 

 
Item 7.01              Regulation FD Disclosure.
 
Investor and Analyst Meetings
 
Pinnacle West Capital Corporation (“Pinnacle West”) will be participating in various meetings with securities analysts and investors in late March and early April 2014 and will be utilizing handouts during those meetings.  Copies of the handouts are attached hereto as Exhibit 99.1.
 
Item 9.01              Financial Statements and Exhibits.
 
(d)           Exhibits

Exhibit
No.	 	Registrant(s)	 	Description	
 	 	 	 	 	
99.1	 	Pinnacle West
Arizona Public
Service Company	 	Pinnacle West handouts for use at meetings in late March and early April 2014.	
 
2 

 
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:  March 18, 2014	By:	/s/ James R. Hatfield	
 	James R. Hatfield	
 	Executive Vice President and Chief Financial Officer	

 	ARIZONA PUBLIC SERVICE COMPANY	
 	(Registrant)	

Dated:  March 18, 2014	By:	/s/ James R. Hatfield	
 	James R. Hatfield	
 	Executive Vice President and Chief Financial Officer	
 
3 

Exhibit 99.1

	DELIVERING SUPERIOR SHAREHOLDER VALUE Investor Meetings | March – April 2014	

	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 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; technological developments affecting the electric industry; 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, 2013, 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.	

	VALUE PROPOSITION • Maintaining focus on core electric utility business Experienced Management • Delivering long-term value Team Driving Focused • Creating a sustainable energy future for Arizona and the communities we serve Strategy • Driving cost management discipline through increased transparency and accountability • Arizona’s long-term growth fundamentals remain largely intact; supportive of Leverage to Arizona more traditional growth patterns 2-3x the national average Economic Recovery • Housing market is gaining momentum, providing more support to new construction • Customer Satisfaction: Top decile in J.D. Power Survey Executing on Operational • Reliability: Customer outage time continues to trend in top quartile Excellence • Safety: 2013 was safest year on record, sixth straight year of improvement • Palo Verde continues record levels of electricity production • Consolidated earned ROE of at least 9.5% (9.9% in 2012 and 2013) Delivering on Achievable • Rate base growing at 6-7% through 2018 Long-Term Targets • Manageable dividend growth of 4% • Strong investment-grade credit ratings	

	PINNACLE WEST: WHO WE ARE We are a vertically integrated, regulated electric utility in the growing southwest U.S. NYSE Ticker PNW Market Cap* ~$6 Billion Enterprise Value* ~$9 Billion Dividend Yield* 4.1% Consolidated Assets Over $13 Billion Principal Subsidiary Arizona’s largest and longest-serving electric utility Regulated utility provides stable, regulated earnings and cash flow base for Pinnacle West Service Territory 1.2 million customer accounts (89% residential) 34,646 square miles Peak Demand – 6,927 MW (July 8, 2013) Nearly 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 United States 2013 Retail Sales: 28,088 GWh Operating Revenues: $3.2 Billion Residential 47% 52% Commercial 44% 42% Industrial 8% 6% Other < 1% < 1% * As of February 28, 2014	

	ARIZONA ECONOMIC INDICATORS Nonresidential Building Vacancy – Metro Phoenix New Home Sales & Single Family Permits Home Prices – Metro Phoenix Value Relative to Jan ‘05 Vacancy Rate Office Retail Job Growth (Total Nonfarm) - Arizona YoY Change	

	CUSTOMER GROWTH Annual Growth Customer growth drives 85% of retail sales (excluding impacts of customer conservation, energy efficiency and distributed renewable generation initiatives) Retail customer growth to average about 2.5% annually 2014-2016	

	RETAIL SALES GROWTH (WEATHER-NORMALIZED) YoY Retail Sales Before Customer Programs Energy Efficiency & Customer Conservation Distributed Energy Weather-normalized retail sales growth about 1% for 2014-2016 after impacts of energy efficiency, customer conservation and distributed renewable generation initiatives (excluding Lost Fixed Cost Recovery)	

	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 by 2013 Energy Efficiency Requirements Renewable Energy (RES) Requirements APS on track to approximately double 2015 requirement APS on track to meet target	

	OPERATIONAL EXCELLENCE Palo Verde Palo Verde has exceeded 30 million megawatt-hours annual production 9 times – the only U.S. plant to ever do so. Safety 2013 lowest number of recordable injuries in company history. Customer Satisfaction Ranked 5th highest nationally among 54 large investor-owned electric utilities in 2013 J.D. Power residential customer survey. Lowering Outage Time Per Customer Top quartile in industry over past several years. Average Outage Minutes/Year Million Megawatt Hours Rating Industry Average APS 2013	

	PNW Consolidated At least 9.5% Annually EARNED ROE Delivering consistent earned return on equity is one of our top priorities Earned ROE * Continuing operations Adjustment mechanisms (Lost Fixed Cost Recovery, Transmission Cost Adjustor, etc.) providing increasing contribution Modest load growth Continued focus on sustainable cost management Key Drivers During Rate Case Stay-Out Goal	

	RATE BASE APS’s revenues come from a regulated retail rate base and meaningful transmission business $6.9 Billion Total Approved Rate Base 6-7% Compound Annual Growth Rate Projected Most Recent Rate Decisions ACC FERC Rate Effective Date 7/1/2012 6/1/2013 Test Year Ended 12/31/2010* 12/31/2012 Rate Base $5.7B $1.2B Equity Layer 54% 57% Allowed ROE 10.00% 10.75% *Adjusted to include post test-year plant in service through 3/31/2012 Rate base $ in billions, rounded	

	DIVIDEND GROWTH Pinnacle West’s annual dividend is $2.27 per share; targeting ~4% annual dividend growth Projected Annual Dividend Growth Approx. 4% Yield as of February 28, 2014 Payout 12 Months Ended December 31, 2013 Dividend Yield Dividend Payout PNW Industry Averages Future dividends subject to declaration at Board of Director’s discretion	

	CAPITAL EXPENDITURES 80% of capital expenditures are recovered through rate adjustors (40%) and depreciation cash flow (40%) ($ Millions) $986* $965 $1,026 Other Distribution Transmission Renewable Generation Environmental Traditional Generation Projected $1,263 * 2013 shown on accrual basis. Capital expenditures amounts shown on cash flow statement in 2013 10-K are represented on cash basis and do not include Contributions in Aid of Construction of $41 million offset by $11 million adjustment related to the purchase of Southern California Edison’s share of Four Corners Units 4 and 5, which are shown on separate lines of the cash flow statement. 2014-2016 as disclosed in 2013 Form 10-K.	

	RESOURCE PLANNING* Existing Owned Resources Includes retirement of Four Corners 1-3 Existing Contracts Four Corners 4-5 Resource Planning Requirement Load Requirement Including Reserves MW Gas Coal Nuclear RE + DE EE Composition of Energy Mix by Resource Note: RE = Renewable Energy; DE = Distributed Energy; EE = Energy Efficiency *Data shown is based on 2012 Resource Plan. Updated Resource Plan to be filed April 1, 2014.	

	OCOTILLO POWER PLANT (TEMPE, AZ) Ocotillo modernization project will maintain valley grid reliability and increase APS’s generating capacity by 290 MW 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 Expected timeline: Early 2014: Stakeholder engagement and initiate permitting activities Q3 2014: ACC Certificate of Environmental Compatibility application filing Late 2014: ACC Siting Committee hearings 2016: Expect to begin construction Q2 2018: Expected project completion 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 (5) GE 102 MW combustion turbines 0 510 Total 330 620 Net site capacity increased by 290 MW	

	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 Estimated environmental compliance: $350 million, primarily in 2016-2017 APS will continue to operate Four Corners and now has total interest of about 970 MW APS filed Four Corner-specific revenue requirement on 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 SCR control technology on Units 4-5 by July 31, 2018 Construction expected to begin by late 2015 after approval of final EPA permit Next Steps: ACC decision on revenue requirement (rates in effect immediately following decision) EPA permitting process FOUR CORNERS POWER PLANT Procedural Schedule - Staff Proposal Staff/Intervenor Direct Testimony June 19, 2014 APS Rebuttal Testimony July 3, 2014 Staff/Intervenor Surrebuttal Testimony July 21, 2014 APS Rejoiner Testimony July 28, 2014 Prehearing Conference July 30, 2014 Hearing Begins August 4, 2014 Post-Hearing Briefs August 22, 2014 Reply Briefs September 5, 2014 ACC Open Meeting November 5 & 6, 2014	

	10-Year Transmission Plan filed January 2014 (115 kV and above) $496 million of transmission investment 275 miles of new lines Includes Hassayampa-North Gila (HANG2) ~110 miles; 500 kV Construction started March 2013 Estimated in-service mid 2015 Projects to deliver renewable energy approved by ACC Transmission investment diversifies regulatory risk Constructive regulatory treatment FERC formula rates and retail adjustor TRANSMISSION Strategic transmission investment is essential to maintain reliability and deliver diversified resources to customers Legend Planned lines Existing lines Proposed Delaney-Colorado River line Solar potential area Wind potential area	

	Utility-scale photovoltaic solar plants to be owned by APS Constructive rate recovery through RES until included in base rates 118 MW in commercial operation to date; 150 MW by end of 2014 Commitments to date: – 170 MW; $695 million estimated capital investment AZ SUN PROGRAM Owning solar resources makes sense for our customers, the environment and provides earnings and cash flow growth Name Location Capacity Developer Actual or Target COD* Paloma Gila Bend, AZ 17 MW First Solar September 2011 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 March 2013 Yuma Foothills Phase 2 Yuma, AZ 18 MW AMEC November 2013 Hyder II Hyder, AZ 14 MW McCarthy November 2013 Gila Bend Gila Bend, AZ 32 MW Black & Veatch 2Q 2014 City of Phoenix Buckeye, AZ 10 MW TBD 2015 Luke Air Force Base Glendale, AZ 10 MW TBD 2015 Total 170 MW As of December 31, 2013 * In-Service or Commercial Operation Date	

	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	

	OPERATIONS & MAINTENANCE Our goal is to keep consolidated O&M growth at or below retail sales growth levels Note: Pinnacle West O&M for 2009-2014E: $10M, $9M, $8M, $11M, $27M and $10M, respectively. * 2013 includes $9M related to the closure of Four Corners Units 1, 2 and 3 deferred for regulatory recovery in depreciation. **Renewable energy and demand side management expenses are offset by revenue adjustors. $790 - $810 ($ Millions) $788*	

	Motivation for Change SUSTAINABLE COST MANAGEMENT INITIATIVE (“SCMI”) Capitalize on changes driven by aging workforce Improve organizational efficiencies Strengthen governance and clarify accountability Refine understanding of cost structure to better identify opportunities Manage costs during regulatory stay-out Sustainable Changes Tiered Metrics Linked to incentives to drive accountability across all levels Business Planning To increase transparency and drive consistent, annual process across organization Corporate Resource Operating Model Align corporate support services with business needs to identify overlaps and gaps; centralize financial analysis and information technology Target Bottom of top-quartile staffing and costs by 2014 (IT by 2015) Enterprise Process Improvement A standardized, systematic approach to understanding our work and determining how we can do it better	

	Pension funded status for GAAP purposes increased to 90% at year-end 2013 due to earned returns, higher discount rates, plan contributions in excess of minimum required contributions and a liability driven investment strategy Improved funded status has lowered pension & OPEB expense for 2014 relative to 2013 and should allow pension contributions to be reduced post-2014 PENSION & OTHER POST RETIREMENT BENEFITS (“OPEB”) Expense(3) 2013A 2014E 2015E Pension(1) $31 ~$10 ~$10 OPEB $18 ~$10 ~$10 Contributions 2013A 2014E 2015E 2016E Pension $141 $175 Up to $100 Up to $25 OPEB $14 $10 $10 $10 Assumptions For 2013 For 2014 Discount Rate: Pension 4.01% 4.88% Expected Long-Term Return on Plan Assets: Pension 7.00% 6.90% (1) Excludes supplemental excess benefit retirement plan. (2) Funded status as defined by ERISA was 107% as of January 1, 2013 and is estimated to be 103% funded as of January 1, 2014. (3) Excludes approximately 50% of total estimated expense which is attributable to amounts capitalized or billed to electric plant participants. Data as of December 31, 2013 ($ in millions)	

	2014 KEY DATES Docket # Q1 Q2 Q3 Q4 Key Regulatory Filings Lost Fixed Cost Recovery 11-0224 Jan 15 Transmission Cost Adjustor May 15 Renewable Energy Surcharge Jul 1 10-Year Transmission Plan (Annual) 13-0002 Jan 31 2014 Integrated Resource Plan (Biennial) TBD Apr 1 Net Metering (Decision No. 74202) 13-0248 Quarterly Installation Filings 13-0248 Apr 15 Jul 15 Sep 15 Value and Cost of Distributed Generation 14-0023 ---- Workshops to be scheduled ---- Innovations and Technology Development Docket Workshops – Substantive (a), Response (b) 13-0375 Mar 20 (1a) Apr 25 (1b) May 28 (2a) Jun TBD (2b) Jul 28 (3a) Aug 18 (3b) Four Corners Rate Rider – (Staff Proposed schedule – full schedule on Slide 16) 11-0224 June through Sept: Testimony and hearings Nov 5-6: ACC Open Meeting Energy Efficiency workshops – (a) Cost effectiveness, (b) Cost recovery and (c) EE standards/rulemaking 13-0214 Mar 18 (a) Mar 31 (b) Apr 17 (c) ACC Open Meetings - ACC Open Meetings Held Monthly Elections - May 28: Nominations Aug 26: Primary Nov 4: General Arizona State Legislature - In Session Jan 13 – End of Q2 Annual Shareholder Meeting - May 21	

	APPENDIX	

	2014 – 2016 FINANCIAL OUTLOOK Key Factors & Assumptions as of February 21, 2014 Assumption Impact Retail customer growth Expected to average about 2.5% annually (2014-2016) Modestly improving Arizona and U.S. economic conditions Weather-normalized retail electricity sales volume growth About 1% after customer conservation and energy efficiency and distributed renewable generation initiatives Weather Normal weather patterns 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 Pending final ACC approval 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	

	ARIZONA CORPORATION COMMISSION Three seats of four-year terms through January 2017 were addressed in the November 2012 election Bob Stump (R)* Chairman Brenda Burns (R) Gary Pierce (R)* Terms To January 2015 Terms To January 2017 Susan Bitter Smith (R) Bob Burns (R) Incumbents New Commissioners * Term limited	

	Mechanism Adopted / Last Adjusted Description Power Supply Adjustor (“PSA”) April 2005 / February 2014 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 2014 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 2014 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 rebates and other incentives to participating customers Environmental Improvement Surcharge (“EIS”) July 2007 / April 2013 Allows recovery of certain carrying costs for government-mandated environmental capital projects Capped at $5 million annually Transmission Cost Adjustor (“TCA”) April 2005 / June 2013 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 2013 Recovers transmission costs based on historical costs per FERC Form 1 and certain projected data Lost Fixed Cost Recovery (“LFCR”) July 2012 / March 2014 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	

	FERC Formula Rates adopted in 2008 Adjusted annually with 10.75% allowed ROE Based on FERC Form 1 and certain projections Retail portion flows through ACC Transmission Cost Adjustor REGULATORY MECHANISMS (TCA) We have achieved constructive transmission rate treatment with annual adjustments Annual Revenue Rate Effective Date Retail Portion (TCA) $21 M 6/1/2013 Wholesale Portion $5 M 6/1/2013 Total Increase (Decrease) $26 M Equity Ratio 57% Rate Base (Year-End) $1.2 B Test Year 2012 Annual Revenue Rate Effective Date $18 M 8/1/2012 $(2) M 6/1/2012 $16 M 55% $1.2 B 2011 Annual Revenue Rate Effective Date $38 M 7/1/2011 $6 M 6/1/2011 $44 M 54% $1.2 B 2010	

	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 March 1st, based on the EE and DG savings from the preceding calendar year Subject to annual 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 2013 ACC Order 2014 Rate Filing Rates Effective March 1, 2013 March 1, 2014 LFCR Rate 0.2% 0.95% Residential rate per lost kWh $0.031 $0.031 Non-residential rate per lost kWh $0.023 $0.023 LFCR Adjustment (Annualized) $5.1 Million $25.4 Million LFCR Revenue (Accrued in prior year) $7.3 Million (1) $22.6 Million (1) Represents six months in 2012.	

	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 Stable Stable S&P Stable Stable Fitch Stable Stable 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	

	FINANCING ($Millions) Debt Maturity Schedule 2014 Major Financing Activities $250 million 30-year 4.70% APS senior unsecured notes issued in January 2014 Currently expect about $550 million additional long-term debt issuance in 2014, including issuance to refinance $300 million of maturing debt In addition, there will be several tax-exempt series subject to remarketing 2015 Major Financing Activities Currently expect about $300 million of new long-term debt in 2015, in addition to refinancing maturing debt	

	Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for our commercial paper programs Pinnacle West and APS currently have ample borrowing capacity under our respective credit facilities, and may readily access these facilities ensuring adequate liquidity CREDIT FACILITIES AND LIQUIDITY (1) APS issued $250 million of long-term debt in January 2014; proceeds were used to repay commercial paper which was used to fund the purchase price and costs associated with the acquisition of SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners. Borrower Capacity $ Millions Maturities APS $ 500 Nov. 2016 APS 500 Apr. 2018 PNW 200 Nov. 2016 Credit Facilities 1,200 Cash 10 Short-Term Borrowings (1) (153) Total Liquidity $1,057 As of December 31, 2013	

	Germany and Japan are among countries with highest installed solar capacity, yet have solar conditions far inferior to Arizona Arizona ranks 1st in the U.S. for solar energy development* RENEWABLE ENERGY RISES WITH THE SUN We are helping Arizona become the “Solar Capital of America” Arizona * Environment America Research & Policy	

	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 137 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 Various Multiple AZ Facilities - As Available 1996-2006 100 4 Total Generation Capacity 6,394 MW 1 Includes leased generation plants.	

	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 WHOLESALE 90 MW Wholesale Contract Not Disclosed Not Disclosed IO Mar-2009 2010 5 90 Total Contracted Capacity 3,008 MW 1 UD = Under Development; UC = Under Construction; IO = In Operation